Analysts weigh in on lumpy production, rig counts, waiting on completions and the decline curve.

Lumpy Bakken oil-production figures of late shouldn’t be alarming, explain analysts with Tudor, Pickering, Holt & Co. Securities Inc.

North Dakota state figures have shown production growth trending sideways in the last months of 2012 and into January. An April 2013 estimate is that daily production jumped some 40,000 barrels in February to 778,971 barrels a day, a new all-time high.

However, the TPH team notes, the sideways production figures were “despite a lack of the variables that are typically rumored to cause production hiccups—no infrastructure issues, relatively dry weather in fourth-quarter 2012 and the rig count actually dropping so no rig shortage.

“Supply bulls have held that Bakken production growth has been temporarily stunted by a change to (multi-well) pad drilling and that production will ultimately accelerate from current levels as (frac) crews work through the (well-) completion backlog.”

The TPH team expects total, daily Bakken production will grow by 150,000 barrels this year. “We see four key factors determining growth: number of rigs drilling, rig efficiencies, EURs (estimated ultimate recovery) per well and underlying production declines. Infrastructure is a limiting reagent that we don’t see playing a role in halting growth going forward.”

1. As for rig count, the state reports 186 rigs were working on new wells in March, down from 218 in May 2012 and up from 81 in January 2010.

2. Rig efficiency—i.e., the pace at which drilling each well is being achieved—in the play has grown some 10% to 15% annually, according to TPH estimates.

3. “Meanwhile, on the E&P side, we’ve seen EURs stay relatively constant,” the team reports. “The net impact is that apparent rig efficiencies in the play are less than other horizontal plays because well type has changed”—i.e., the Bakken uses longer laterals, thus more total footage to drill.

4. As for production decline, this has grown. “Of the 700,000 barrels per day producing at year-end 2012, roughly 50% comes from wells drilled during 2012, meaning that producers have to replace 244,000 barrels a day, assuming 40% first-year declines and 25% vintage 2010-12 declines, with that number increasing each year as base production increases.

“So factor No. 1 has declined, No. 2 is improving, No. 3 is declining and No. 4 is creating a bigger headwind to growth with each year.”

More data inbound

Other securities-research teams estimate Bakken production will grow to 1.5 million barrels per day. The TPH team reports, “We think that the recent, seasonal plateau highlights that figures like that would take a meaningfully higher rig count than present to be achieved.”

It concludes that more will be clear as Bakken producers complete their first-quarter earnings calls in the coming week, “which should provide a more current update than the two-month-lagged, government, production data.”

Among the key calls are those of

–NOG (Northern Oil & Gas Inc.), “a good proxy for (Williston) basin growth as it holds working interests across wide swaths of Bakken acreage,” and

–WLL (Whiting Petroleum Corp.), CLR (Continental Resources Inc.) and HES (Hess Corp.), which are making 30% of gross Bakken-play production, combined.

New-well decline

As for Bakken production decline, Bob Brackett, senior analyst for securities-research firm Bernstein Research, estimates Bakken-play well output was falling some 30% in their first year in 2011-12. Thus, January 2012 production of some 545,000 barrels a day in North Dakota would include 312,000 barrels from wells that came online in the prior 12 months.

He also expects new-well productivity to decline as more are landed outside the highly drilled sweetest spots. And, he believes that some of the recent Bakken-play production growth has been due to a drawdown of the well-completion backlog as frac spreads are more available in the past year as they have been leaving the smallest-margin U.S. shale-gas plays.

“While 2012 U.S. crude production admittedly surprised slightly to the upside, we believe investors are increasingly baking in linear—i.e. constant, absolute growth—or even accelerating production increases into U.S. oil projections through approximately 2016,” Brackett concludes.

“For sure, growth will continue at a healthy clip, but accelerating production-growth forecasts in areas like the Bakken don’t make sense to us.”

Waiting on completion

Lynn Helms, director of the North Dakota Industrial Commission’s Department of Mineral Resources, reports that the number of Bakken-play wells waiting on completion (WOC) services has actually been growing in the past few months, however. In February 2012, he reported some 300 wells were WOC. That fell to roughly 250 the following month and roughly 240 the next. However, he estimated 347 WOC in August, 410 this past January and 375 in April.

As for production, Helms reported in April that January 2013 oil production from North Dakota was 737,787 barrels a day, up from 235,925 barrels a day in January 2010. He forecasts February 2013 production was 778,971 barrels a day, a new historical high.

Meanwhile, the state’s oil producers continue to connect associated-gas production from Bakken-play wells into pipe and onto sales. In January, captured-gas production was 791 million cubic feet a day, up from 255 million a day in January 2010, and Helms estimates February gas capture was 850 million a day, a new state historical high.

He adds that there are now an estimated 8,500 oil- and gas-producing wells in North Dakota, up from some 4,600 in January 2010, and 186 rigs were working on new wells in March, down from an all-time high of 218 in May 2012. “Over 95% of drilling still targets the Bakken and Three Forks formations,” he notes.

Still to be produced

An updated U.S. Geological Survey assessment of additional Bakken oil—that is, “undiscovered, technically recoverable”—that may be produced from the Williston Basin, plus now including an assessment of additional oil that may be produced from the underlying Three Forks formations, to be 7.4 billion barrels—roughly half from the Bakken and half from the Three Forks.

There is a 95% chance 4.42 billion will be produced and a 5% chance as much as 11.43 billion may be produced, the USGS adds. The 7.4-billion-barrel estimate is roughly twice that of a 2008 assessment of the Bakken only; the difference is entirely from adding estimates for Three Forks potential.

“Since the 2008 USGS assessment, more than 4,000 wells have been drilled in the Williston Basin, providing updated subsurface geologic data,” the USGS reported when releasing the highly anticipated 2013 assessment Tuesday.

“Previously, very little data existed on the Three Forks Formation and it was generally thought to be unproductive. However, new drilling resulted in a new understanding of the reservoir and its resource potential.”

The Bakken and Three Forks formations may also contain 6.7 trillion cubic feet of recoverable gas—ranging from a low estimate of 3.4 Tcf and a high of 11.3 Tcf—and a half-billion barrels of recoverable natural gas liquids (NGLs).

Editor’s note: Click for a map of the USGS’ 2013 Bakken and Three Forks assessment areas.

-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.

]]> http://blogs.oilandgasinvestor.com/blog/2013/05/02/what-gives-in-the-bakken%e2%80%94besides-a-growing-amount-of-oil/feed/ http://blogs.oilandgasinvestor.com/blog/2013/04/30/why-obama-wants-to-end-the-us-oil-and-gas-industry/ http://blogs.oilandgasinvestor.com/blog/2013/04/30/why-obama-wants-to-end-the-us-oil-and-gas-industry/#comments Tue, 30 Apr 2013 20:01:48 +0000 Nissa Darbonne http://blogs.oilandgasinvestor.com/?p=2087

The No. 1 U.S. growth industry in this century is just “oh so 20th century.”

President Obama’s proposed changes to tax law are rich with irony. An initial section lists tax incentives to encourage manufacturing, research, clean energy, bringing jobs back to America and creating new jobs. Listed later are tax-law repeals to discourage American oil and gas production—thus, discouraging manufacturing, research, clean energy, bringing jobs home and creating new jobs.

Ultimately, according to the Treasury Department report, Obama wishes to end the American oil and gas industry because it is, well, just oh-so-20th-century. And, as current tax law encourages drilling for U.S. oil and gas, then this must be stopped.

“The President agreed at the G-20 Summit in Pittsburgh to phase out subsidies for fossil fuels so

that the United States can transition to a 21st-century energy economy,” the Treasury Department reports in “General Explanations of the Administration’s Fiscal Year 2014 Revenue Proposals.” Concerning the repeal of tax credits for trying to make an old oil well continue to make oil (the enhanced-oil-recovery or EOR tax credit), the department reports, “the credit, like other oil and gas preferences the Administration proposes to repeal, distorts markets by encouraging more investment in the oil and gas industry than would occur under a neutral system.

“This market distortion is detrimental to long-term energy security and is also inconsistent with the Administration’s policy of supporting a clean-energy economy, reducing our reliance on oil and cutting carbon pollution. Moreover, the credit must ultimately be financed with taxes that result in other distortions, e.g., in reductions in investment in other, potentially more productive, areas of the economy.”

It is ironic in that, in his 2014 tax-related proposals, most of the business activity Obama wishes to encourage with incentives are ones in which the American oil and gas industry has been vigorously engaged in the past decade, particularly as a result of new, horizontal drilling and fracture-stimulation completions in ever-tighter rock:

–Bringing jobs back to the U.S. and basing new jobs in the U.S.

–New manufacturing in communities affected by economic disruption.

–Research and experimentation.

–Hiring veterans.

–Production of enhanced-technology vehicles.

–Alternative-fuel vehicles.

Activities he wishes to discourage—via repealing existing credits—have been critical to advancement of U.S. oil and gas production:

–The EOR credit for enhanced efforts to recover further oil and gas from existing fields and wells.

–New drilling for oil and gas resources (intangible drilling credits or IDCs).

–Spending on studying America’s subsurface via development of geological and geophysical data.

In short, Obama believes that encouraging American oil and gas production begets yet more American oil and gas production. And, it does. Incongruous is why this is a bad thing. Meanwhile, subsidies for solar and biomass fuels, laws and regulations requiring poor-energy-quality ethanol use, and other non-fossil-fuel incentives don’t make the marketplace neutral.

Instead, the marketplace is working just fine—and largely due to growing American oil and gas production. Obama and Treasury could consult the Labor Department and Department of Energy for facts:

–New U.S. natural gas production and its use in electricity generation, transportation and other formats have resulted in the past several years in a reduction of U.S. greenhouse-gas (GHG) emissions by more than the Kyoto Protocol would have required, if the U.S. had participated in it. (EIA)

–In March, North Dakota—the home of the giant new Bakken oil play—had the lowest unemployment rate in the U.S., 3.3%. (Labor Department, March 2013). In a Labor Department study of 17 counties in North Dakota and Montana that consist of the Bakken oil play, jobs grew to 105,891 in 2011 from 77,937 in 2007. Total wages grew to $5.4 billion from $2.6 billion. Average annual pay grew to $50,553 from $33,040.

–U.S. oil production had fallen to an average of 5.0 million barrels a day in 2008, despite oil prices peaking at some $148 a barrel that summer. Meanwhile, production this past March was an estimated 7.16 million barrels a day. (EIA, April 2013)

–Imports from OPEC members were 3.85 million barrels a day in January, down from a peak of 5.98 million a day in 2007. (EIA, April 2013)

–Imports from non-OPEC members peaked in 2006 at 8.19 million a day. In January, these imports were 6.12 million (EIA, April 2013)

–Energy imports of all types, including coal, have declined from a peak of 34.7 quadrillion Btu in 2005 to 26.6 quadrillion in 2012. (EIA, April 2013)

–Natural gas use in power generation, replacing coal, thus less carbon emission, grew to 9.137 trillion cubic feet (Tcf) in 2012 from between 6 and 7 Tcf a year in the prior six years. (EIA, April 2013)

–Natural gas use as a vehicle fuel was an estimated 33 Bcf in 2012, up from 29 Bcf in 2010. (EIA, April 2013) Natural gas use in transportation overall was 763 trillion Btu in 2012, up from some 602 quadrillion in 2004. (EIA, April 2013)

–Petroleum use in transportation was 24.7 quadrillion Btu in 2012, down from a peak of 27.8 in 2007. (EIA, April 2013)

New American oil and gas production is clearly brilliant for the American energy consumer, trade deficit, employment rate and national security. Yet, for Obama, it is a nuisance.

-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.

]]> http://blogs.oilandgasinvestor.com/blog/2013/04/30/why-obama-wants-to-end-the-us-oil-and-gas-industry/feed/ http://blogs.oilandgasinvestor.com/blog/2013/03/20/oil-rail-steel/ http://blogs.oilandgasinvestor.com/blog/2013/03/20/oil-rail-steel/#comments Wed, 20 Mar 2013 18:28:03 +0000 Nissa Darbonne http://blogs.oilandgasinvestor.com/?p=2082

A renewed American industrial economy is a reminder of the economic security free markets provide.

To hear Rodney Cohen’s story reminds one of the opening chapters of Atlas Shrugged, when innovation has the potential to further catapult America in its greatness. At the time of the writing, 1957, the scientific premise of the work was farfetched but upon which Rand played out a clash of communism and capitalism, a strange business anti-Darwinism—survival of the least fit.

In the more than 50 years since it was published, one premise has, in fact, become reality: production of oil from shale. Of course, the Ellis Wyatt character’s breakthrough may have been of oil from true shale—oil that has to be produced with mining or thermal assistance—unlike that from the Bakken, for example, which is from rock that sits between shale barriers.

However, the need to get all of this new oil to market brings the railroad into play and exactly what has developed from the more than 700,000 barrels of new Bakken oil that is now being made a day from North Dakota and Montana.

And, that brings steel into play, like the Hank Rearden character’s Rearden Steel. Factories across America are fast at work today, building thousands of new railcars for transporting Bakken and other new North American oil to refineries that were to be shuttered if not for this new, lower-priced feedstock. BNSF expects to be railing some 700,000 barrels a day of American oil to refiners by year-end. That’s up from some 150,000 barrels a day at year-end 2011.

Meanwhile, steel-making itself has become more economic as well by newly abundant, low-priced U.S. natural gas—produced from shale.

But, who is Rodney Cohen? A few years ago, Cohen had three heads—at least, that’s how some folks looked at him when he put forth an idea of investigating whether low-priced Bakken oil feedstock, the existing rail system and low-priced natural gas could make profitable a refinery in Philadelphia that was destined for closing.

Curious, indeed.

The managing director of The Carlyle Group’s U.S. Equity Opportunities and his colleagues continued to gather information. “We were trying to understand what the real potential was,” Cohen told attendees at Hart Energy’s Marcellus-Utica Midstream conference in January. “At that point, (production) numbers were being thrown around in the Bakken that were all over the place. It was very hard to understand what the real potential was.”

Eventually, the potential and the reliability of supply became apparent. Last summer, Carlyle closed the acquisition of the Philadelphia plant, just a month shy of Sunoco Inc.’s planned shuttering of the 330,000-barrel-a-day refinery, which produces some 26% of the region’s fuel.

Meanwhile, Bud Brigham, who sold his Bakken-producing Brigham Exploration Co. in 2011 to Statoil ASA for $4.7 billion, says the new U.S. industrial revolution reminds him often of Rand’s story. An advocate of reading Rand’s work, Brigham is co-executive producer of Atlas Shrugged II: The Strike, which premiered in Washington this past fall.

“She wrote about what’s happening today over 50 years ago,” Brigham says. “Amazingly, she even wrote about Ellis Wyatt, an oil man who was rejuvenating the Rockies because he figured out how to get oil out of shale…That stimulated the rail business…, and steel…in an otherwise struggling economy. The parallels are remarkable.

“Clearly, this is huge for the country today, particularly the lower cost structures, improved trade balance and less dependency on foreign energy supplies.”

Dan Pickering, a multi-decade energy analyst and chief investment officer for TPH Asset Management, agrees that the revolution is the real deal. “Shale is translating to lower commodity prices, which is creating an input-cost advantage for U.S. manufacturing. Users are getting more comfortable with supply availability, which is going to translate to more demand.

“I am optimistic on the renaissance. That doesn’t mean it is great for stocks at all points, but it is good for consumers, industrials and the American populace.”

Brigham hopes the rest of the novel doesn’t play out, though—government controls that result in a new Dark Age, “a brief flare of hope that will be snuffed out by collectivism…Though it’s not pleasant to think about, that is my biggest concern.”

Government and labor did well by the Philadelphia project, from the mayor, governor and members of Congress to concessions by trade unions, however. Cohen says, “We were in a moment of time when the U.S. government realized we may be left with no refiners in this PADD 1 area or maybe very few. And, what is the implication of that? I think that was a little scary to everyone.”

He concludes, “It’s incredibly exciting times…, when new ideas are developing every day…, game-changing ideas….”

Editor’s Note: Dr. Tara Smith, professor of philosophy at the University of Texas, where she currently holds the Anthem Foundation Fellowship for the Study of Objectivism, will present a lecture, “The Virtuous Egoist,” 7:30 p.m., March 25, 2013, in Houston at Rice University, Sewell Hall, Room 301. The program is free and open to the public. More details on this and more upcoming lectures are available at HoustonObjectivism.com.

-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.

]]> http://blogs.oilandgasinvestor.com/blog/2013/03/20/oil-rail-steel/feed/ http://blogs.oilandgasinvestor.com/blog/2013/03/16/an-interview-with-the-chainman-shale/ http://blogs.oilandgasinvestor.com/blog/2013/03/16/an-interview-with-the-chainman-shale/#comments Sat, 16 Mar 2013 15:39:03 +0000 Nissa Darbonne http://blogs.oilandgasinvestor.com/?p=2079

This long-known Nevada rock remains underexplored.

As Noble Energy Inc.’s exploration of the Elko Basin in northeastern Nevada has captured industry and Wall Street attention, Utah-based Phoenix Oil & Gas LLC has developed three prospects south of Elko, including for Chainman shale. Oil and Gas Investor visited with Jonathan Baker, landman for Phoenix, recently, including at NAPE in Houston in February.

Investor Oil production from Nevada has been hit or miss in the past—mostly miss?

Baker Shell (Oil Co.) was the first major active in the basin. They had to create their own topographical maps; these didn’t exist before then. They spent years in southeastern Nevada studying this and then a corporate decision was made to exit Nevada. All that data was kind of lost.

There was a Grant Canyon well in the 1980s that made 4,000 barrels a day for eight years without decline. It was a miraculous discovery. The operator tried to offset that well, but they really couldn’t find anything else. They happened to nail (the formation in that one). The volume of oil produced from that zone—there is oil more than three times the pore space available for it, so it is a dynamic reservoir. It’s coming from somewhere else and it’s tied to the Chainman shale.

In the mid-1980s, Exxon (Corp., pre-merger with Mobil) had a huge area out here. We believe they were onto it, but Valdez happened and they had to forfeit all of their land in the frontier areas. After they pulled out, it seems all the big boys quit looking out here.

Investor Tectonic shifting and other geologic events have made the subsurface in Nevada particularly complex?

Baker Yes. This makes it difficult for conventional 2-D seismic to build a view of the subsurface very well, at least using older seismic methods. Noble Energy is shooting 3-D here; it is in the Elko Basin. I spoke with them at NAPE and they seemed pleased with data from the first shoot; they’re gearing up for their second. Chainman shale isn’t the target where they are. We’ve always compared that area to the Uinta Basin in terms of setting and maturity. We wish them success.

Investor Their success would bring oilfield services to near your prospect area?

Baker Yes. It would also get people to take a second look at Nevada.

Investor From what formations have producers made wells in Nevada in the past?

Baker Most wells in Nevada have only been drilled to 2,000 to 4,000 feet and are in the volcanics. The Grant Canyon well was a 4,500-foot test in Devonian. That’s where the 4,000 barrels a day came from. It is an extremely prolific, karsted-dolomite-type section, several hundred feet thick.

There has recently been a new discovery, Tomera Ranch, up in Pine Valley in Eureka County. The operator is Andromeda Oil LLC. They’re producing from around 2,000 feet from a sand within the Chainman. They’re not really strong wells. They’re conventionally drilled and we think they’re conventionally completed too. So who knows what could happen if you put a larger frac job into this formation?

Investor How long have you had these prospects?

Baker Four or five years ago, we started putting them together. We met a group in Texas that had a good finding tool we liked. We high-graded three prospect areas in Nevada. We then met a gentleman who had looked at this too. He had done some conventional field work, attitude collection, rock samples—the old-school geology. He had high-graded the same three areas. These happen to be where Exxon’s big contract area was and Chevron had a contract area at one time as well. So we’re within the sandbox. We think we’ve high-graded where in the sandbox we want to be.

Investor Are there bail-out zones in the area?

Baker The nice thing about where we’re situated is we have a very nice, stacked potential here. We have the Chainman shale that is a geological equivalent of the Barnett stacked on top of the Pilot shale that is the geological equivalent of the Bakken out here, with very large conventional opportunities—anticlines, regional karsting in the Devonian—below that. From a big picture, you have three really good shots out here—if just drilling deeper than what’s been done in the past.

Editor’s Note: Baker can be reached at jonathan@phoenixoilandgas.com. Details of drilling in Nevada, based on state records, are available 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.

]]> http://blogs.oilandgasinvestor.com/blog/2013/03/16/an-interview-with-the-chainman-shale/feed/ http://blogs.oilandgasinvestor.com/blog/2013/01/27/yergin-burkhard-declining-us-oil-imports-won%e2%80%99t-soften-world-oil-prices-unless-opec-doesn%e2%80%99t-curtail-output/ http://blogs.oilandgasinvestor.com/blog/2013/01/27/yergin-burkhard-declining-us-oil-imports-won%e2%80%99t-soften-world-oil-prices-unless-opec-doesn%e2%80%99t-curtail-output/#comments Sun, 27 Jan 2013 16:45:07 +0000 Nissa Darbonne http://blogs.oilandgasinvestor.com/?p=2075 Saudi Arabia is already producing some 800,000 barrels a day fewer than this past spring.

Daily U.S. oil imports—estimated by world oil traders to have fallen by as much as some 1 million barrels this past year—will decline yet further in 2013, according to IHS vice chairman Dr. Dan Yergin and IHS CERA managing director Jim Burkhard. Overall, as a result of new U.S. unconventional-oil production, such as from the Bakken oil play in North Dakota and Montana, net U.S. oil imports are 42% of daily supply today, down from 60% in 2005, says Dr. Nariman Behravesh, IHS chief economist.

Meanwhile, Saudi Arabian output has grown in the midst of “the unconventional oil and gas revolution in the United States, which has pushed up U.S. oil output by 25% since 2008 and turned North Dakota into the second-largest oil-producing state in the United States. It is here where we see the first effects of the unconventional revolution on world energy markets,” Yergin and Burkhard report.

What effect will this and other world oil supply/demand developments have on the international oil scene? Yergin and Burkhard explore this in the “Oil Market Outlook: Non-OPEC’s Big Chance” section of a new report, “Energy and the New Global Industrial Landscape: A Tectonic Shift?” The report was released at the World Economic Forum 2013 annual meeting in Switzerland this past week.

“Indeed, it looks as though 2013 may see a rare occurrence for the world oil market: Supply growth from non-OPEC(-member countries) may exceed the growth in world oil demand. This has happened only four times since 1986 and two of those years were during the Great Recession of 2008–09, when oil demand fell,” Yergin and Burkhard report. “…Oil-supply growth outside of OPEC—led by tight-oil development in the United States—could meet or even exceed the total gain in world oil-demand growth.”

They expect daily supply from non-OPEC-member countries will increase by some 1.1 million barrels this year, “slightly higher than the expected increase in world oil demand.”

So what effect will this have on world oil prices? There might be no change, if OPEC members curtail their production by as much as new, non-OPEC-member production grows, thus eliminating a situation of more excess world oil supply. Yet, the specter of that much go-to, crisis-production capacity could soften the “fear premium” that continues to encourage a $100-plus Brent oil price.

“In this case, there (would be) a moderation in oil prices, but no severe and sustained decline. Spare (daily) production capacity would increase from around 2.8 million barrels in 2012 to about 4 million in 2013.”

They add that an OPEC cutback—at least by Saudi Arabia—is already obvious, with it surfacing some 9.1 million barrels a day in December, down from 9.9 million last spring.

They note too that these scenario forecasts assume meaningful growth in non-OPEC supply. “The non-OPEC-supply story is based on real potential—no­tably further large gains from the ongoing revival of North American oil production. However, non-OPEC-supply projections have a history of disappointment due to technical and weather-related difficulties and security challenges. A strong year of non-OPEC gains would buck the past decade’s trend of underperformance—but such growth is far from assured.”

This aside, Yergin and Burkhard also comment on whether the unconventional-resource revolution will sweep the world. They expect it will, but slowly. The United States differs from other countries in that it has a large number of private oil companies (“independent” oil companies), mineral rights are held—with small exception—by individuals and private companies rather than by the government, infrastructure for transporting and processing oil exists, and there is a plethora of oilfield services and equipment at the ready.

“Moreover, the development of these resources requires experience, the build-up of knowledge and trial and error. It also involves different…work practices and mindset. Governments also have to create fiscal and regulatory regimes that permit work to go ahead and avoid being overly prescriptive with evolving technologies.”

(In the oilfield, “overly prescriptive” is when the government practically regulates the color of work boot or the zipper length of coveralls.)

Unconventional resources are known in Mexico and Argentina, for example, note Yergin and Burkhard. “Our own research indicates that the resource base in China may be larger than that in the United States. However, it is in very early days, and we believe that it will take several years before significant amounts of unconventional oil and gas begin to appear in other regions.”

The report is available at “Energy and the New Global Industrial Landscape: A Tectonic Shift.”

-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.

]]> http://blogs.oilandgasinvestor.com/blog/2013/01/27/yergin-burkhard-declining-us-oil-imports-won%e2%80%99t-soften-world-oil-prices-unless-opec-doesn%e2%80%99t-curtail-output/feed/ http://blogs.oilandgasinvestor.com/blog/2013/01/27/how-the-new-tax-laws-affect-investments-in-energy-mlps/ http://blogs.oilandgasinvestor.com/blog/2013/01/27/how-the-new-tax-laws-affect-investments-in-energy-mlps/#comments Sun, 27 Jan 2013 16:29:02 +0000 Nissa Darbonne http://blogs.oilandgasinvestor.com/?p=2072 In brief, earnings from all types of capital gains and dividends or distributions are equally taxed higher.

What affect does the “fiscal-cliff relief” legislation of earlier this month have on investments in energy MLPs? Oil and Gas Investor asked the team at tax- and business-consulting firm UHY Advisors.

“With the American Taxpayer Relief Act of 2013…investors in energy MLPs will pay as much as 24% more on their ordinary income that flows through on their Schedule K-1s—43.4% versus 35%—among top-bracket taxpayers and up to 59% more in capital gains when they sell their holdings—23.8% versus 15%,” the firm reports.

The firm breaks out the ordinary-income—or income from distributions—increase this way:

–MLP ordinary income for top-bracket taxpayers with incomes of $450,000 or more (married, filing jointly) is now taxed at 39.6%.

–Taxpayers with adjusted gross incomes of more than $250,000 are now also liable for an additional 3.8% Medicare surtax on investment income.

=This brings the total tax on MLP-investment-related ordinary income for top-bracket taxpayers to 43.4%. This is 24% more than the 2012 rate of 35%.

As for the increase in capital-gains-related taxes, which kicks in only upon divestment of MLP units, the UHY Advisors team reports:

–On the sale of MLP units held for at least one year, taxpayers with $450,000 or more in modified adjusted gross income—that is, taxable income before itemized deductions and personal exemptions plus tax-exempt income—are now liable for a 20% long-term capital-gains tax, plus the new 3.8% Medicare tax.

=This brings the total tax liability on gains from the sale of long-term holdings of MLP units—or any other investment—to 23.8%. This is 58.6% more than the 2012 rate of 15%.

–As for short-term capital gains on investments, which are for those held for less than one year, these are taxed at the same rate as ordinary income, or 39.6% for top-bracket income earners.

The team adds, “Please note that, depending upon the MLP, some or all of the gain on a sale could be taxed as ordinary due to the recapture of certain deductions taken by the MLP against ordinary income.”

Net/net, while both ordinary-income and capital-gains tax rates on profits from investing in energy MLPs are higher, they’re similarly higher for profits from other types of investments, so investor appetite for units in energy MLPs should be unchanged as a result of new tax law.

More information is available from UHY Advisors.

-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.

Thane Gustafson’s newest book on the politics of Russian business focuses on how Soviet oil and gas assets were distributed in the 1990s, who won them and how their ownership has evolved in the past two decades—a culmination of Gustafson’s research, relationships and interviews beginning in the 1980s.

Of course, the fate of Russian oil upstart Mikhail Khodorkovsky is well known, particularly within international human-rights courts and councils.

Lesser known is the role of Joe Mach, a veteran Schlumberger well specialist and University of Tulsa petroleum-engineering graduate, who was hired by Khodorkovsky’s Yukos in early 1999 to turn around its declining oil fields. Mach’s is one of the many tales Gustafson shares in his new Wheel of Fortune: The Battle for Oil and Power in Russia.

Gustafson writes, “Joe Mach enjoyed playing the part of the tough, rough-spoken Tulsa petroleum engineer, complete with cowboy boots and cigar. His language was so colorful, it was said he spelled ‘oil’ as a four-letter word.” By 1999, Mach’s career had already spanned several decades.

Khodorkovsky, who was still in his 30s at the time, meanwhile, “was a chemical engineer by first training and knew nothing of wells and reservoirs…and the logic of (Mach’s) nodal analysis appealed to him immediately….”

Mach went to work, training Yukos engineers. Mach tells Gustafson, “These people had one job: to look at each well, calculate its performance gap and sort them in descending order. The well with the biggest gap went on top and we worked on that well.”

Gustafson writes, “For Joe Mach, West Siberia was an oilman’s dream. ‘Siberia is the simplest environment in the world: It’s one big beachfront,’ he would tell visitors. ‘The Ob’ River is flowing today right over where it was 130 million years ago. It’s the same place. You can see it on seismic; you can see it on the logs. The West Siberian landscape has not changed in 130 million years.’

“The result was a uniquely uniform and prolific environment for oil. ‘You can go a thousand kilometers; it’s the same g[------]ed sand. All across, it’s 18% porosity. The water saturation is very consistent. The other no-brainer is [that] the reservoir pressure is 4,500 pounds and the bubble point’s 1,800. In other words, it’s pure oil. Man, it doesn’t get any simpler than that.’”

Relatively little of the oil the rocks contained had been produced yet. “Pumps, fracs and floods: These became Mach’s mantra over the next five years. But he might as well have said ‘shibboleths, bad practice and screw-ups’ because making changes in these three basic techniques ran straight up against established ways, beliefs and rules.

“From the moment Mach arrived at Yukos, the fight was on, both inside the company and out, in Moscow and in the field.”

Russian pumps at the time were old school in terms of power. Gustafson cites the Russian newspaper Moskovsky Komsomolets’ interview with Khodorkovsky in 2002. “When Joe first arrived, our guys said, ‘We know everything better than anybody.’ But Joe says, ‘Set the pump lower!’ And they said, ‘Go [----] yourself. (Da poshel ty!)’ Because we knew that if you set the pump low in the well, it’d burn out. Joe insisted. So we lowered it, and it burned out. Another one, and it burned out too. Six pumps burned out, but Joe kept saying, ‘Lower, lower g[------] it! One out of three will burn out, but the other two will work so well that you won’t miss the third one.’”

Yet, hydraulic fracturing, which Gustafson points out was as common in West Texas oil fields as wind, was Mach’s “most controversial innovation” in the Russian oil patch. The proppant—that is, ceramic spheres used to hold rock open after being fractured—that Mach ordered for the jobs became known in the field as “Joe’s balls.”

Khodorkovsky was eventually imprisoned in 2003, just weeks after his 40th birthday, on a variety of allegations that are internationally recognized as “trick charges” as Putin’s means of depowering the successful capitalist who had Western-style ambitions for Soviet-era-embedded Yukos.

Gustafson writes that Mach’s large fracs were among the charges. Also offensive was Mach’s prioritization of fixing the best oil wells first and shutting in some 7,000 poor wells—roughly half of Yukos’ inventory.

“Mach regarded this wholesale triage as one of his proudest achievements,” Gustafson writes. “Yet there was one small problem with shutting down wells in this way: It was illegal.”

Gustafson’s 662-page Wheel of Fortune includes 110 pages of footnotes as endnotes, a 20-page bibliography and more than 1,000 indexed terms.

Since leaving Russia and what was left of Yukos in 2006, Mach runs an investment-consulting firm, Houston Consultants, according to the Society of Petroleum Engineers’ JPT publication, which recognized Mach in its 2009 annual “JPT Legends of Production and Operations” program.

In Mach’s first four years at Yukos, until the company was put into bankruptcy by the Putin government, JPT reports, “…Oil production more than doubled from 800,000 to 1.7 million barrels of oil per day. This was accomplished in part while the active, producing well count fell from more than 14,000 to 7,000. The increased production rate came about as a result of decreasing water cut by 15% and increasing the average rate per well fourfold, while reducing operating expense per barrel. Reserves increased by 3 billion barrels.”

Gustafson writes that Khodorkovsky admired Mach, who “did not discriminate between Russians and Americans; he was brusque with everybody” and whose manner of dressing down subordinates appealed to Soviet-era-styled workers’ expectations while Khodorkovsky’s manner was quiet. “(Mach) wove four-letter Anglo-Saxon into a unique language, which his interpreters struggled to render into Russian equivalents—no small achievement in Russia, the homeland of mat—the elaborate obscenity that is an art form among Russian males.”

In the Moskovsky Komsomolets’ interview in 2002, Khodorkovsky said of Mach, “He swears like a Russian.” Gustafson writes, “The unbelieving interviewer then asks, ‘In Russian?’ to which Khodorkovsky answers proudly, ‘In English, but the interpreter translates into Russian.’”

Gustafson’s book is available in print and Kindle format at Amazon.

-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.

]]> http://blogs.oilandgasinvestor.com/blog/2013/01/21/a-tulsan-in-russia-how-joe-mach-pumped-fraced-flooded-bleeped-yukos%e2%80%99-oil-output-into-doubling/feed/ http://blogs.oilandgasinvestor.com/blog/2013/01/19/woodmac-2013-us-ma-will-make-few-gas-headlines-many-for-unconventional-oil/ http://blogs.oilandgasinvestor.com/blog/2013/01/19/woodmac-2013-us-ma-will-make-few-gas-headlines-many-for-unconventional-oil/#comments Sun, 20 Jan 2013 00:49:43 +0000 Nissa Darbonne http://blogs.oilandgasinvestor.com/?p=2065 Canadian gas-weighted deal-making will continue, though, for export as LNG.

2013 U.S. oil and gas M&A deal-making will consist of few transactions for natural gas, Wood Mackenzie researchers forecast. “U.S. shale gas is likely to remain out of favor until expectations of future pricing begin to strengthen,” the Scotland-based firm reports in its annual global M&A review, “and the timing on that event is as yet uncertain.”

Spend on U.S. shale-gas properties fell to some $3 billion in 2012 from as much as $30 billion in 2011. Instead, gas-weighted deal-making was focused in Canada, where buyers anticipate exporting production as LNG (liquefied natural gas), particularly into the heated Asia-Pacific market from plants on the British Columbian coast, the WoodMac team reports in “Global Upstream M&A: 2012 in Review and the Outlook for 2013.”

Buyers of Canadian gas in 2012 included PetroChina Co. Ltd., Chevron Corp. and Petronas. The lattermost’s $5.2-billion bid for Canada-based Progress Energy Resources Corp. received federal approval in December. “Canadian shale-gas spend increased from $3.3 billion in seven deals in 2011 to $11 billion in 13 deals in 2012,” WoodMac reports.

In the U.S., existing LNG-import-plant operators and other firms have filed federal applications to build export facilities. To date, only one-that by Cheniere Energy Inc. for export from Sabine Pass, Louisiana-has received full approval. The U.S. Department of Energy is awaiting a series of public comment on allowing more.

The WoodMac team expects more gas-for-export transaction headlines in 2013-globally. “LNG will remain a key theme, whether through equity stakes in Australasia or in emerging developments in East Africa.”

In the U.S., meanwhile, buyers will spend more on adding unconventional-oil reserves to their portfolios, the researchers expect. Overall in North America, “the U.S. will see the vast majority of investment, but Canadian, tight-oil M&A could grow as embryonic plays are proved up. Canadian shale gas will continue to attract interest as a feedstock for future LNG developments. (In that,) the upper end of the market will continue to be dominated by Asian players-NOCs (national oil companies) and Japanese trading houses-and the very largest IOCs (international, non-government-held oil companies).”

Of course, U.S. shale gas remains in play with contrarian buyers, so a big deal of this nature “cannot be ruled out,” the team adds.

Otherwise, among unconventional-resource M&A in this and coming years, “Australia aside, unconventional plays outside North America are too immature to attract material M&A spend. We may, however, see some early-stage joint ventures targeting unconventionals in China and Argentina.”

-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.

Mark Collette, investigative reporter for the Corpus Christi Caller Times, tells the story in a recent special report of the geological and leasing feat behind Petrohawk Energy Corp.’s discovery of the Eagle Ford shale play in South Texas. The 4-year-old play is currently believed to be the largest-in terms of barrels of oil equivalent (BOE) that it holds, including oil, gas liquids and dry gas-in the Lower 48 today, rivaling that of the giant Bakken oil system in North Dakota and Montana.

Collette reports in a Dec. 29, 2012, article, “The Wildcatter: Corpus Christi’s Gregg Robertson, key member of Eagle Ford discovery, named 2012 Newsmaker of the Year,” of how Robertson, a long-time Corpus Christi-based geologist, was called upon by Petrohawk’s president and chief operating officer, Dick Stoneburner, in 2008 to help evaluate whether internal suggestions of the possibility of an Eagle Ford play could pan out. Robertson’s work included a trip to Texas’ library of more than 500,000 core and other rock material at the Bureau of Economic Geology’s headquarters in Austin that is part of a more than 2-million-box collection of subsurface materials there and in Houston and Midland.

Collette writes of Robertson’s Austin trip to analyze some Eagle Ford rock from an old South Texas well attempt, “The brown boxes sat like building blocks stacked 15 feet high in endless rows of towering metal shelves at a University of Texas research campus…Hidden here was the final piece of the puzzle that would change South Texas forever…Only Gregg Robertson knew where to look: Row 57, Bay H, Shelf 4.

“There, the manila pouches of ash-gray pebbles sat in their box. They probably went unnoticed since 1952, five years before Robertson was born. That’s when a Phillips Petroleum drillbit brought the cuttings up from a layer of sediment deposited on the sea floor more than 66 million years ago.”

For the full, approximately 3,800-word tale, see Collette’s article: “The Wildcatter: Corpus Christi’s Gregg Robertson.”

For a full report on the founding and growth of Petrohawk, which was sold in 2011 to BHP Billiton Ltd. for $15 billion for its leadership positions in the Haynesville and Eagle Ford shale plays plus horizontal Permian Basin potential, see the November 2011, Oil and Gas Investor, report, “Floyd-Opoly.”

–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.

Here, Louisiana Oil & Gas Association president Don Briggs discusses, in a guest column, industrial developments in the state as a result of an abundance of new Louisiana and other U.S. gas. -Nissa Darbonne

“One glance at the newspaper or a few minutes of watching the evening news and it is clear that the Louisiana economy is thriving with comparison to the rest of the United States. Plants are re-opening, oil and gas rigs can be seen peering over the treetops, the chemical and manufacturing industry are booming, and new hotels and restaurants are lining the frontage roads. A major contributing factor to our state’s economic success is the natural gas industry.

“Louisiana and many regions of the United States are experiencing a shale revolution, largely in part to the technology surrounding hydraulic fracturing and lateral drilling. While these shale plays are not newly discovered, many of them are now newly reachable within the last few years. Since 2008 alone, the natural gas industry in Louisiana has provided over $14 billion in economic impact, with more than 60,000 jobs created due to the Haynesville shale play in Northwest Louisiana.

“New construction projects are popping up all over Louisiana, thanks to the abundant natural resources that Louisiana has beneath our feet. In Cameron Parish, Cheniere Energy Inc. is constructing a liquefied natural gas (LNG) exportation plant that is an $11-billion investment in Louisiana’s economy. Another win for Louisiana is coming to Calcasieu Parish thanks to (South Africa-based) Sasol (North America Inc.), as it will be producing high-quality transportation fuels from natural gas. Sasol will be making an up to $21-billion investment in the state. And Caddo Parish is receiving two economic victories, one from BHP Billiton, which opened a $70-million, state-of-the-art facility that houses its Haynesville shale operations office, and the other victory coming from Benteler International AG, which will be opening a steel-making operation to the tune of $900 million.

“Dr. David Dismukes, a Ph.D. at the Center for Energy Studies at LSU, released a study recently with specific numbers about the future of our state. He said that the “abundance of natural gas resources has led to a virtual manufacturing renaissance in Louisiana where, to date, some $62.3 billion in new capital investments have been announced.” Dismukes goes on to say that, resulting from the natural gas induced projects, over 214,000 jobs and more than $9 billion in increased wages will likely result over a nine-year period.

“Jobs, multi-billion-dollar investments and new plants are each part of the macro-level ripple effect of the shale revolution that is taking place right here in Louisiana as well as around the country. To be more specific, Louisiana is the second-largest producer of natural gas in the United States and the third-largest consumer of natural gas. Dismukes credits the consumption level as being due to the massive “energy-intensive manufacturing industry” in Louisiana.

“Economic development announcements are a welcomed sight in Louisiana as the rest of the country struggles to overcome one of the worst economic recessions since the Great Depression. These aforementioned announcements are just a few examples of what a bright future Louisiana can expect. As more natural resources are developed in Louisiana and abroad, we can only hope to see more plants open and more jobs available.”

For more information about the Louisiana Oil & Gas Association, go to LOGA.la.

-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.

Amongst resource plays, next in line for advancement, since the Barnett, into oil- and gas-producing MLPs’ portfolios is the Fayetteville shale play, followed by the Haynesville, says Jonathan Hough, director, energy investment banking, for BMO Capital Markets.

On a scale of resource-play maturity-that is, its advancement from science experiments and early exploration to more of a methodical, manufacturing mode-the original shale play, the Barnett in the Fort Worth Basin in North Texas, is the most advanced, Hough notes. He presented to attendees at Hart Energy’s workshop in Pittsburgh on Marcellus and Utica finance and M&A, preceding the fourth annual DUG East conference.

Already, EV Energy Partners LP and Atlas Resource Partners LP have bought into the Barnett, which was proven by Mitchell Energy & Development Corp. in the late 1990s. Also, Fort Worth-based Quicksilver Resources Inc. plans to form an MLP, Quicksilver Production Partners LP, for the purpose of dropping into it its developed Barnett portfolio.

Meanwhile, the Fayetteville in Arkansas that was founded by Southwestern Energy Co. in 2004, hosts one MLP, Vanguard Natural Resources LLC, already. The Haynesville in northwestern Louisiana that was proven in early 2008 by Chesapeake Energy Corp., hosts Memorial Production Partners LP.

MLPs (master limited partnerships) are built to produce oil and gas-paying out earnings as pre-tax distributions to investors-and exploit known new-well targets, rather than to explore for oil and gas as do traditional E&P companies. “Basin maturity is critical to meet the MLP model,” Hough says.

Next on the MLP course? Far along, but still needing more capital-intensive investment and further de-risking, are the Marcellus, Bakken/Upper Three Forks, and Eagle Ford condensate window, Hough says. These remain best suited to traditional E&P companies, including slightly lower-risk-taking public-equity-backed E&Ps.

“The Marcellus is still in early-stage development versus the Barnett, which has matured,” Hough says. However, it is advancing much more rapidly. “It took more than six years for Barnett production to grow from 1 Bcfe (billion cubic feet equivalent) a day to 5 Bcfe a day.” Meanwhile, Marcellus grew to that rate in only two years of exploration and he estimates there are still 100 years of drilling left to be done in the rock at the current pace. In contrast, drilling inventory in the Barnett has declined to a 30-year supply, particularly at the current-gas-price pace.

Another distinction is that Barnett wells hit their MLP-appropriate decline rate-some 10% a year-in their fifth year of production, while Marcellus wells might not reach this until their seventh year.

And, existing Marcellus producers are not motivated to sell: Keeping exploration companies at work there-rather than casting off this inventory to MLPs as a means of funding a next great play-is that they can better afford to do this there than in the Barnett.

At a $4 gas price, Marcellus wells produce an average 44% internal rate of return (IRR), Hough says; Barnett, 28%. At $5, the Marcellus generates an average 75% IRR; the Barnett, 54%.

“Given strong economics of the Marcellus, producers are likely to continue development drilling. Monetizations will be more frequent as the basin matures.”

For most MLPs, they want more Marcellus production results to define areas with high concentrations of PDP (proved, developed, producing) reserves that are ready for infill drilling. Meanwhile, there are plenty of other, mature property packages for them to consider in basins elsewhere, he adds.

“Buyers and sellers agree that MLP M&A activity in the Marcellus will happen, but it’s too early,” Hough says.

For potential Marcellus sellers, they still have plenty of wells to drill, the Marcellus has superior economics and they can divest properties elsewhere to continue to fund Marcellus exploration. “Currently there is no pressure (for a producer) to find ‘the next asset’ to replace the Marcellus.”

The Marcellus itself is still a next, great asset. He notes that Range Resources Corp., which founded the Marcellus play in 2007, sold its Barnett acreage and production under and around its Fort Worth headquarters in just 2011 to fund development of its new Marcellus play.

Last in line for MLPs? Resource plays best suited to remain in the hands of public-equity-funded E&Ps-in terms of continued nascence, thus higher capital risk-for some time longer are, in order of most to least risk,

–The Lower Three Forks formations, which sit under the Bakken/Upper Three Forks play in the Williston Basin and hosts only a few wells yet, albeit each highly successful,

–Cline and Wolfbone in the Permian Basin,

–Utica in Ohio and northwestern Pennsylvania,

–Niobrara in eastern Colorado and Wyoming,

–Eaglebine in southeastern Texas,

–Bone Spring/Avalon in the Permian Basin,

–Mississippi Lime in northern Oklahoma and southern Kansas,

–Horizontal Wolfcamp in the Permian Basin, and the

–Eagle Ford oil window.

Perched on the border of being best suited for a traditional E&P-either publicly or privately funded-is the Eagle Ford’s dry-gas window, Hough says.

Drilling inventory? Hough estimates the

–Marcellus’ 15 million acres have 175,000 locations remaining to be drilled or a 100-year inventory at a rate of 1,650 wells a year,

–The Eagle Ford, across all windows, consists of some 10 million acres with 100,000 remaining locations or a 40-year supply,

–The Haynesville, 3.5 million acres, 50,000 locations remaining or a 50-year inventory, and

–The Barnett, 4 million acres, 30,000 wellsites remaining or 30 years.

“As (traditional E&P) C-corps continue developing new resource plays, legacy assets in blow-down stage will be divested, and MLPs are likely buyers,” he concludes.

But not just yet for most.

-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.

NOTE: For news tweets from DUG East 2012, search #DUGEA2012.

Oneok Partners LP’s withdrawal of its 1,300-mile, 200,000-barrel-per-day Bakken Crude Express pipeline plan from North Dakota to Cushing may reflect that

–Producers want flexibility of rail, instead, in the markets they can reach,

–Producers don’t want to send their oil to the WTI-priced Cushing market,

–The price of using the Oneok pipe wasn’t competitive with the flexibility of rail or other pipeline plans and/or

–More than enough pipe is already planned for Bakken take-away.

These are suggestions from myriad U.S. E&P analysts upon the Oneok news this week.

“We are not sure what the required terms were for the deal from Oneok,” says David Tameron, senior E&P analyst for Wells Fargo Securities LLC. “But the price could have been a deciding factor. We have heard from some producers that they are hesitant to make long-term commitments at this point as options multiply and producers see sufficient capacity via existing and in-process pipe and rail.

“As rail capacity continues to expand in the basin, providing access to additional markets outside of Cushing, we have seen refinery demand for Bakken crude stretch to the (East, West and Gulf) coasts, bringing along with it premium pricing.”

Analysts with Tudor, Pickering, Holt & Co. Securities Inc., report, “The abundance of rail is the likely culprit.” They estimate there are some 750,000 barrels of daily oil-by-rail capacity currently, plus some 450,000 a day of pipe. Also, some 1 million of additional pipe capacity is expected to come online by year-end 2015, they add.

Bernstein Research senior analyst David Vernon says, “Anecdotally, we understand producers are taking a wait-and-see approach in regards to shipping from the Bakken shale to Cushing, given the price differential between WTI-Cushing and (the coastal price). As such, it appears producers are reluctant to sign multi-year-approximately 10-year-pipeline contracts when railroads are offering flexibility of destination and one-, two- or three-year deals.”

In a report earlier in November, Vernon estimated U.S. oil carloads grew from fewer than 5,000 in first-quarter 2010 to nearly 90,000 in the second quarter of 2012. While rail provides producers with flexibility in the markets they can reach, he expects Bakken-by-rail will decline by 2014 as more pipe capacity comes online.

“A valid question is if other pipelines are at risk,” Vernon concludes. “We will be watching and asking industry contacts about other pipelines, though we suspect that one of the reasons the Oneok pipeline was cancelled was because there wasn’t enough (Bakken) crude oil production to justify its completion.

“Now it seems production and pipeline take-away capacity are better matched and, as such, we would expect the remaining pipelines to have a higher chance of being built.”

The WTI price-that is, the Cushing price-for oil has been less than the coastal price by $15 to $30 a barrel for most of the past 22 months.

Estimates are that North Dakota currently gives up some 700,000 barrels a day and the figure is growing at great speed, while formations in addition to the Bakken are coming online. The play’s founder, Continental Resources Inc., also proved the deeper Three Forks play to be a prolific oil producer. Since then, it has also proved the lower Three Forks II bench in 2011 with the Charlotte 2-22H that has made 87,000 barrels of oil equivalent (BOE) in its first 10 months. A second Three Forks II producer, ConocoPhillips’ Sunline 11-1TF-2SH, has made 85,000 in six months.

Continental is now drilling a first test of the yet-deeper Three Forks III zone with its Charlotte 3-22H. In accessing different markets, some of the company’s roughly 62,500 BOE a day of Bakken production is now going via rail to a refinery on the West Coast at Anacortes, Washington.

Bakken oil is also making its way to the East Coast, and more for that destination is planned. A day prior to the Oneok news, pipeline operator Enbridge Inc. announced a plan begin railing 80,000 Bakken and other barrels a day to a former coal-offloading terminal at Eddystone, Pennsylvania, south of Philadelphia. Two of a power-generation plant’s six generation units there had operated on coal until they were retired in just the past 18 months, thus retiring the coal-offloading terminal; the balance of the power-gen units use natural gas as feedstock.

Steve Wuori, Enbridge president, liquids pipelines, says of the rail plan, “Rail is the fastest way to provide increased export capacity out of the Bakken, creating a near-term solution to transportation bottlenecks and the resulting oil-pricing differentials.

“Eddystone is an important step in our longer-term strategy to accommodate the anticipated growth of light crude-oil supply and to provide Bakken producers and PADD I (that is, U.S. Northeast) refiners with cost-effective capacity to premium markets on the eastern side of North America.”

-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.

NOTE: For a full report on Bakken take-away to the East Coast and West Coast, in addition to the Gulf Coast, see “Tri-Coastal Bakken,” December, Oil and Gas Investor, at OilandGasInvestor.com.

Here, Texas Land Commissioner Jerry Patterson, elected to a third term in 2010 by Texans, provides his opinion of protests that are against the completion of the southernmost leg of the Keystone XL pipeline, which is to carry some 1.3 million barrels of oil per day from Canada to U.S. Gulf Coast refiners. -Nissa Darbonne

“As Texas Land Commissioner and the elected head of the General Land Office, my job is to generate income from state land and mineral resources that are constitutionally dedicated to funding public education, provide veteran’s benefits through the Texas Veterans Land Board, and protect the environment associated with state owned land, particularly along the Texas coast.

“In fact, Commissioner of the Texas General Land Office is the oldest continuously existing office in Texas government, having been established in 1836.

“I’ve recently learned that a bunch of out-of-state, self-appointed “eco-anarchists” think they know better than Texans and have arrived to save us from ourselves. They’re trying to block the Keystone Pipeline Gulf Coast Project, the pipeline that’s under construction in East Texas that will create thousands of jobs and lessen our dependence on foreign oil.

“Fortunately, they’re not succeeding.

“The only thing they’ve managed to do so far is get arrested and waste the time and resources of local law enforcement officers. They have also generated publicity for a clueless Hollywood actress who was recently arrested, and thanks to her mug shot, probably received more press than she’s received since she played a mermaid in a movie a couple of decades ago.

“The protesters are under the misguided notion that they know better than Texans about what’s good for Texas. I’ve got news for them: they don’t.

“Their scare tactics and misinformation won’t work in Texas. Gangs of tree sitters who trespass and defecate on landowners’ property don’t understand Texas values and culture. Their antics aren’t going to convince Texans to “rise up” and abandon our energy industry, an industry that has made this state the economic envy of the United States.

“If anything, they’re going to convince most Texans to tell them to shut up and go home.

“TransCanada has worked responsibly to ensure it has the legal authority and regulatory approval needed to build the pipeline and will diligently work to restore property to its original condition. Along the way, the company has treated Texas landowners with integrity and respect, which is more than I can say about the protesters and their trespassing, tree climbing, drum beating antics.

“Like all Texans, I expect TransCanada to meet high expectations regarding environmental and safety standards. As an elected steward of the land, a proponent of responsible energy production, and an advocate for private property rights, I expect TransCanada to continue to treat landowners fairly and respectfully.

“Texas is a proud leader in the development and transportation of oil and gas in a safe and environmentally responsible manner. As part of the Keystone Pipeline System, the Gulf Coast Project will be constructed using industry-best practices and will meet or exceed all regulatory standards. TransCanada also has agreed to meet 57 additional safety and operating standards above and beyond existing codes.

“One last point: If you think these folks are motivated by private property rights, think again. They are simply part of the environmental lunatic fringe that hates the oil and gas industry and is attempting to co-opt their message using the private property rights tradition that Texans hold dear. If you don’t believe me go to their website: www.tarsandsblockade.org.

“Given all those indisputable facts, it’s time for the protesters to come down out of the trees, take a bath, and hit the road.”

-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.

Colorado’s Niobrara play has the best NGL economics today, says KeyBanc’s Deckelbaum.

As prices for NGLs (natural gas liquids) decline, whose going to start feeling the pinch first? “Looking at possible slowdowns, we see the most risk for the Cana/Woodford and Eagle Ford (wet-gas-window) plays,” in terms of percent of production that is wet gas, says David Deckelbaum, senior E&P research analyst for KeyBanc Capital Markets.

Production from each play is roughly 30% NGLs. “At $90 (oil) and (as NGLs are getting) 40% of WTI, if NGL pricing comes down to 30% or so, the Cana and wet portion of the Eagle Ford become marginal at best,” Deckelbaum says. The third-ranked play would be the wet-gas window of the Marcellus, which produces 22% NGLs.

“A year ago, when you were at about 55% WTI, you were getting about $2.50 an Mcf equivalent uplift for having NGLs in your gas stream. We think that has compressed today to about a buck.” So, at the Nymex price for natural gas, “instead of getting $2.70, you’re getting about $3.70.” A year ago, at the Nymex prices for oil and gas, producers may have been getting more than $5.50.

Deckelbaum addressed attendees at a KeyBanc-sponsored industry program in Houston recently. He and fellow senior E&P analyst Jack Aydin cover some 34 oil and gas producers with roughly $140 billion in market capitalization, ranging from $200 million to $13 billion.

The best wet-gas play today is the Niobrara in the Wattenberg Field in Colorado, he says. “It has the best economics in the entire U.S. It’s tough to get some (acreage) positioning there, but we’ve seen some very reasonable acreage valuations…You can still lease at attractive pricing, compared with the returns you can get.”

Deckelbaum suggests that NGL producers hedge the heavier portions of the NGL barrel. “Consider hedging some of your propane…To some extent, we believe the lack of hedging reflects the attitude that some of this (down-pricing) is seasonal, that it’s going to be short lived, but I think we’ve all lived through attitudes like that before with natural gas-where we waited for a cold winter or a hot summer and it doesn’t do enough to really work down that excess supply.”

Demand for ethane is some 900,000 barrels a day while supply has grown to some 1 million a day. “We should see bringing on another 50,000 barrels a day of demand, but we still see a situation where we’re going to be oversupplied on the ethane side.”

Hedging is the best solution, he concludes. “Propane is a product you can hedge effectively. Hedging is at least something that many of our best-in-class names hedge well over 50% of production.”

-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.

With natural gas prices below $3, how do gas buyers get deals done? Year to date, 15 publicly announced, gas-weighted deals-that is, with proved reserves of more than 50% gas-valued at $25 million or more have been done, notes Sylvia Barnes, managing director and head of oil and gas investment banking for KeyBanc Capital Markets.

In the past 12 months, there have been 26 of these deals, she adds.

“They’re not getting done with the buyers we’re used to-the traditional oil and gas companies. Rather we’re seeing foreign entities, trading houses, the big private-equity firms with a contrarian view like an Apollo (Global Management LLC) and Riverstone (Holdings LLC et al.), such as in the $7.15-billion El Paso (Corp. E&P) deal.”

Barnes addressed attendees at a KeyBanc-sponsored industry program in Houston recently. “We are also seeing a lot of deals done where there is an advantage of cost of capital, like a flow-through MLP vehicle.”

These buyers, such as Linn Energy LLC and EV Energy Partners LP, use low-cost equity capital to buy producing properties that require little reinvestment in contrast with traditional, C-corp E&Ps, which must replace and grow production.

“We also draw your attention to how effective these flow-through MLPs are in their hedging strategy. The poster child for that is one of our clients, Linn Energy.” Among the 26 gas-weighted deals industry did for U.S. gas-weighted properties, Linn did 15%. “And every time they make an acquisition, they hedge 100% of the proved reserves for four years-100%. This has given them a strategic advantage.

“So to do deals in this market, you need to do something out of the ordinary. You have to challenge conventional thinking. This is the type of strategic thinking we’re seeing the successful players use to navigate the storm of these commodity markets.”

Amongst MLPs, the average gas-hedging level for 2014 is half that of Linn’s. “Even more interesting is, if you look at the C-corps, you’re down to 4% in 2014.”

Andrew Fletcher, KeyBanc senior marketer, energy derivatives, adds that, in hedging, producers have to be nimble and seize the day. “Be flexible on timing. Opportunities don’t always coincide with the next board meeting. Stick to your plan and don’t second-guess yourself. Failure to execute is a real cost.”

In 2008, when the gas-price strip pushed above $12, gas-weighted deals were at $3.01 per thousand cubic feet equivalent (Mcfe) of proved reserves, Barnes notes. There were 47 publicly announced transactions of at least $25 million in value that year. In 2009, when the strip fell below $4, there were 26 and at an average price of $1.75 per proved Mcfe. To date, the 2012 average is $1.37.

-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.

With one simple multiple, “3-4x,” Bill Marko explains just how depressed asset valuations for deepwater Gulf of Mexico assets are these days. The figure is how much public-stock investors will pay for these properties within E&P companies’ portfolios: three to four times EBITDA.

That’s in contrast with 8x to 10x EBITDA at which investors are valuing onshore U.S. unconventional-resource plays, he says, and is less than an overall multiple of 5x to 7x for large-cap E&P companies in general.

Marko, managing director, energy M&A, for Jefferies & Co., addressed more than 500 attendees at Oil and Gas Investor and A&D Watch’s 11th annual A&D Strategies and Opportunities conference in Dallas recently.

Since the Macondo incident in the Gulf in April 2010, “the increased regulatory environment, risk of deepwater operations, and size and timing of deepwater development are causing reconsideration of deepwater strategies,” he says.

In more than two years since Macondo, there have been only a handful of deals for Gulf assets, including a few that had been signed prior to April 2010 and subsequently closed on schedule.

The highest-profile new deal involved shallow-Gulf assets, with Oklahoma-focused SandRidge Energy Inc. buying Dynamic Offshore Resources LLC this year, sweeping the private-equity-backed producer off the IPO market. And, what a bargain it was, according to Tom Ward, SandRidge chairman and chief executive officer.

Ward told attendees at Oil and Gas Investor’s Energy Capital Conference in June, “The idea of us getting into the Gulf of Mexico was just a dislocation of the market. Post-Macondo, oil in the Gulf of Mexico was selling at a discount to what we could buy it for onshore the U.S.” (See senior editor Steve Toon’s report.)

Interest in Gulf leases is strong since lease-sales have resumed post-moratorium. Marko notes that the June 2012 Central Gulf sale was the third largest in history; the first- and second-largest were in 2008 and 2007, respectively, as oil prices were heading to $150 and natural gas above $10.

Tudor, Pickering, Holt & Co. Securities Inc. analysts reported after the 2012 sale, “The bidding was dominated by supermajors as the Top 5 accounted for 74% of total winning bids versus 48% in the March 2010 auction-with two supermajors in the Top 5 (at the time).”

But bids for shallow Gulf leases were weak this past June. “Shallow-water (acreage) received lots of attention, but operators were not paying up for it. Compared with the March 2010 lease sale, shallow water showed an increase of 28% in blocks receiving bids, but the price per acre declined from $118 to $102…

“The (shallow-water) bidding activity suggests lots of interest-if the price is right.”

-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.

What’s the next great new Lower 48 horizontal play? There will be fewer going forward, according to analysts at Tudor, Pickering, Holt & Co. Securities Inc.

“Interestingly, U.S. resource plays continue to be either smaller in areal extent or increase in complexity-there aren’t many Bakken, Eagle Ford, Marcellus (plays) popping up,” they note. Those three formations have been vast in acreage they underlie, commercial-success repeatability across that acreage and predictability in hydrocarbons they give up-all hallmarks of a “resource play.”

Investors wanting to anticipate the next great resource play may run out of relatively easy opportunities, so importance in stock-picking should be place more in the future on playmakers’ wherewithal to tackle complicated rocks. “We expect this trend (of fewer new plays) to continue and, over time, the affinity for stocks with differentiated abilities to find, develop and repeat smaller-field-type plays will increase.”

Gabriele Sorbara, E&P analyst for Imperial Capital LLC, says the Utica play, which Chesapeake Energy Corp. proved last year, remains promising. Yet, “the leveraged Ohio Utica shale companies-PDC Energy Inc. and Rex Energy Corp. in our (coverage) universe-may underperform the group in the near term, despite the numerous catalysts to come, given the high expectations set on the play.” As more data develops, “we believe a buying opportunity may emerge in 2013.”

The TPH analysts’ favorite new horizontal play is the horizontal Permian Basin “where we are expecting a slew of updates, including (M&A) transactions, well results and inventory updates over the next three to six months.”

Sorbara also likes the Permian’s more immediate potential: “…In this volatile market, we continue to believe the operators in the (more) proven plays, specifically…in the Permian Basin, Eagle Ford and Williston Basin, present the more attractive risk/reward profiles.”

The TPH analysts also have the Utica on an “areas to watch” list. Others are the

–Tuscaloosa Marine Shale, which Encana Corp., Devon Energy Corp. and Goodrich Petroleum Corp. are working to commercialize;

–the Woodbine play in East Texas that is being drilled by several private companies as well as Crimson Exploration Inc., Halcon Resources Corp., Zaza Energy Corp. and Devon;

–the Pearsall in South Texas that is being worked by Cabot Oil & Gas Corp., EOG Resources Inc., Goodrich and others;

–the Uinta in the Rockies that Newfield Exploration Co., Bill Barrett Corp. and Berry Petroleum Co. are drilling; and

–the Mississippi Lime that was commercialized by SandRidge Energy Inc. last year and is also being proven by Chesapeake, Midstates Petroleum Co. Inc., Range Resources Corp., Devon, Royal Dutch Shell and Apache Corp.

Midstates is expanding in the Mississippi Lime, buying a portfolio from privately held Eagle Energy of Oklahoma LLC for $325 million in cash and some $325 million of preferred shares. The TPH analysts expect the deal, which is to close by the end of this month, will bring a less complex cash-flow-maker to Midstates’ portfolio to balance its geologically complex Louisiana properties.

“The Mississippi Lime is one of the more recent emerging oily/NGLs-rich plays onshore with the distinct characteristics of being shallow reservoirs-driving low well costs and high-water-cut production,” the TPH analysts report.

Meanwhile, for more Utica-stock-pop exposure sooner, Sorbara suggests, from among just five Utica names in the Imperial Capital coverage list current, Magnum Hunter Resources Corp., “with a potential liquidity event on the horizon, given the company has hired an advisor to market its Utica shale properties in search of a joint-venture partner.”

Not covered by Imperial but also marketing Utica packages include Chesapeake and EV Energy Partners LP.

-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.

If they build it, the price will come….

In the midst of ethane rejection at Conway and somewhat-stranded Canadian oil-sands and North Dakota oil, several build-out and new-build fractionation, ethane-cracker, gas-export and refining projects are on the books across the U.S. to monetize producers’ new NGLs, dry gas and crude oil.

While burgeoning U.S. hydrocarbon supply has heralded expectations for a U.S. manufacturing renaissance, it is certainly resulting in a U.S. engineering and construction (E&C) windfall.

Here are details on some downstream build-out to take on new, indigenous supply as well as insight on further build-out, according to Tudor, Pickering, Holt & Co. Securities Inc.’s equity-research analysts’ notes since commencing coverage of E&C stocks this spring:

–Globally, “identifiable ethane-cracker work represents $20- to $30 billion of opportunity with a potential, overall chemical/petrochemical pipeline of $70- to $90 billion of projects, e.g. ethylene, PDH (propane dehydrogenation), butadiene.”

–Chicago Bridge & Iron Co. NV (CB&I) won a PDH construction job from Enterprise Products Partners LP, which enjoys “unparalleled access to Gulf NGL supplies,” for a fee-based PDH facility, giving Enterprise “a new growth platform and marginally improves propane supply/demand fundamentals with 35,000 barrels per day of demand, i.e. 3% of the market.”

–HollyFrontier Corp. is expanding its Woods Cross refinery in Salt Lake City. Marathon Petroleum Corp. has a $2.2-billion heavy-oil under way at its Detroit refinery. Valero Corp., which expects to quit using imported, light, sweet crude on the Gulf Coast by year-end 2013, has two $1.5-billion hydrocracker projects under way.

–E&C firm Fluor Corp. won $5 billion of additional oil and gas projects this spring globally, bringing its total for the sector to $19.5 billion. “Going forward, oil- and gas-sector prospects remain robust, especially on the low-U.S.-gas-price-driven side, given petrochemical, GTL (gas to liquids) and even LNG (liquefaction) opportunities…Fluor believes the U.S. markets-led by oil and gas and associated chemicals/industrial work-look promising.”

–Besides Fluor, KBR Inc. also expects some U.S. GTL-facility construction projects to come. “While we’re not certain of the economics there, (Fluor) maintains it is involved in some discussions on that front.”

–CB&I’s planned purchase of The Shaw Group Inc. in early 2013 will bring its all-sector backlog from $18 billion to $28 billion. “The acquisition also adds material U.S. leverage to CB&I as Shaw’s revenue is some 85% U.S. versus CB&I, which does some 80% international. Locking up a U.S. labor force for low-gas-/LNG-driven infrastructure build-out is also a potential goal here…(And) large, greenfield petchem projects have yet to hit E&C backlogs.”

–Technip bought Shaw Group’s “ethylene-cracker-capable energy and chemicals group” for $300 million. “Petchem capabilities are so hot right now…The deal demonstrates that E&Cs without petchem leverage are looking to jump in pre- the build-out boom-a theme we’re onboard with.”

–KBR’s North American construction-services backlog grew to some $2.3 billion this summer, such as for gas-processing. “Not coincidentally, the downstream backlog was up a whopping 60% to more than $700 million as shale production drives petrochemical and gas-processing work domestically and abroad.”

–The TPH analysts don’t expect many U.S. LNG export facilities will be permitted, though. “Exporting base hydrocarbons is not historically a U.S. forte….” That may bode well for more U.S. (end-user) E&C awards. “The U.S. prefers processing the hydrocarbons in-house and selling refined products-e.g. shale gas processed and fractionated, ethane extracted and cracked into ethylene then into plastic for export.”

–Williams Cos.‘ Williams Olefins LLC is well on its way to expand its ethylene plant at Geismar, Louisiana, from 1.35- to 1.95 billion pounds a year, awarding CBI with a $300-million E&C contract for this earlier this year.

–Meanwhile, KBR won a contract from Ineos Olefins & Polymers USA to build a 465-million-pound-per-year ethylene furnace along the Houston Ship Channel. “We believe U.S. ethylene-cracker build-out opportunity represents a potential of some $20 billion in expenditures by E&C clients; associated processing/fractionation opportunities offer an additional multibillion dollars of upside.”

–Bechtel Corp. has won Cheniere Energy Inc.’s Sabine Pass, Louisiana, liquefaction E&C project. Meanwhile, CBI has received the FEED project for Freeport LNG Development LP’s LNG project at Freeport, Texas.

–”CB&I views the North American petchem opportunity as $16 billion during the next 24 months, which we believe may surprise some folks to the upside. We estimate the U.S. ethylene-cracker opportunity alone at some $20 billion, but over a longer time horizon. Large greenfield cracker projects-potentially $4 billion each-are not likely a 2012 story but, as we saw with the $300-million Williams Olefins award, CB&I will benefit from ethylene-cracker expansions via its technology and E&C businesses in 2012.”

It will still be a while for downstream infrastructure to catch up to upstream supply, however.

Brad Olsen, TPH’s midstream analyst and author of its monthly NGLs report, notes, “We are seeing returns migrate from upstream companies towards the midstream and even the downstream-i.e. refining and petrochemical…

“Ethane supply is sufficiently robust and pricing versus crude is already sufficiently weak that petrochemical companies are rushing to build new and to convert existing ethylene crackers that are capable of consuming greater quantities of ethane. The rub: Ethylene crackers take two to three years to convert; five to seven years to build.

“That’s a lot longer than drilling wells, laying pipe or building new fractionation towers to deliver the end product to petchem consumers. Expect ethane supply to outpace demand through 2017-18.”

-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.

News of private-equity investor The Carlyle Group LP’s deal with Sunoco Inc. brings the Northeast U.S.’ high-priced oil-feedstock market into new, lower-priced, U.S. oil supply. Tudor, Pickering, Holt & Co. Securities Inc. analysts sum it up: “Cheap domestic supply versus expensive, light-oil imports equals action.”

Sunoco’s Philadelphia refinery had been slated for closing next month, while it and its already-closed Marcus Hook each depended on higher-priced, seaborne oil supply as feedstock in making refined products, such as gasoline. The TPH analysts name the Philadelphia plant as the largest refinery in the PADD 1, or U.S. East Coast region, processing 330,000 barrels of oil per day.

Plans are for railing Bakken-shale-play oil from North Dakota to the plant, giving it access to a lower-cost feedstock than Brent-priced oil. Upgrades to the plant will also utilize U.S. hydrocarbon producers’ new gas and gas-liquids supply from the Marcellus shale play that is in western Pennsylvania.

The TPH analysts note that some 50% of East Coast refining capacity had been targeted for closing. “But Trainer (the ConocoPhillips refinery Delta Air Lines bought this year and that processes 187,000 barrels of oil per day) and (Sunoco’s) Philadelphia escaped.” Western Refining’s Yorktown plant, which processed 60,000 barrels per day, is closed, along with Sunoco’s Marcus Hook, which processed 180,000 per day.

Paul Sankey, global energy analyst for Deutsche Bank, says in his report “Diamond Age: Refining and the U.S. Manufacturing Export Renaissance” on Monday before the Carlyle-Sunoco news, “We believe the U.S. unconventional oil and gas boom is a secular long-term play that is unique to the U.S., providing oil, natural gas liquids and natural gas at far below global prices for at least a decade to come.”

Stock investors are wrong if thinking the U.S. hydrocarbon-supply boom doesn’t create profit opportunity for U.S. refiners, he adds. “The equity market maintains an irrational belief in the cyclicality of this business, despite the secular shift. It refuses to pay for the export growth. It disregards the lack of new capacity addition and growth in exports. It ignores the improved, safety, returns, and management execution and strategy.”

Carlyle and Sunoco report in a joint press release that the continued operation of the Philadelphia plant-the oldest on the East Coast in continuous operation-will “save 850 jobs, secure the region’s fuel supply by continuing the daily flow of 10 million gallons of various fuels, and create 100 to 200 new, permanent jobs, as well as thousands of construction jobs.”

Brian MacDonald, Sunoco chairman and chief executive, says, “This partnership is a great example of what can happen when motivated people think creatively to solve pressing problems. The private sector, government and labor all played important roles in getting this done. This is the best possible outcome for everyone involved: Existing jobs will be saved, new jobs will be created and new business opportunities will be given the chance to develop.”

Carlyle managing director Rodney Cohen says, “Together we’ve re-imagined the Philadelphia refinery and its role as a critical energy hub in the Northeast. This joint venture will keep one of the region’s most important economic engines up and running. The refinery will be a reliable and critical supplier of fuels to the regional market through its new business structure and improved crude oil sourcing.

“In addition, the refinery’s exceptional location and infrastructure will enable the joint venture to create new business opportunities related to Marcellus shale natural gas fields….”

Leo Gerard, international president for employees’ rep United Steelworkers, says, “Not only will good paying manufacturing jobs be saved, but new ones will be created as this vital facility is improved and expanded.”

-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.

North Carolina’s legislators have overridden Gov. Bev Perdue’s veto of pro-hydraulic-fracture-stimulation legislation, thus allowing the well-known oil- and gas-extraction-assistance technique in the state in the future.

The state’s Senate voted 29-13 to override, according to Reuters; the House, 72-47.

James Taylor, senior fellow for environmental policy for The Heartland Institute, a Chicago-based supporter of free markets, says in an institute press release, “State agencies and the U.S. Environmental Protection Agency have diligently monitored hydraulic fracturing for decades. As EPA Administrator Lisa Jackson testified under oath in Congressional hearings, EPA has not found a single case of hydraulic fracturing contaminating groundwater. State agencies have yet to identify a single case of groundwater contamination, either.”

The institute also provides a statement from Bernard Weinstein, associate director of the Maguire Energy Institute at Southern Methodist University and a policy advisor to the institute: “…The outcome is a plus for North Carolina taxpayers and businesses. Fracking has been used for more than 50 years to complete tens of thousands of wells across the U.S., and neither the Environmental Protection Agency nor state regulators have ever documented a case of groundwater contamination from the process.

“North Carolina now has the potential to join America’s shale-gas revolution, which is helping put our country on the path to energy independence with attendant economic and fiscal benefits to producing states.”

For more information on shale resource potential in North Carolina, see “North Carolina’s Shale Potential Attracts Attention” at UGcenter.com. For information on hydraulic fracturing, see “Independent Review Finds EPA Pavillion Report Lacking in Scientific Data, Methodology and Analysis” at IPAA.org.

-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.

E&P management, capital, asset-marketing and recruiting veterans have a bounty of sage advice for MBAs and engineers looking to build and monetize an E&P company of their own. They converged in early June for an afternoon of rich tutorial on best practices.

–A good capital partner provides support. “You should be running the company. We try to provide oversight and not interfere with the ‘day to day,’” said Carl Tricoli, co-founder, managing partner and co-president of Denham Capital Management LP, the sponsor of Oil and Gas Investor’s annual “Starting and Building an E&P Company: The Workshop.”

Denham’s current private-equity fund consists of $3 billion for investing in start-ups in E&P and also in new oilfield services and midstream ventures with targeted initial commitments of $75- to $100 million.

Tricoli notes that a start-up should be launched with a complete management team, including with a chief financial officer-no matter if the founding CEO thinks one isn’t necessary yet. When a CFO is needed, “it may take six months to find one,” he says.

–David Preng, president and founder of the 32-year-old energy-executive recruiting firm Preng & Associates, provided questions to ask possible management-team members. For example, when interviewing someone who will run operations, ask about what vendors he would turn to for solutions. Also, ask if he is aware of local operating customs. “Can he anticipate problems and how would he avoid them?”

Consider too what your company brings to the table. “Money (alone) is not what drives people to move from one company to another,” Preng says. Instead, it’s for the work, the challenge and the pursuit of something to be proud of. A start-up developer should ask, “Will people want to come here? Is it exciting?”

And, be careful of recruiting from the super-majors, he warns. Employees there tend to eventually become task-specific-or “silo-ed”-and become overly reliant on systems and other employees. “Get them before they hit their 10-year mark (with the major).” After this, odds are diminished of bringing in a self-sufficient, motivated, multi-tasker, he says.

When checking references, “nobody really wants to say anything bad,” he adds. To get beyond this, ask the past employer about the individual’s performance reviews. Was he counseled on areas that needed improvement, what were they and what were the results? “That will tell you so much.”

–And, the payday will come to the successful. Craig Lande, managing director for asset-marketing firm RBC Richardson Barr, provided a “report card” for E&P asset portfolios that win premiums: control of operations, production and cash flow, and a high working interest. “The higher the better,” he says.

About acreage, “more is more,” contiguous leasehold is more valuable, long lease terms are good but “held by production” is best, and ownership of all rights at all depths results in a less complicated valuation. A reserve life of more than 10 years is optimal.

And, wait, if possible, until the portfolio has achieved bulk. “Bigger deals get premiums over smaller deals.”

–Rich Gan, team lead and managing director for Wells Fargo’s energy-lending group, oil and gas division, notes to establish a borrowing base with a bank-even if not having assets yet to support a loan. “Involve your bank early,” Gan says. A zero-dollar borrowing base can be established to open the relationship. When that first company-building, platform-asset acquisition comes along, the initial paperwork is already done.

–Tyler Crabtree, chief financial officer of Denham-backed start-up Ursa Resources Group II LLC, reminds those starting up an E&P that staffing is a luxury. Be flexible. “Sometimes you have to take the trash out.”

-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.

While producers highlighted their liquids-rich profiles, natural gas prices were also addressed at OGIS New York-directly at times but mostly indirectly, as if “gas” is the “Voldemort” of the industry as “he who must not be named” is in the Harry Potter stories.

John Walker, chairman and chief executive of EV Energy Partners LP and a contrarian buyer of gassy properties and production in the past few years, said, “For the first time since 2007, I’m turning a little bit positive about natural gas (dynamics)…

“We needed a really dreadful (price) event to stop people from drilling gas wells and bring some balance to the supply and demand.”

Walker addressed some of the more than 1,600 registered attendees at the IPAA’s 18th annual oil and gas investment symposium last week.

The company’s production is hedged at higher-than-current gas prices through 2014, “so we’re okay through then.” He still seeks to add gas-as well as oil-properties to EV’s portfolio, he added. “All we’re looking for is a good PV (present value). Rate of return is what drives us.”

Tim Benton, GMX Resources Inc. executive vice president, geosciences, said of the Haynesville dry-gas play, “When you’re selling gas at $2 an Mcf, it’s hard to be excited about anything.”

Leaseholders in the northwestern Louisiana gas field have now mostly secured their positions by 640-acre sections-some of it leased for as much $25,000 an acre in late 2007 and early 2008 when gas prices were more than $10 an Mcf-and are laying down rigs rapidly.

However, GMX has acreage over and production from the oily Bakken, Sanish and Three Forks in North Dakota, as well as leasehold over the oily Niobrara in the Rockies. And, it is focusing its efforts there.

Tony Best, SM Energy Co. president and CEO, noted, “We’re completing our last Haynesville well at this time.” All of its acreage there is now held by production. New wells are possible when gas prices improve.

Gary Evans, Magnum Hunter Resources Corp. chairman and CEO, said the company is also reducing its gas-directed drilling. “We’re trying to do our part.”

-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.

“At 80 years old, I’m really glad to be here,” Clayton Williams, founder, chairman, president and chief executive of Clayton Williams Energy Inc. (Nasdaq: CWEI), told some of the more than 1,600 registered attendees at the IPAA’s 18th annual OGIS New York investment symposium last week.

The legendary Permian Basin wildcatter joined Mel Riggs, executive vice president and chief operating officer, in presenting the Midland, Texas-based company’s financials and outlook, providing some current color to the U.S. oil and gas field, which he calls “the most fun business I can imagine.”

The business begins with an idea, he said, and then geologic work, some seismic shoots, leasing, drilling a well, and “you create wealth for a lot of people…that didn’t exist until it started in your mind.”

During his career, he adds, “many times, you wouldn’t have recognized me. Back when oil was (a remarkable at the time) $40 in the old days, I was 6 foot 4; by the time it got down to $9,” not so tall, he quipped.

And, it’s important to use other people’s money, OPM, and to do it wisely. “I never had enough cash flow to do what I thought needed to be done, so generally I’ve had a debt load of around $500 million-and it’s not much if you say it quick.”

A good reputation is essential. “I’ve borrowed money from a lot of different banks. I can tell you I could go back to all of them-but there’s one or two I wouldn’t go back to because they were hard on me when I was down and now they come around, kissing my…

“So I think a good reputation, paying it back, meeting your commitment of doing what you said you would do has been my trademark…(This way,) you go bed and sleep at night. I like that. So, life has been good for us.”

About that cash flow and credit capacity, the “banks are still happy with us.” The company has a $475-million borrowing base and has drawn $180 million. “We haven’t even used up all our credit this time. I don’t know what we’re doing wrong,” he joked.

Some more highlights:

–In Reeves County, Texas, in the Permian Basin, “holy mackerel” there are more than a dozen pay zones to tap. The company will work toward holding its 60 square miles of leases by production from vertical wells in Wolfcamp and Bone Springs, which will take two years alone, and then come back with horizontal wells. “It’s an amazing thing that has happened right next door to where I live (in Midland).”

–”We have problems in the Permian with getting the oil out of the basin, there’s so much production that has come on.”

–The company holds a lot of acreage that has potential for renewed production via waterfloods. “They’re wonderful, but sometimes they (have a) three- or four-year payout. We think our opportunity is in drilling wells today and putting (our) new acreage into HBP (held by production)…When we get bored…, we’ll go into the waterfloods.”

–The company is also a long-time producer from the Austin Chalk in Texas, and its acreage doesn’t include much prospective for Eagle Ford. “It’s good reserves and economics, but we were late having acreage in it.”

–Nearly 50 of the company’s employees have been with it for between 20 to 35 years. “If you take care of your employees, they’re going to take care of you. I think that’s the right way to run a company; I know…it’s the best way to live your life.”

–As oil prices have fluctuated, including to as little as $10 in the late 1990s, “I’ve been through five different layoffs and about that many pay cuts to be able to stay in business these years.”

–The U.S. is the best place to build a business. “I’ve been able to keep people a long time…We’ve been able to do that because we live in a free country and we live in Texas, which is probably the freest state…All of this (business) would be bull—-, if we didn’t have the privilege of being in the United States of America.”

Williams, who once ran for governor of Texas, concluded his remarks: “And, relax. I’m not running for a damn thing.”

-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.

Oil and Gas Investor’s annual Energy Capital Conference, “Inside the Boardroom-Have a Seat at the Table,” opens June 6 at the Omni Houston with two encore half-day exclusive sessions: “The CFO Workshop: Beyond the Numbers” and “The Workshop: Starting and Building an E&P Company, 2012.”

The full-day forum opens June 7 with keynote remarks by Ed Morse, managing director and global head, commodities research, for Citigroup Global Markets Inc., from his new report, “Energy 2020-NorthAmerica as the New Middle East.”

Morse says, “The United States has become the fastest-growing oil and gas producer in the world, and is likely to remain so for the rest of this decade and into the 2020s.” Only one thing can impede this, he adds: Politics.

Also, closing keynote remarks will be presented by Dick Morris, political author and presidential campaigner and advisor.

Joining Morse and Morris will be additional, leading insiders and forecasters discussing matters that affect E&P and other energy company-builders, including:

–Floyd Wilson, chairman, president and CEO of Halcon Resources Corp. and founder of Petrohawk Energy Corp., which was sold to BHP Billiton Ltd. last year for $15 billion,

–Tom Ward, founder of chairman and CEO of SandRidge Energy Inc., which is the lead developer of the Mississippi Lime play in Oklahoma and southern Kansas,

–Gary Evans, founder, chairman and CEO of Magnum Hunter Resources Corp. and chairman of GreenHunter Energy Inc.,

–John Olson, the award-winning 35-year natural gas analyst and retired managing partner of SMH Capital Group’s Houston Energy Partners,

–Forrest Hoglund, chairman and CEO of LNG tanker company SeaOne Maritime Corp. and former chairman of EOG Resources Inc. and Forest Oil Corp.,

–Kent Wilkinson, vice president of Chesapeake Energy Corp.’s new Chesapeake NG Ventures Corp., which has invested in Clean Energy Fuels Corp. and other companies working toward greater use of U.S. natural gas,

–Jerrit Coward, president, oil and gas segment, for energy-infrastructure company Willbros Group Inc.,

–Bill Cooper, president of the Washington, D.C.-based Center for Liquefied Natural Gas,

–Dr. Peter Hartley, Rice University professor of economics, James A. Baker Institute fellow and the current president of the U.S. Association for Energy Economics,

–Marty Phillips, co-founder and managing partner of private-equity firm EnCap Investments LP, which has invested approximately $5.5 billion in 175 different oil and gas companies in the past 20 years,

–Bruce Bullock, director of the Maguire Energy Institute at Southern Methodist University and author of numerous articles and a blog, “Barrels and BTUs,”

–John McNabb II, vice chairman, investment banking, for Duff & Phelps Corp. and founder of energy financier Growth Capital Partners LP,

–Mark Ammerman, industry head, energy, U.S., Latin America and U.K./Europe, for Scotiabank Global Banking & Markets, which is in the midst of acquiring New Orleans-based boutique investment banker Howard Weil,

–Mark Bononi, senior analyst for global small- and midcap energy-sector growth investor Vedanta Energy Fund, and

–Bill Weidner, president and CEO of Weidner Advisors and the former co-manager of The Rodman Energy Group and COSCO Capital Management.

Workshop presenters include

–Carl Tricoli, co-founder, managing partner and co-president, Denham Capital Management LP,

–Frank Verducci, managing director, structured products, BP Corporation North America Inc.,

–John O’Shea, co-founder & CEO, Tradition Midstream LLC,

–Hal Chappelle, president and CEO, Alta Mesa Holdings LP,

–Dr. Tomas Villamil, co-founder & executive vice president, exploration, C&C Energia Ltd.,

–Matt Steele, president and CEO, Ursa Resources Group II LLC,

–Tyler Crabtree, chief financial officer, Ursa Resources Group II LLC,

–Mike Wylie, president, Cascade Petroleum LLC,

–Jerry McGee, president and CEO, Cadre Proppants,

–Victor Perez, chief financial officer, Gori Energy Inc.,

–Jim Burgoyne, managing director, natural resources, GE Energy Financial Services,

–Tom Field, director, Quantum Energy Partners,

–Sylvia Barnes, managing director and head, oil & gas corporate & investment banking, KeyBanc Capital Markets,

–Tim Carlson, senior managing director, Evercore Partners,

–Chris Croom, president, Asset Risk Management LLC,

–Frank Verducci, managing director, structured products, BP Corp. North America Inc.

–Bryan Chapman, executive vice president and manager, energy lending, IberiaBank,

–Rich Gan, team lead and managing director, Wells Fargo,

–Craig Lande, managing director, RBC Richardson Barr,

–Chris Lallo, partner, transaction advisory services, Ernst & Young LLP,

–Ken Friedman, director, Denham Capital Management LP,

–Jordan Marye, managing director, Denham Capital Management LP,

–David Preng, president, Preng & Associates,

–Dick Rice, partner, Bracewell & Giuliani LP.

–Jon McCarter, partner, transaction advisory services, Ernst & Young LLP,

–Greg Matlock, senior manager, transaction advisory services, transaction tax, Ernst & Young LLP,

–Bill Arend, regional manager, Oracle, and

–Kevin Richards, partner, partnership transactional planning and economics group, Ernst & Young LLP.

Hear the experts’ views on politics, the spread and take-away issues; raising and investing capital; the natural gas conundrum or arbitrage opportunity; and opportunities for both organic and inorganic growth. All of this directly from top decision-makers and their advisors.

Click here for the agendas: Energy Capital Conference, The CFO Workshop, The E&P Start-Up Workshop.

-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.

Privately held E&Ps have been picking
up rigs faster than publicly held E&Ps in the past month, Uhlmer adds.

Rigs that are exiting the Haynesville
dry-gas play in northwestern Louisiana and northeastern Texas at a rapid pace
are finding new homes in South Texas’ Eagle Ford oil and gas-liquids zone. “Since
the beginning of the fourth quarter of 2011, the once-prominent Haynesville shale
has witnessed an astounding 50-rig decline—a 43% decline—and now stands at 67
rigs,” says Brian Uhlmer, senior oilfield-services and -equipment analyst for
Global Hunter Securities LLC.

This is while the overall U.S. rig count
has grown 4% in that period, Uhlmer adds, based on Schlumberger Ltd.’s Smith
Bits rig data.

At the horizontal Haynesville’s peak in
2010, more than 180 rigs were drilling for the formation’s bountiful gas while
gas prices were mostly still above $4 and producers were rushing to secure
acreage for which many had paid more than $20,000 an acre to drill. Since then,
gas prices have fallen to some $2.50 per million Btu on Nymex, making many new Haynesville
wells uneconomic; several E&Ps have wrapped up or are nearly wrapped up
with holding their acreage by production (HBP); and/or some E&Ps will allow
to expire some acreage that has been determined since the height of the land
rush to be less-economic, “fringe” zones.

In the play, an E&P must have at
least one producing well per section (640 acres) to HBP the entire section and,
thus, be able to return another day to drill the rest of the section without paying
for new leases.

Uhlmer says, “Of the 50 fewer rigs
drilling in the Haynesville today, the Eagle Ford has been the most welcoming,
and currently accounts for 13 of the 30 ex-Haynesville rigs currently working
in other plays.”

Among the other rigs, he adds:

–Three have gone to work on the Austin
Chalk play just north of the Gulf Coast Basin;

–Three on the Granite Wash gas-liquids-rich
play in western Oklahoma and the Texas Panhandle;

–Three in the Permian Basin where new
horizontal oil and gas-liquids developments have pushed the total rig count to
more than 400;

–One in the Cana gas-liquids-rich play
where Devon Energy Corp. is dominant;

–One each in East Texas, other pay in North
Louisiana, the new oil-rich Tuscaloosa Marine Shale play in southeastern Louisiana
and southwestern Mississippi, and the Woodford shale play in eastern Oklahoma;
and

–Three in other plays.

Drillers with the most relocated or
idled rigs out of the Haynesville play (by number of rigs and not percentage)
since the end of September 2011 are:

–Trinidad Drilling Ltd., down 14, from
18 to four. Eight have gone to the Eagle Ford; one to the Tuscaloosa; and six
are idle.

–Patterson-UTI Energy Inc., down 10,
from 19 to nine. Two have gone to the Eagle Ford; one to the Austin Chalk; two
to other plays; and five are idle.

–Nabors Industries Ltd., down eight,
from 29 to 21. One has gone to the Austin Chalk, Eagle Ford, Permian each; one
has gone to another play; and six are idle.

–And, Ensign Energy Services Inc. and
Unit Corp., each down five, from five to zero. The new location of Ensign’s rigs
is to be determined, as Ensign is renaming the rigs, Uhlmer notes, after having
purchased them from Rowan Cos. Inc. The five Unit rigs are now in the Granite
Wash (one), Woodford (one) or idle (three).

Trinidad, Patterson-UTI and Nabors had
the most rigs running in the Haynesville at third-quarter 2011’s end. In the
No. 4 spot was Helmerich & Payne Inc., whose count has declined from 10 to
eight.

“Nabors remains the most active driller,
currently running 21 rigs in the play, followed by Patterson-UTI with nine, and
both Helmerich & Payne and (privately held) Scan Drilling with eight rigs.”

According to the Baker Hughes Inc.’s
weekly rig count, 1,984 rigs were at work at the end of last week, up 11 from
the week before and all of the additional are working on oil targets. “Year to
date, Baker Hughes’ oil-rig count has increased by 124 versus a gas-directed decline
of 146 rigs,” Uhlmer says.

He notes too that private E&P
companies are picking up rigs faster than public companies. “Public E&Ps
have put 13 more rigs to work over the past month. Private operators have
outpaced public E&P rig-count additions, putting 38 more rigs to work over
the past month.”

The U.S. land-rig inventory has plenty
more work to do: In just the past week, E&Ps submitted requests for permits
to drill 1,318 more wells locations across the U.S., “bringing the four-week
average to 1,407 or some 11% above year-ago levels.”

–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.

Railing in lieu of pipe is expensive and not enough railcars are
available, says Dahlman Rose’s Seidl.

Oil production from the Bakken play in North Dakota has now
reached some 600,000 barrels per day, up from virtually none just five years
ago and some 400,000 a day a year ago, according to John Seidl, director,
E&P research, for Dahlman Rose & Co.

Additional new Canadian oil production has put between 2.0-
and 2.4 million barrels of oil per day into the U.S. market, up from some 1.8
million a day five years ago, Seidl adds.

And the barely year-old Mississippi Lime oil and gas liquids
play in northern Oklahoma and southern Kansas has SandRidge Energy Inc. in an
arrangement with Plains All American Pipeline LP to ship out 150,000 barrels a
day. Meanwhile, Chesapeake Energy Corp. is in a deal with Semgroup Corp. and Gavilon
LLC to send out 140,000 a day, note analysts with Tudor, Pickering, Holt &
Co. Securities Inc.

Bottlenecks are growing, Seidl says, as Canadian oil meets
with North Dakota oil in trying to get to the U.S. Gulf Coast and both are running
into new Oklahoma oil production along the way.

“Producers in Canada and the Bakken are increasingly turning
to rail as a transportation option to move barrels,” Seidl says. “For example,
in the Bakken, the current capacity to get oil onto rail is 160,000 barrels per
day, but, by early 2013, that capacity is expected to increase to 527,000. Hess
Corp….expects to generate higher profits from railing crude to the Gulf Coast
than it currently receives from selling oil into the pipeline system. Anecdotal
reports from Canadian E&Ps suggest they are also using rail to get around the
pipeline bottlenecks, as they are working on adding capacity.”

Meanwhile, Canadian oil-sands producers who have been
counting on the Keystone XL project to get their oil to the Gulf Coast are
looking west, note the TPH analysts. Kinder Morgan Inc.’s TransMountain
Expansion (TMX) project will move an additional 300,000 barrels per day by 2016
to the West Coast, up from 300,000 a day currently. “TMX challenges Enbridge
Inc.’s larger Northern Gateway (pipeline) for Alberta-to-the-Pacific supremacy
as post-XL regulatory uncertainty increases interest in projects that utilize
existing pipes, like TMX,” the TPH team reports.

Seidl notes that Canadian oil is now fetching $10 less on the
market than U.S. onshore—that is, West-Texas-Intermediate-priced oil—which is
fetching $18 less than Gulf Coast or Brent-priced oil or nearly $30 less
combined. Meanwhile, railing oil from the oil sands of Alberta to the Houston
Ship Channel costs $10 to $14 a barrel.

Seidl says, “There appears to be an opportunity to narrow
that gap by arbitraging the differential; the aforementioned cost from Edmonton
to Houston suggests there should also be an arbitrage between WTI and Gulf
Coast pricing too. However, the mathematical arbitrage does not exist in
reality because of the shortage of rail cars.”

In early January, 19,376 North American railcars carried
petroleum products, he adds—“the highest weekly traffic ever for the commodity.”

Some relief to producers seeking to get their oil to the
highest-priced, Gulf Coast market will come this summer as the existing Seaway
pipeline that brings Gulf Coast oil to Cushing, Oklahoma, is reversed, moving
150,000 barrels per day to the Gulf Coast instead and as much as 400,000 a day
in 2013.

“Enbridge expects to bring on an additional pipeline from
Cushing to Houston in 2014, along with a new pipeline from Illinois to Cushing,
which would essentially open up capacity for Canadian crude to reach the Gulf
Coast. Another Enbridge project to reverse the flow of oil from Sarnia, Canada,
to Montreal by 2014 could also aid in reducing the differential between the
Midcontinent and the Gulf Coast. “However, North American oil production likely
will also grow sizable volumes during the same timeframe. Other future sources
of potential relief would come from approvals to build Keystone XL, Northern
Gateway and the TransMountain Expansion,” Seidl concludes.

–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.

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.

Panelists include Joe Foster and Forrest Hoglund, Bobby Tudor and Jack Randall. Topics include international JVs, turning purchases into profit, what the money wants, what the deals will cost.

Want to be on top? Forrest Hoglund, Joe Foster, Charles Stephenson and Ted Collins will be in the house Aug. 30 at the 10th annual A&D Strategies & Opportunities conference in Dallas, presented by Oil and Gas Investor and A&D Watch.

In a special roundtable panel, these heavyweight-ranks, legendary deal-makers will tell tales from both sides of major purchases and divestments, how they got it right, how they made them right and how they knew which ones were wrong in “The Masters—Their Favorite Deals, The Ones That Got Away, And The Ones They’re Glad Got Away.”

Also on tap for this anniversary edition of the No. 1 E&P M&A gathering of the year are these powerful deal-makers and hot topics. Click for the full conference agenda. Click to register.

–Sheridan Production’s Lisa Stewart, QR Energy’s Alan Smith and Concho Resources’ Jack Harper will present on and discuss how their acquisition targets have fit their business strategy and how they’re generating a greater return on investment in “Field Reports—How These Producers Are Turning Purchases Into Profit.”

–International M&A advisor Bobby Tudor will provide the 411 on global energy capital access and demands and oil and gas markets.

–Fresh from inking a $15-billion sale to BHP Billiton Ltd., Petrohawk Energy Corp.’s Steve Herod will lead the roundtable discussion “The Metrics & Drivers–What Assets Cost,” including presentations by Albrecht & Associates’ Harrison Williams on “Cost & Competition For High-PDP (80%) vs. Low-PDP (20%) Plays;” Jefferies & Co.’s Bill Marko, who co-led two Chesapeake-CNOOC JVs on “JV Rewards: The Latest Deal Terms, Play By Play;” Tudor, Pickering, Holt’s Ward Polzin, who represented CNOOC in these deals, on “Conventional v. Unconventional: Cost Of Entry, Lease Renewal, Lease Expansion;” and RBC Richardson Barr’s Scott Richardson on “Cash Or Stock: The Latest Dynamics In Financing The Deal.”

–Energy M&A innovators Jack Randall and Ken Dewey, who founded Randall & Dewey in the supermajor divestment windfall of 1989, will share their prescience about A&D then and today in a spotlight Q&A as well as receive Oil and Gas Investor and A&D Watch’s “Lifetime A&D Achievement Award.”

–Global Hunter Securities’ Michael Bodino, who gave industry its first breakdown on the Tuscaloosa Marine Shale play in May at Hart’s DUO conference, will reveal U.S. conventional formations that are ripe targets for unconventional technology in “The New, ‘Old’ U.S. Oil Plays—Where Are They?”

–BNP Paribas’ David Marcell will present his ground-breaking formula for when to sell in “Defining the Exit Window.”

–Three-decade-long PE investor EnCap Investments’ Murphy Markham will lead the roundtable discussion “The Money—What Capital Sources Will Fund Today” with presentations by SandRidge drilling-trust leader Howard House of Raymond James on “The U.S. Drilling Trust and the New Canadian Royalty Trust;” longtime PE-to-E&P matchmaker Weidner Advisors’ Bill Weidner on “Private Equity For Big and Small;” Banc of America Merrill Lynch’s Randy King on “The JVs: What’s Next?;” and commercial-lending scorecard-keeper Macquarie Tristone’s Jon Goddard on “Energy Lenders’ Price Decks.”

–Netherland, Sewell & Associates’ Lance Binder will lead a discussion of “The Gas Glut & The Liquids-Rich Rush” with presentations by The Oil & Gas Asset Clearinghouse’s Ken Olive on “Oil v. Gas: The Bid/Ask Spread;” Madison Williams’ Sylvia Barnes on “Buy Gas Now;” and DrillingInfo’s Ramona Hovey on “Need a JV to HBP? Lease Expirations on the Horizon, Play by Play.”

Click for the full conference agenda. Click to register.

–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 source rock for nearly a century of Upper Smackover production is a new target as a horizontal oil play.

A hot new horizontal “dirty shale” carbonate/shale play may surface from the Lower Smackover’s Brown Dense. Here are some facts about the formation. For a new report, see “At Closing” in the September issue of Oil and Gas Investor online Sept. 1. Available online now from March 2011: Let’s Talk Some Smack(Over).

–The Brown Dense play is also known as the Lower Smackover Brown Dense or LSBD. It is a Jurassic-age, kerogen-rich, carbonate/shale source rock. It is a “dirty shale” in that it is mixed with carbonate. It is also described as an organically laminated, carbonate mudstone. And, it is at times called a limestone.

–The formation is found from East Texas to Florida. In northern Louisiana, it and its Upper and Middle Smackover members are just below the Haynesville shale play. In the area, Lower Smackover is at 8,000 to 11,000 feet and is between 300 and 530 feet thick.

–Southwestern Energy Co.’s new 460,000-net-acre leasehold is in southern Arkansas and northern Louisiana. It is at an 82% average net revenue interest. The average primary lease term is four years with four-year extensions. It was leased at an average of $326 per acre.

–Two horizontal wells are under way now—one by Southwestern in southern Arkansas and one by Devon Energy Corp., which has some 40,000 net acres over Brown Dense. The Southwestern horizontal, in Columbia County, Arkansas, will have a vertical depth of some 8,900 feet and lateral length of 3,500 feet.

–Rehan Rashid, E&P analyst for FBR Capital Markets, says total organic content (TOC) is high and carbonate content appears to be 40% to 60%.

–The oil is light at 40 to 50 API gravity. There may be high sulfur content (H2S). Upper Smackover production, since the 1920s and which is sourced from Lower Smackover, is sour. Sour hydrocarbons will need processing.

–Porosity and permeability appear to be similar to that of the Eagle Ford shale play, which is also a carbonate/shale mix or “dirty shale.” Southwestern says a piece of a core sample it tested from Brown Dense was brittle.

–In southern Arkansas, laterals of some 4,500 feet are all that is allowed. In Louisiana, between 6,000 and 8,000 feet is allowed.

–Core Lab calls Lower Smackover Brown Dense “one of the most prolific source rocks in the Gulf Coast Basin area.”

–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.

Tudor, Pickering, Holt & Co. Securities Inc. analysts say Niobrara wells cost less but make less after-tax return on investment.

How does the horizontal Niobrara oil play in the Denver-Julesburg Basin of northeastern Colorado and southeastern Wyoming compare with the oily Bakken and Eagle Ford?

Tudor, Pickering, Holt & Co. Inc. analysts say there may be more original oil in place (OOIP) in the Niobrara (30 million barrels of oil equivalent per square mile, including chalk and marl/shale intervals) than in the Bakken (10- to 15 million) but less than in the Eagle Ford (30- to 50 million).

In the Niobrara, when considering OOIP in the “B” chalk bench only, which is thicker and has better porosity than two other chalk benches (A and C), the TPH analysts estimate 5- to 10 million BOE—or less OOIP per square mile than in the Bakken or Eagle Ford.

Also, reservoir pressure is lower in the Niobrara, so productivity and recovery are lower and less consistent on average. And, development is being slowed by that many leases are held by production from other formations. Thus, there is no rush to drill to hold the acreage for future development and operators are more willing to let other producers do the spending to crack the Niobrara well-design and fracture-stimulation code. In the Bakken, for example, most leases are new and expire within three to five years if not drilled, so there is more activity.

“Also, most operators are acquiring 3-D seismic to better understand the (Niobrara) reservoir prior to drilling,” says Jessica Chipman, a TPH analyst and lead author of a new Niobrara study.

As for well spacing in the Niobrara, this may be similar to or tighter than in the Bakken and Eagle Ford when there is little natural fracturing in the well target. The Niobrara formation has low “fracability,” Chipman says.

Niobrara wells may cost less, however, because the formation is at a shallower depth than Bakken and Eagle Ford and there are oilfield services in the area, while there are fewer services that are indigenous to the Bakken in western North Dakota and eastern Montana. A Niobrara well in the D-J Basin area may cost $3.5- to $5.5 million, drilled and completed, compared with $6- to $9 million in Eagle Ford and $7 to $12 million in Bakken.

Chipman adds that a Niobrara well in the more remote Powder River Basin may cost $7- to $9 million.

The D-J Basin also hosts other productive formations: three Niobrara chalk reservoirs, the Codell sandstone and the Fort Hays/Greenhorn limestones. “We expect these intervals will be tested for potential as stand-alone plays over the next few years.”

Yet, Niobrara wells in the D-J Basin may average a lower after-tax rate of return due to less recovery of hydrocarbons than being surfaced in Bakken and Eagle Ford. Using $60 to $100 oil and $4 to $6 gas, an average Niobrara well in the gassier Wattenberg Field area may return 10% to 45%-plus on the dollars invested, 15% to 60%-plus in oilier sweet spots outside Wattenberg and 0% to 15% in marginal areas outside Wattenberg.

 “These returns compare to 15% to 80%-plus in the Eagle Ford oil window and 15% to 200%-plus in the Bakken.” If the operator is able to tap a large, natural fracture system, the Niobrara return may improve significantly to between 100% and 200%-plus, she adds.

She and co-authors David Heikkinen and Brian Lively report, “It’s early days. We think the Niobrara now is where the Bakken was in 2005 as far as knowing which drilling and completion techniques work best and where the sweet spots and edges of the play are. A play in its infancy means more risk but potentially greater reward.”

They add that investors shouldn’t be turned off by that many Niobrara operators aren’t revealing much about their work in the play. “Many operators have kept public commentary close to the vest, so investors have formed a certain skepticism—a ‘no news means bad news’ view of the play. This lack of open discussion and resulting skepticism mean operators are lumped together with those we think are ‘doing the right things’ in the ‘better’ parts of the play undifferentiated from the rest.”

–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.

From folding card tables and lawn chairs for office furniture, Foster and team grew Newfield to 2 Tcfe proved.

“There’s ‘Joe time’ and there’s ordinary time,” former Newfield Exploration Co. board member Dale Zand tells Art Smith of Newfield founder and retired chairman Joe Foster in Smith’s new book, Something from Nothing: Joe B. Foster and the People Who Built Newfield Exploration Company.

“…Joe can see and understand a problem a hundred times faster than anyone else.”

Published this year, Smith explores how Foster led two dozen other former Tenneco Oil Co. professionals in the formation of Newfield in 1989 with a total of $9 million in employee and outside investments, growing the company to 2 trillion cubic feet equivalent of proved reserves upon his retirement in 2005.

Foster’s philosophy references Rudyard Kipling in “If:” “…If you can meet with Triumph and Disaster and treat those two impostors just the same…Yours is the Earth and everything that’s in it….”

Smith writes, “One of Foster’s strongest and most persistent characteristics as an oilman is his stoic acceptance of failures and setbacks. Success often follows failure and Foster has long viewed drilling dryholes as Babe Ruth did strikeouts. Like the Babe, Foster has no fear of setting ‘whiff’ records in the pursuit of home-run success. This anonymous quote is a favorite of Foster’s: ‘Failure is never fatal and success is never final.’”

Smith peppers the book with anecdotes and succinct descriptions, such as of Newfield’s early and ascetic days. For example, office furniture consisted of what employees, who were all owners, could put together, thus meetings were held at folding card tables complemented with an assortment of lawn chairs.

Spartan use of money was evident in a Wall Street Journal article in the early 1990s in which a Newfield platform in the Gulf was noted for its “kaleidoscope of colors.” The platform was made from components from other platforms and pieces were blue, red, yellow or gray.

Six-foot Foster and all Newfield employees flew coach class—even to Australia, a 26-hour flight. Investor-relations chief Steve Campbell, six foot four, joined Foster in coach on a flight to New York just two days after joining Newfield from Anadarko Petroleum Corp., which had a corporate jet. Upon landing at LaGuardia at almost midnight (Campbell tells Smith, “Joe likes to fly after business hours because it allowed you to get in a full day of work in the office.”), Foster told Campbell, “You know what I like about flying coach? It’s so damn uncomfortable you can get a lot of work done!”

And employees found cabs, not limos. During the company’s 1993 IPO road show, which involved meetings in Boston, New York, Chicago and on the West Coast (Foster says, “There sure is a lot more road than there is show in a road show.”), the Newfield team took cabs the first week. Bobby Tudor, a Goldman Sachs managing director at the time and now co-founder of Tudor, Pickering, Holt & Co. Securities Inc., was a co-manager of the IPO.

Smith writes, “The second week, (Tudor) said, ‘Look, Joe. We’re going to get limos and Goldman Sachs will pay for them…It’s not coming out of Newfield’s pocket.’ Tudor’s rationale was that arranging the logistics for all of them was just hell on the secretaries.”

And, about that IPO, Foster says he thought it might be too soon for Newfield, which had some 100 billion cubic feet equivalent of proved reserves at the time. Howard Newman, a managing director at the time of Warburg Pincus that was a second-round investor in Newfield and currently co-founder of Pine Brook Road Partners, emphasized that the IPO window was open at that time and it was unknown when it would be open again. Smith writes, “(Newman) passed on this gem of advice: ‘Joe, you take the cookies when the tray is passed—not just when you’re hungry.’”

In Foster’s hand-written notes (Foster carried a yellow legal pad to any meeting and made copious notes; longtime assistant and a founding Newfield employee Betty Smith says, “…We never ran out of them. That was one of my key jobs…to keep a good supply of yellow tablets.”) in early 1989 while forming Newfield, he lists what he will tell the troops two weeks into the effort. Among them: start-up pains are normal; Newfield will be data-driven; networking and exposure are essential but to take care that it isn’t taking more time than it is giving back; and “we must be prepared to live with failure.”

He concludes his list with this: “Finally, when we achieve success, we must not let it go to our heads.” Find Art Smith’s book here: Something from Nothing.

–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.

Dear Ian,

In reading your June 25 online report “Insiders Sound an Alarm Amid a Natural Gas Rush,” it is apparent that the story, with the application of sincerity and more thoughtfulness, would have been titled “Shale-Gas Well Decline-Rate Criticism Unfounded.” You were on the cusp of the real story and missed it; it appears that great effort went into missing it.

Instead of simply pushing readers’ Enron and dotcom buttons via highlighting these words from critics’ e-mails, your report would have explained that the critics’ comparison of these with the shale-gas investment phenomenon is unfounded: Shale gas is a real asset; the Enron, or gas-marketing, bubble and the dotcom bubble were burst upon a lack of fundamental business principle — that is, to operate profitably.

As free and transparent markets work, investors themselves — those trading in and those trading out — define the ultimate boundary of an asset’s value on a daily basis. That boundary is tested 24/7; at times, such as in the case of the dotcom phenomenon, the correction can be gross, yet the dotcom business did not end — it simply was righted, just as the automaker industry found its way in the past century from dozens to the few best and how the home-ownership industry pushed to an ultimate test in this past decade, and tens of thousands more U.S. citizens are now enfranchised with property rights.

And, then, in your report, there are the anonymous critics themselves: They are provided to substantiate a scientific premise, yet the individuals themselves are unsubstantiated and not real assets in your story modeling. In reviewing the pages of e-mails with identifiers — although the remnants of their protocols are easily recognizable by industry — marked out, their commentary is merely that of friendly banter, envy or wonder, when read by one who understands the science behind forecasting decline rates, evaluating demonstrated decline rates from surfaced resources and, then, modeling in rate-of-return economics upon which an investment decision is made.

Your report lacks what would be easily demonstrable, as decline rates are no secret — they are on the surface, literally — and, while sophisticated, consist of simple math. Had the anonymous critics been asked to demonstrate this to you, your report would have been titled “Shale-Gas Well Decline-Rate Criticism Unfounded.” The business of evaluating decline rates is not mysterious and it is not taken lightly by oil and gas producers and by the investment community. Knowledge of it is easily obtained.

And, why provide safe harbor of anonymity for these critics anyway? There is regular debate and diligent effort within the oil and gas industry — as it is a science- and, thus, math-based business — on best practices, from well placement to completion method to reinvesting returns. This debate is conducted internally within oil and gas companies on a daily basis and also in open sessions at professional-organization symposiums and even in oil and gas producers’ regular investor conference calls.

Why, then, does criticism of this have to be secreted with anonymity? Are the critics anonymous because identifying them would show your readers that they lack credentials in contrast with that of members of an industry of hundreds of thousands who drill wells and are accountable for their profitability?

The energy analyst John Olson signed his name to his early 2001 report that said something was amuck at Enron. Alan Greenspan publicly stated he believed there was irrational exuberance in public markets in 1996 and devotes a chapter to his reason for this in his autobiography. Yet, your sources cannot do the same — sign their name to their statements? And, yet, your report’s intent is to affect the value of hundreds of billions of dollars of public and private investment in U.S. shale-gas resources?

These are incongruous.

The market for shale-gas stories is regularly corrected as wells work out and wells don’t work out, and simultaneously by user-market appetite for the natural gas itself. In mid-2008, for example, natural gas prices began to fall, thus the value of both shale-gas and all other gas wells — and not due to any change in the wells’ performance, but upon the application of simple business math, that is X$=X$ and X$-50%=0.50/X$.

In fact, shale-gas stories are out of favor in the short-term-investment marketplace today — not for poor well performance but because of the low price of the product the shales are making so well and, thus, is a contrarian investment opportunity for longer-term investors, who understand decline rates and that there will be gas — and years from now.

Alas, those who seek unsubstantiated journalism get unsubstantiated journalism. Your report suggests “sell your gas holdings now,” while the smart money is buying in.

It’s unfortunate you have burned your very own readers too.

–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.

Having spent most of my professional career writing about energy issues, I understand and appreciate the power of the pen. Writing persuasively and interestingly can make a difference. In a world where the news cycle is 24/7 and people are swamped with information, anecdotes are king. The Times article wields cherry‐picked anecdotes like a samurai with a sword.

One snippet is as follows: “Money is pouring in” from investors even though shale gas is “inherently unprofitable”, an analyst from PNC Wealth Management, an investment company, wrote to a contractor in a February email. “Reminds you of dot‐coms.” End of snippet. Wow. That is good stuff. Captivating. Entertaining. But is it the truth? Or is it an opinion? I’m not sure that PNC actually has any dedicated energy analysts (I couldn’t find any on their website). So perhaps that cool quote came from a high net worth broker? Maybe he/she is a genius with reams of analysis on shale gas decline. Or maybe the observations are based on reading blogs and internet postings. One can’t tell from the anecdote. Which should I trust more? – the February 2011 $4.7+ billion purchase of Fayetteville shale gas assets by BHP Billiton or the February 2011 anecdotes from an unnamed broker of unknown quality?

Follow the money is usually a good credo.

The New York Times also captured the eye‐opening and alarming comments of Deborah Rogers, a member of the advisory committee of the Federal Reserve Bank of Dallas. Her research indicated Barnett shale wells were declining faster than expected. Fascinating. A Dallas Fed adviser has spotted an important issue. But is it the truth? Or is it an opinion? Would I be just as fascinated if the article quoted Deborah Rogers, proprietor of Deborah’s Farmstead, a small Fort Worth family dairy that produces goat cheese? That’s her bio from the 2008 Dallas Fed press release. Maybe Ms. Rogers is a closet petroleum engineer and excellent decline curve analyst. Maybe not. But 2011 Barnett shale gas production is at higher levels than 2009, with rigcount down by two thirds. That is not an anecdote seized by a newspaper reporter, it is a wellhead fact.

The Times article does make one statement that is dead on. The article says “these companies have been making predictions based on limited data and a certain amount of guesswork, since shale is a relatively new practice.” Indeed, natural gas comes from reservoirs 1‐4 miles deep in the earth. It seeps out through pore spaces so tiny they can’t be viewed with the naked eye. As such, almost everything about shale gas is an estimate. It is only natural that individuals inside and outside the industry are skeptical, curious, questioning and uncertain – as the anecdotes in their emails prove. The debate is healthy. Early estimates about various shale plays were too conservative in some instances and too aggressive in others. The Western Barnett turned out disappointing. The Marcellus is better than people initially thought. That isn’t fraud or deception, it’s the oilpatch.

It is this author’s opinion that recovery per well in gas shales will be closer to industry forecasts than the dire predictions of gas shale skeptics. But we can’t know for sure. Real money is made BEFORE estimates turn into facts. Just like the stock market.

Gas shale drilling has been wildly successful – just look at the quadrupling of U.S. shale gas production in the past 5 years. Right now, this is the same hollow success of long‐distance telephone carriers – volumes way up, prices way down. Even as oil prices returned to triple digits, an oversupply of gas has cratered gas prices. I believe that most new drilling for shale gas is uneconomic or marginally economic at current $4‐$4.50/mcf prices. So does the industry! The gassy Haynesville shale rigcount is down by ~30% from the peak. It will fall further during 2011 and 2012 as leasehold drilling requirements are fulfilled. Cheap prices, falling gas‐focused drilling, a recovering economy, eventual LNG exports ‐ this is why industry executives are getting more bullish on the gas macro. However, even with optimism growing, most E&P companies are still hedging 2012 gas production at $5/mcf and/or selling down gas properties to fund oil drilling. Midstream companies are building gas pipelines like crazy. Several new LNG export projects are under way. These actions by a myriad of companies, hundreds of executives and thousands of employees indicate the industry believes in both the short‐term and long‐term viability of shales. They are speaking with their capital budgets, their bonus pool, their acquisition budgets…not with their keyboards and chatroom postings. If there is any conspiracy or hidden agenda, it’s amongst those writing articles, not drilling gas shale.

For the record, our alternative investment strategies have essentially no directional investment in gas shale producers. As an investment thesis, I believe US natural gas is trapped in limbo between yesterday’s news and a recovery story. Oil is the hot ticket and I’ll be writing about the recent SPR news over the next day or two. If you have any questions, don’t hesitate to call or write.

Respectfully Yours,
Dan Pickering
Chief Energy Strategist

Also, check out additional feedback from Chesapeake’s CEO, Aubrey McClendon.

When talking Marcellus, Eagle Ford, Granite Wash and other gas-liquids-rich plays, here’s a guide to the NGLs producers and end-users are talking about.

Increasingly, U.S. oil and gas producers are growing their weighting to surfacing liquids—crude oil but natural gas liquids (NGLs) too. In the mix of NGLs are higher-value gases—higher value in that they fetch more per Btu (or energy) content than dry gas, which is methane. NGLs are priced based on a percentage of crude oil.

Ethane, for example, has received 46% the Nymex price of West Texas Intermediate (WTI) crude oil in the past two years, on a Btu basis, according to Robert Mackenzie, managing director, energy and natural resources, for FBR Capital Markets. Methane? Only some 9%.

Thus, the NGLs- and oil-rich rush.

Here’s an “NGLs 411” as reference as producers of wet gas from Midcontinent, Eagle Ford, Marcellus and other wells discuss them in quarterly conference calls. According to Mackenzie, a “liquids-rich” well may make gas condensate, NGLs or oil. Some may make dry gas too, which is methane and which is what is traded on Nymex. Methane is known as C1 for its single carbon atom.

–Condensate (C10+). Mackenzie says, “This condensate is comprised of higher-order hydrocarbons (C10+) that assume a liquid state at surface temperature and pressure. Its pricing is fundamentally equivalent to WTI crude oil, and it has many of the same end markets. It is a high-quality feedstock for the petrochemical industry, but it is most commonly refined into various types of fuel.”

–NGLs (C2-C5+). “’Natural gas liquid’ refers to the components, other than condensates and dry gas, that are refined out of the gas stream at a processing plant before the gas is sent to market.” Among the NGLs, Mackenzie says, are:

            –Natural gasoline (C5+). “Natural gasoline is the heaviest segment of the non-condensate liquids, but it is still extremely light relative to crude. Natural gasoline is the collection of hydrocarbons that remain once the lighter segments of the stream are collected. The typical gravity of natural gasoline is around 80 degrees API, and its boiling point is in the same range as that of commercial gasoline. It is frequently used as a fuel additive, as well as a petrochemical feedstock. When viewed on a Btu basis, natural gasoline typically receives a price premium to WTI crude.”

            –Butane (C4). “Butane enjoys robust demand, with varied end markets and pricing per Btu very similar to WTI crude. Butane has industrial and residential heating applications and is frequently blended with propane to produce liquid petroleum gas (LPG). For simplicity’s sake…N-butane and isobutane (may be regarded as) butane…, a blend of the two.”

              –Propane (C3). “Propane use is predominantly split between heating and petrochemical applications, but it is also used as a fuel for certain types of vehicles. Demand is seasonal and subject to weather.”

               –Ethane (C2). “Ethane has the most inherent pricing risk among the NGLs. Demand for pure ethane is driven by the ethylene-production industry, which utilizes the gas to meet 38% to 51% of its feedstock need. If insufficient demand for ethane exists in the ethylene-cracking value chain, a refiner has the option to reject a certain amount—and regulations vary by region—of excess ethane. Upon rejection, the ethane is simply left in the gas stream and sold to customers as extra-Btu natural gas.”

Mackenzie and the research team at FBR Capital Markets estimates that new NGLs-rich production across the U.S. will make more than 200,000 extra barrels a day of ethane by next year.

“Ethane only has one true end market, which is growth-constrained in the short term due to the time and capital required to bring new refining capacity online. Most additional midstream capacity is not slated to come online until mid-2012 or in 2013, and this is a particular problem in the Marcellus (wet-gas window) due to the lack of ethane-processing capacity in the region.

“Many believe that U.S. fractionation plants are operating nearly at full capacity, and there are concerns that the refining infrastructure will not be able to accommodate the more ethane-intensive stream that is likely to be produced as a result of (producers’) rush to liquids. Only a limited amount of ethane can be legally rejected by the refiner, because if excessive quantities are transmitted via pipeline it can damage the infrastructure and cause safety hazards. This could limit the efficacy of the natural gas price as a lower bound on ethane prices.

“For the other NGLs, the petrochemical sector acts as a price stabilizer. For example, if propane is in oversupply, its price will fall and it will temporarily displace other hydrocarbons as a petrochemical feedstock. Because ethane already holds the position of petrochemical feed of choice, it lacks this price control.”

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

Obama has no real, sincere interest in a better American energy future, defense, economy and job security.

The list of incompatible messages from the Obama administration continues into 2011, with the next even more daft than the former. In 2010, it was a moratorium on drilling in the Gulf of Mexico, suspending, and even ending, some American jobs in one of the few regions of the U.S. where hiring and economies remained relatively robust. This was in the midst of regular talk from D.C. about its struggle with and determination to create American jobs.

So far in 2011, there is Obama’s idea of fighting high gas-pump prices by releasing oil from the Strategic Petroleum Reserve, which was created for American defense purposes and not for White House re-election defense purposes. Besides that, the problem with the $4-plus gas-pump price in May wasn’t even due directly to the high price of crude oil, which was some $114 at the time.

In fact, for example, crude oil was $148 a barrel in July 2008, and the national average pump price peaked at $4.11 briefly. Clearly, there would be another circumstance involved in a $4 pump price at both $148 oil and $114 oil.

There was—and is—but that message wasn’t delivered to Americans by the White House. It is that the pump-price run-up has been due to a confluence of circumstances: refineries that were offline for regular, spring-season maintenance that precedes the heavier summer-demand season and refineries offline for technical reasons. It had very little to do with the actual supply of oil in the U.S.

Tudor, Pickering, Holt & Co. analysts noted recently that Obama’s talk of releasing oil from the SPR “is a political ‘Hail Mary’ when there is no apparent relief from high oil and gasoline prices. Maybe Energy Secretary Chu—the Nobel Prize winner—should remind the president (also a Nobel Prize winner) that U.S. oil inventories are at record levels and well above normal—that is, plus 13%—so, we’re not sure who will buy the oil or where they will store it.”

In short, U.S. oil-storage capacity is full. Where would Obama put it, except back into the SPR? “In the meantime,” the TPH analysts added, “someone in the administration should run an energy policy post-route. The clock is running with no time outs left.”

Also this spring, Obama offered the idea of increasing taxes on oil-producing companies as a means of reducing energy costs. That is to say that increasing the cost of making a product will result in lowering its cost to the consumer. His idea—which was swiftly defeated by the U.S. Senate after major oil-company executives had to go to Washington to explain this incongruity—was to use the additional tax revenue to fund research into alternative energy, something the U.S. government has funded for decades with little to show for it, while oil prices keep climbing, thus pump prices.

Meanwhile, an alternative-energy idea the government has not seriously funded during the past 40 years of net—and growing—reliance on imported oil is use of natural gas as a transportation fuel.

And in another underwhelming White House response to pump prices this spring, Obama has called for an investigation into U.S. oil-market fraud, without noting that the continued weak U.S. dollar—some 70% the value of the Euro—is largely responsible for the high price of oil, which is traded worldwide in U.S. dollars.

Which brings this back to jobs and to the economy. In all the blame-deflecting speak from the White House this spring, Obama has obfuscated the fact that its energy-related efforts to date have consisted at net of trying to kill the solution—instead of killing the problem. The message is “Kill American oil producers. Kill American oil-industry jobs. And, ignore the job-creating, economy-boosting, American defense-boosting opportunity of using natural gas as a transportation fuel.”

That message was also delivered this spring and is the most revealing from the White House about Obama’s true lack of feelings about improving America’s profile of dependence on imported energy. In May, the Department of Energy approved exporting U.S. natural gas, which is now prolific due to producers’ pioneering work on some of the most complicated gas formations in the country.

But, what could Obama say? No? If no, then what? What to do then with all this abundant, indigenous, clean, super-fuel—a new methane-rich situation that is the envy of energy-dependent countries worldwide? While the decision to allow export is pro-free-markets and is best for gas producers, it says that Obama has no real, sincere interest in a better American energy future, defense, economy and job security.

One U.S. gas producer says, “The administration says a lot of stuff with words that it doesn’t follow through on with real actions. Look at the Gulf of Mexico and the moratorium. The president talks about supporting the use of more natural gas and reducing energy imports, but if you look at his actions, you’ll see we have energy policy that has been more adversarial than supportive.”

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

Questioning the shale plays has become a good sport this summer. Critics say the plays are not economic, that the E&P industry is merely churning through cash flow to hold leases, with profitability a distant dream.

Others say the supply projections are over-hyped and that there is no way the U.S. has 100 years’ worth of natural gas supply, as the industry so proudly proclaims.

Still others say hydraulic fracturing does indeed harm groundwater and/or the aquifers below. Or, they claim the equipment associated with production and transportation emits far too many air-polluting substances.

Cornell University says, in a recent study, that natural gas may emit more air pollutants than coal, once you factor in every slice of the production chain from exploration to fracking, including service trucks going to and fro, to gas processing facilities.

Two hearings the week of June 3 were held on Capitol Hill, to figure out how to improve the safety and environmental performance of fracturing in shales. IPAA reports “disclosure was the main focus…as CEOs from numerous companies called for more disclosure at the state, not federal, level. ‘Our company is very much supportive of full transparency,’ said Jack Williams, president of ExxonMobil subsidiary XTO Energy.”

Williams, Texas Railroad Commissioner Elizabeth Ames Jones, and others, say the states can regulate fracturing and its disclosure, and they already set industry standards, because each state has its own set of issues and geology–a one-size-fits-all approach is not scientifically reasonable.

The industry has already responded to the groundswell of critics. It developed Fracfocus.org, where companies now voluntarily post their frac fluid data.

In February, API completed a series of documents specific to hydraulic fracturing. They provide the blueprint for the environmentally sound development of natural gas through the publication of a five-document series. The series is publicly available at the API website, and it has also been shared with the Department of Energy.

In May the Texas legislature voted to require mandatory frac fluid disclosure beginning in 2013. Gov. Rick Perry is to sign it soon. Montana is looking at voluntary disclosure.

Is the bloom coming off the shale-gale rose? Would you like to conduct a study of gas shales and fracturing? Why not? Everyone else is. Perhaps we could organize a contest: we’ll give awards (a lump of coal?) to those studies that come out the soonest, which have the most pages, and are most full of erroneous assumptions, bias and miscalculation.

Cornell and Duke universities have recently released studies about the effects of shale drilling on water quality and air emissions. The Post Carbon Institute has (you can easily guess which side of the argument it’s on). The EPA, the DOE and the University of Texas are each conducting studies on hydraulic fracking as we speak.

UT’s Chip Grote announced the university will undertake a new science-based study to help refute the growing noise by stating the facts, all along the supply chain..

Geoscientist and Post Carbon Institute Fellow J. David Hughes argues that the gas industry “has propagated dangerously false claims about natural gas production supply, cost and environmental impact. (His boldface, not mine.) His full report, “Will Natural Gas Fuel America in the 21^st Century?” is available at the Institute’s website.

Hughes says, “The most significant of the natural gas industry’s claims– one that has been bought hook, line and sinker by everyone from the Energy Information Agency (EIA) and the Obama Administration, to leading environmental groups–is that the United States has a 100-year supply of cheap natural gas. The report shows this to be a pipe dream.”

The Institute claims natural gas supply would require higher costs and unprecedented drilling pace to meet even baseline supply projections made by the proponents of shale gas. “In fact,” it says, “the U.S. faces a decline in domestic gas supplies in the very near future unless drilling rates quickly increase.”

Also debunked is the perception that shale gas is better for the climate than coal, because it emits fewer pollutants. “Building on other recent analysis, the report shows that shale gas is worse than coal over a 20-30 year timeframe, even after efforts to mitigate fugitive methane emissions. This should have major implications for those who have touted natural gas as a near-term bridge to a clean energy future.”

Hughes claims the shale gas industry is motivated to hype production from shales in order to attract large amounts of investment capital; “it did this by drilling the best sites first and extrapolating initial robust results to apply to more problematic prospective regions.” He says the energy-policy establishment, desperate to identify a new energy source to support future U.S. economic growth, accepted the industry’s hype uncritically. This in turn led The Wall Street Journal, Time, 60 Minutes, and other media outlets to proclaim that shale gas would transform the energy world.

Finally, he says, “several prominent environmental organizations, looking for a way to lobby for lower carbon emissions without calling for energy cutbacks, embraced shale gas as a necessary ‘bridge fuel’ toward a renewable energy future.”

So, upon reading this, are energy policy-makers and end-users to conclude that after all, we should use more coal—or only coal?

Just wanted you to be aware of what the industry is up against!

Some 100 million gallons of gasoline are made a day by refineries along the Mississippi River.

Gasoline for June delivery recovered on Monday nearly all of its 30-cent loss of last week, driven in part by speculation of supply disruption from refineries along the lower Mississippi River. The contract closed in trading this afternoon at some $3.30 per gallon, up from a morning open of $3.09 and resuming its Wednesday morning profile.

The contract for June delivery of crude oil rebounded to some $103 on Monday from less than $98 on Friday. The price remains shy of the $114 it reached last Monday and the more than $140 it peaked at in mid-2008.

Andy Lipow, president of Houston-based, energy-consulting firm Lipow Oil Associates LLC, tells Bloomberg today that the threat of refinery flooding along the lower Mississippi—as seen after Hurricane Katrina’s storm surge spilled over the river’s banks—is unlikely from this lock-and-levee-controlled and highly anticipated flood.

Instead, disruption to oil-tanker traffic along the river due to swiftness of current is possible. In trading crude oil and refined products, “the bias is to the upside,” he said this morning. (Watch the video of Bloomberg’s interview with Lipow.)

There are 11 oil refineries along the river, making some 2.5 million barrels of gasoline a day or 13% of U.S. daily supply, according to Lipow. (For more data, see the U.S. EIA’s fact sheet.)

Flood waters, projected to approach or exceed historical records, are pushing south from the April rain-soaked upper Mississippi (nearly 500% above-average precipitation for the year) and Ohio (nearly 400%) rivers’ regions. Memphis was to see the crest today.

The river at Baton Rouge, Louisiana, where ExxonMobil has a large, legacy oil-refining plant is already at more than 40 feet; flood stage is 35 feet. At 43 feet, “shipping and industrial activities are significantly affected,” reports the National Weather Service.

The water is to reach 44 feet on Friday morning and crest at 47.5 feet on May 22, assuming the opening of the Bonnet Carre flood-control structure downriver but not the Morganza structure upriver.

The record crest is 47.28 feet, set in the spring flood of 1927 that was also exacerbated by excessive rainfall except along the entire southern half. Currently, Louisiana and Mississippi are in the midst of a drought, thus additional water due to rainfall is not expected in the coming weeks.

Farther south, at Donaldsonville, Louisiana, near yet more oil-refining and petrochemical plants, the water was at 30 feet today; flood stage is 27 feet. At 34 feet, “river-barge traffic becomes dangerous, particularly when navigating sharp turns on this stretch of the river,” the NWS’ Advanced Hydrologic Prediction Services reports.

At 38 feet, the river spills over its banks into neighboring communities, and river traffic would be stopped. It is expected to crest at 36 feet on May 22, again assuming the opening of Bonnet Carre downriver but not Morganza upriver.

At New Orleans, the river is expected to exceed flood stage (17 feet) tomorrow and crest at about 19.5 feet the morning of May 23, again if Bonnet Carre but not Morganza. At only 17 feet, “the river will rise on the levee, making navigation and docking difficult,” the NWS reports. It also notes that New Orleans is protected by the Mississippi River levee at up to only 20 feet. (For more in-depth NWS data on river water stages, see the interactive website.)

Thomson Reuters reports in its daily energy-commentary round-up:

–“Murphy Oil Corp. said Friday it did not expect any effects on operations at its 125,000-barrel-per-day refinery in Meraux, Louisiana, due to the rising Mississippi River.” (May 6, 2011)

–“Marathon Oil Corp. said on Wednesday it was closely monitoring the flooding situation along the Mississippi River to determine if any special preparations were required at its 436,000-barrel-per-day refinery in Garyville, Louisiana.” (May 5, 2011)

–“Valero Energy Corp. said it expects no disruptions to production at its Memphis or St. Charles refineries from the flood situation along the Mississippi River.” (May 5, 2011)

The Bonnet Carre Spillway north of New Orleans—built by the U.S. Army Corps of Engineers since the most tragic Mississippi River flood in modern history in 1927—was to begin to be opened today to relieve pressure on river levees south of Lake Ponchartrain, spilling excess water into the lake, which drains into the Gulf of Mexico east of New Orleans.

The Morganza Spillway–farther upriver, north of Baton Rouge, and also built since 1927 as part of an intricate Corps locks-and-levees flood-management system—is to begin to be opened on Thursday, sending excess river water into the Atchafalaya Basin and eventually into the Gulf via the Atchafalaya River west of New Orleans.

Yet, neither assures the river’s current along America’s “refinery row” will be at a ship-manageable level. Lipow points out in the Bloomberg interview that the river has many sharps turns in its path.

The $3.30 close today of the June contract for gasoline is shy of the May 2 peak of $3.40. The contract has been traded since mid-2008 and opened then at roughly the current price, while crude oil was trading at the time at more than $140 a barrel.

The contract fell to as low as some $1.55 in early 2009, while oil fell to below $40 a barrel.

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

The pioneer of the world’s shale plays discusses the future of energy development in this exclusive interview with Hart Energy, celebrating the 30th anniversary of his Barnett play opener.

George Mitchell’s advice to oil and gas explorationists? “Be bold.”

The founder of America’s—and now the world’s—unconventional oil and gas plays says the late, legendary explorer Michel Halbouty would rib him decades ago, telling him, “Come on. Explore. Do something.”

Upon discovering how to extract natural gas resources from the Barnett shale after a first well, C.W. Slay No. 1 in Newark East Field, 30 years ago, and hundreds more thereafter, he told Halbouty, “Mike, I found this field because of you.”

He quips in this exclusive interview with Hart Energy for a video tribute that celebrates the 30th anniversary of C.W. Slay, the Barnett play opener, “I’ve been busy now for 60 years, drilling wells all over the country, and now I’ve done something important.”

(Editor’s Note: The 30th anniversary of America’s shale plays will be celebrated at Hart Energy’s sixth annual Developing Unconventional Gas (DUG) conference April 18-20 in Fort Worth with more than 2,000 attendees and a keynote address by President George W. Bush. For conference details and to register, click DUGConference.com.)

The application Mitchell pioneered of horizontal drilling and multi-stage fracturing into the low-permeability, low-porosity shale has re-invented the U.S. natural gas profile. The U.S. led in 2009 for a third consecutive year in percentage increase in gas production, posting 3.5% more than in 2008, according to the annual BP Statistical Review of World Energy published in June 2010.

It has surpassed Russia as the world’s most prolific gas producer.

And, the application of the technology into U.S. oil plays now contributed to the U.S. also posting the largest increase in oil production in 2009. “(Daily) U.S. production increased by 460,000 barrels, or 7%—the largest increase in the world last year and the largest U.S. percentage increase in our data set,” the BP Plc analysts report. That data set is of 59 years of world production history.

Mitchell says America could readily use the additional oil that is being produced from horizontal and multi-frac plays. “We have to get more oily and you’ll see a lot of the industry trying to make more oil out of plays…If we have the same information on oil plays right now that we have on the gas plays, we would solve a lot of our oil problems…There’s a lot of work that’s still to be done.”

For more highlights from the exclusive interview with George Mitchell, see this article at OilandGasInvestor.com.

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

M&A advisor cites 2011 E&P transaction themes, market changes to watch.

Strong demand for oil-weighted assets will continue in 2011, particularly in the oil window of the Eagle Ford in South Texas and in the vertical Wolfberry, a multi-zone Wolfcamp and Spraberry play, in the Permian Basin.

But, will the wells flow into transaction data rooms? “Will oil prices above $100 a barrel create a chill in the acquisition market?” asks Chris Simon, managing director and head of A&D for Raymond James & Associates Inc.

That question remains to be answered, but other 2011 M&A themes are on the surface, he told members of ADAM Houston, an organization of E&P M&A professionals.

–Joint ventures will continue, he says, in U.S. unconventional-resource plays, driven by foreign E&Ps wanting access to reserves, technology and expertise. He expects many more JVs will be announced in coming months.

–Upstream MLPs will continue to be aggressive in data rooms for producing properties and the number of MLPs competing for packages will multiply, as long as they continue to have ready access to capital. “There will be a few IPOs of new MLPs this year. This is largely due to the demand for yield by investors.”

–Likewise, more U.S. royalty trusts may be formed this year to create capital to drill resource plays, while distribution-seeking, public-equity investors remain ravenous for income-producing investments, he adds. “Like the MLP, the U.S. royalty trust is a yield product.”

Market changes to watch include a continued depressed gas-price strip, which may force some E&Ps to let loose of non-core assets to provide income to continue to work core properties. Whole companies may be sold, he adds. The first to fall is Appalachian gas-focused NGas Resources Inc., which is to be purchased by Magnum Hunter Resources Corp.

He also warns that February U.S. gas-supply data may be misleadingly bullish. Much of the gas-producing U.S. was frozen in early February, and frozen gas lines shut in some production. (On the demand side, a fifth of Texas’ electric-power plants were shut in the first few days of February due to frozen gas lines, resulting in controversial rolling blackouts throughout the state while temperatures fell into the teens.)

Simon estimates as much as 5 billion cubic feet of gas was shut in due to freeze offs each of the days.

“The bigger issue going forward is that liquids-rich gas freezes faster than dry gas,” he adds. “This has the potential to provide ‘head fakes’ in supply data.”

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

The world of executive compensation is struggling to find its balance.  Over the last twenty years CEO compensation has tracked closely the growth in the economy, making the administration of executive pay relatively easy.  But with the dramatic reversal of markets and high unemployment, executive compensation faces pressures from outside influences that make the job of administering executive pay very challenging. The volatility of the market is forcing general industry companies to deal with the same issues the energy industry has dealt with for decades – there’s no one right answer to successful executive pay programs.  Today, the regulators and critics of executive compensation are influencing boards to administer executive pay programs in ways that fit with the latest definition of “best practices.”   Although the current emphasis is on increased regulation, it is essential to remember that the job of administrators is not to conform to the generic definition of a good program, but to oversee pay plans that actually work!  Over the years, I have observed that a well balanced approach to executive pay will pay great dividends to shareholders, and relieve some of the anxiety of outside directors carrying out their role.

The following are some basic principles that directors should consider as they navigate the changing environment of public company compensation committee membership:

It’s okay to be different. First and foremost, being different may actually be better than conformity in terms of encouraging optimum performance at the executive level. Empirical and experiential evidence suggests that one of the hallmarks of high performing companies is that they often do things differently.  They may get second guessed by academics, but this does not deter them. Not all effective executive compensation plans are configured alike.

Not all “best practices” are best. Journalists and critics are not the de facto arbiters of best practices for executive pay. It is not effective to assume that what others cite as best practices are in fact the wisest course of action for every situation. In addition, most public companies in the United States are not in the Fortune 50 and the rules and best practices for the largest companies are not universally applicable.  Last, many critics mistakenly think that pay practices from other countries should be adopted in the US, without considering the risk/reward implications.

Look for the “business case” in executive pay decisions. In today’s dynamic business climate, the momentum of best practices continues to move many companies away from certain pay practices just because it is the popular thing to do.  In the case of golden parachute agreements, for example, shareholders may not be best served by categorically eliminating such arrangements.  The merger and acquisition environment, the makeup of the executive team, and the nuances of the tax laws all have significant impact on the value proposition facing the company. These issues should be carefully studied in light of the business case before decisions are made.  The energy industry has long been a fertile field for mergers and acquisitions.

Discretion is the better part of valor. Don’t be afraid of discretion in managing executive pay plans.  Volatile markets make goal setting very difficult, which can dim the motivational effectiveness of incentive plans. The use of discretion however remains a very challenging process. Amidst pressure from both sides – upwards pressure from management and downward pressure from board of directors — compensation measurement and assessment is ever-evolving and goal setting is increasingly difficult. This pressure from both sides makes “soft issues” such as strategy, HS&E, organization development and other non-financial performance more important than ever. Directors of energy companies have known for a long-time that the exercise of discretion is key to maintaining motivational value of plans.

Not all risk is bad. Taking risks is a basic premise of being in business and most traditional pay plans are set up to balance risk.  Boards cannot take the risk out of executive compensation plans and expect a company to perform at a high level.  When viewed as a whole, the regulation and external pressure on executive pay is aimed at one thing – reducing risk.  This doesn’t mean that we should take mindless risk, but if we eliminate the risk from our pay plans, we shouldn’t expect superior returns.

Understand the purpose of the elements of pay. Everyone involved should understand the basic role of the various elements of the executive pay plans and administer each plan according to its design intention. For example, annual bonus plans typically reward for short-term strategic and financial accomplishment while long-term incentive plans reward for creation of shareholder value (e.g., TSR).  While the two should be closely related, administrators should understand the differences as they make decisions about results.  Too many outside observers don’t know the difference.

Advance planning promotes optimum results. Upfront work on establishing the company’s compensation philosophy, strategy, and guiding principles goes a long way towards ensuring the effectiveness of administration and program effectiveness.  These efforts help keep us on track as we walk the minefield.

Pay supports business culture. Executive pay is an important tool for the CEO in managing the business and supporting the corporate culture. Over time, we have felt the pressure to make it an academic exercise that is separated from the leadership of the organization, and more focused on compliance. This has led to dissatisfaction on several levels and continued debate that is often not productive.

Good people are good. Bad people are bad. Executives are not subject to the laws of cause and effect, and pay should not be viewed as a means to force certain behavior.  Good people will still behave admirably and bad people poorly, despite the pay plans.  The role of a director is to know the company’s people. It goes without saying that some compensation arrangements can lead to unintended results; the point is that the majority of arrangements in the market are well thought out and reasonable, and applied to reasonable and ethical people.

Constituent education is key. Shareholders and other constituents must be educated about the company’s compensation practices and supporting rationale in a clear and consistent manner. This will go a long way in developing the confidence of shareholders as it relates to executive compensation practices.

It’s okay to say no. Directors are under tremendous pressure to comply with expectations for executive compensation arrangements.  It’s okay to say no to payouts, pay increases, and other compensation arrangements if it makes sense and is consistent with the company’s compensation philosophy.  Many directors feel tremendous pressure to do what management expects them to do, but when directors are sensitive to external constituent interests, it may be prudent to say no.

Finding the balance in this time of transition will help ensure effective and meaningful executive pay plans for both the participants and the shareholders. The US based major oil companies are good examples of cyclical, businesses with long-term investment decisions where executive pay programs reflect this balance. These programs demonstrate well-conceived use of the elements of pay, support of their unique culture, and prudent use of discretion.  General industry companies may soon figure out what these energy companies learned years ago.

* * * * * * * * * *

Steve Cross is Managing Partner of Cogent Compensation Partners, headquartered in Houston, Texas. He has over 20 years of experience providing executive compensation advisory services to some of the world’s leading companies.

]]> http://blogs.oilandgasinvestor.com/blog/2011/03/23/finding-balance-in-the-executive-compensation-process/feed/ http://blogs.oilandgasinvestor.com/blog/2011/03/16/mcclendon-equity-markets-are-getting-chesapeake%e2%80%99s-upside-%e2%80%98for-free%e2%80%99/ http://blogs.oilandgasinvestor.com/blog/2011/03/16/mcclendon-equity-markets-are-getting-chesapeake%e2%80%99s-upside-%e2%80%98for-free%e2%80%99/#comments Wed, 16 Mar 2011 21:57:32 +0000 Nissa Darbonne http://blogs.oilandgasinvestor.com/?p=1880  

Chesapeake Energy Corp. is worth twice what Wall Street has built into its stock price, says Aubrey McClendon, Chesapeake co-founder, chairman and chief executive. Just do the math, he told analysts in a recent earnings conference call.

It goes this way:

The reserve value implied by BHP Billiton Petroleum’s planned $4.75-billion cash purchase of Chesapeake’s Fayetteville shale package involves 10% of Chesapeake’s PV-10 proved reserves as of year-end 2010. Using this, the value of Chesapeake’s remaining proved reserves is at least $40 billion, McClendon says.

“That means that all of our unproved resources—that’s 175 Tcf of natural gas and 15 billion barrels of liquids—are valued at absolutely zero at today’s Chesapeake market valuation,” he says. “Where else, but at Chesapeake can you acquire resources of this size and quality for free?

“(These are) world-class resources, such as in the Marcellus, Haynesville, Bossier, Barnett, Eagle Ford, Niobrara, Cleveland, Tonkawa, Granite Wash, Mississippian, Avalon, Wolfcamp, Bone Spring and Wolfberry plays—to name just the most well-known of our plays with huge amounts of unrecognized upside.”

McClendon estimates Chesapeake’s unproved reserves are worth some $40 billion. The company also has $6 billion of non-E&P (midstream and oilfield-service) assets, and $4 billion of drilling carries.

“Added all up, I think you can easily confirm asset values of more than $80 billion for Chesapeake.”

He adds that Chesapeake will generate $10- to $11 billion of EBITDA in 2015, based on accelerated developmental drilling of liquids-rich plays.

“If we are able to do so, then we should be able to increase our enterprise value to a range of $70- to $80 billion versus our current enterprise value of about half that. We have the strategy, the land, the science, the people and the capital to achieve this goal and I believe we will achieve it.”

For example, he says, Chesapeake doubled its oil production in one year—from 30,000 barrels per day in the fourth of quarter 2009 to 60,000 in the past quarter. It grew reserves by 5.1 trillion cubic feet equivalent at a cost of $1.07 per thousand equivalent in 2010.

“That means that, in just one year and just through the drillbit, we found more reserves than any of these highly regarded companies have built up in their entire history: Range (Resources Corp.), Ultra (Petroleum Corp.), Southwestern (Energy Co.), Newfield (Exploration Co.) and Petrohawk (Energy Corp.), to name a few.”

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

Note: Quotes from this conference call are from SeekingAlpha.com’s file of transcripts. For the entire transcript, see www.SeekingAlpha.com.

Shale-gas joint ventures have kept the U.S. natural gas industry drilling the millions of acres they leased and need to hold by production in the wake of the financial turmoil of second-half 2008 and increasingly lower gas prices.

That’s the good news.

The challenge: These JVs have kept the U.S. gas industry drilling.

This dichotomy is apparent in U.S. gas prices.

“I don’t know if I’d say the U.S. gas industry would have been crushed by the events of the second half of 2008. But, it’s been good and bad,” says an executive with an Appalachia-focused E&P.

“A lot of these JVs were great for the (acreage-owning) companies doing them, and I certainly did some of that too,” he notes. He arranged JVs with producers who wanted entry to Marcellus gas acreage—and knowledge—and was late to the play, buying into it via JVs later.

“It allows you to keep drilling and to hold the acreage that all of us had spent hundreds of millions of dollars putting together. The drawback is that the rig count has not dropped and capital is not reallocated in the way it would have been in an efficient market because all this foreign capital continues to invest in onshore U.S. shale plays.

“So, it’s good and it’s bad. It’s definitely sustained a lot of companies and allowed them to clean up their balance sheets but, for commodity prices, it’s certainly been bad because it has promoted inefficient use of capital for a longer period of time.”

The plethora of gas JVs is not yet exhausted, he forecasts. He’s seen the number of interested parties in data rooms. “I think there are still a lot of very resource-rich companies out there and still a lot of foreign-capital interest in onshore shale plays, so I think it’s a trend that will probably continue for a long time.”

Because of the drilling carries that JVs bring, making them economic despite the traditional business paradigm, U.S. gas prices will continue to range between $4 and $6 per million Btu, he adds.

“I don’t think natural gas can stay below $4 for an extended period of time because, when you add up the true F&D (finding and development) costs, it isn’t very profitable to drill at $4 gas, so if we get below that, it would be for a relatively short time period,” he says. Rigs would be laid down, thus less production would come online.

“But, I don’t believe we’re going to see gas over $6 any time soon if the gas-targeted rig count declines as shale-gas acreage becomes held by production and/or rigs move to drilling for oil. That hopefully self-corrects some of the gas oversupply. But as gas prices start to move back up to $6, I would expect the rigs would move right back into the gas shales.

“So, my opinion is that we are in a $4 to $6 trading range for natural gas for quite some time.”

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

The Academy Awards’ documentary category has become increasingly political in the past decade, and also increasingly open to controversy. It started in 1999 when “One Day In September,” a very interesting docu-drama that showed a combination of actual footage and reenactments of the events leading up to and following the Munich Massacre in 1972. Narrated by Michael Douglas, the film plays out in a suspenseful manner like a political thriller (a countdown clock appears from time to time) and also features unverified speculations as though they are proven facts.

The film for the most part is an accurate depiction of the event, but its bending the rules of what classifies as a documentary simply opened the door for later films to flub facts and make speculations while still being given the golden stamp of Oscar approval.

The most egregious of these examples is Michael Moore’s “Bowling for Columbine,” a film filled with blatant distortions of facts, animated sequences and other thinly veiled partisan attacks. That the film won the 2003 Academy Award for documentaries was simply the death of any last vestiges of dignity that the award ever held.

Following that, “populist” documentaries meant to espouse the filmmaker’s political feelings and belittle his or hers opposition under the guise of telling a truthful story became all the rage. Documentaries being political or even biased are nothing new, with anti-Vietnam ones like “F.T.A.” and “Winter Soldier” being released in the early ’70s. But this new class of film was something different.

The problem ultimately is with Moore’s documentary win, the standards for documentaries having falling to absolutely nil. Really, the only requirement is that the filmmakers include “real” footage. It’s not just films with liberal biases that are guilty, I sat through Ben Stein’s “Expelled,” after all. Fair warning: you probably shouldn’t follow in my footsteps there.

The nomination of “Gasland” is not a surprise in this current lax environment of documentary qualification, and is perhaps a sign of further things to come. The oil and gas industry has rarely been a popular business in mainstream film community, so expect documentaries on the BP Gulf of Mexico spill, the recent earthquake activity in Arkansas (guess what environmentalists are blaming THAT on) as well as the recent Ecuador oil spill judgment. Anticipate capitalism to be vilified, all while the filmmakers boast you can buy their films on DVD.

So what to make of all this? Well, if you want to be nominated for an Oscar, pick some sort of political issue, take a populist approach to the topic (i.e., show working people as the salt of the Earth and corporate executives as mustache twirling villains) and you’re a shoo-in. Bonus points if (1) you don’t actually interview the other side and instead rely on second-hand or even third-hand anecdotal evidence or (2) you do score the interview, but you edit the footage out of context or deliberately leave out arguments critical of your thesis. Is that Oscar I hear ringing?

Following the ouster of Egyptian president Hosni Mubarek last week, the demand for democratic change has begun to sweep the Middle East and Northern Africa. In 21nations throughout the region, protesters have been having violent clashes with their countries security forces, demanding democratic changes to their societies.

Bahrain, an island national in the Persian Gulf, is actually one of the more even-keeled nations in the region. However, the country is still ruled by an absolute monarchy. Several protesters began demonstrating on Feb. 4 to show solidarity with the Egyptians. According to the LA Times, Bahrain’s Shiite legislators have left the nation’s Parliament in protest toward government crackdown on protests, which has so far led to 8 deaths and more than 200 other injuries.

Tunisia is also locked in an revolution, with leaders complaining about high unemployment, inflated food prices, lack of free speech and other issues. The outburst in that nation began following the death of Mohamed Bouazizi, a 26 year-old food vendor whose cart was confiscated for allegedly operating an unlicensed business. Bouazizi was assaulted and insulted by the police woman who fined him, and he was denied a right to speak his case before the provincial authorities. He later doused himself with gasoline and set him afire to protest the nation’s unemployment problems.

This act soon caught popular thought and tapped into the nation’s growing unrest. Within one month, Tunisian president Zine El Abidine Ben Ali was ousted by the military.

Iran is facing uprising that commemorate 2009’s protests. Now the protesters are screaming death to President Mamoud Ahmadinejad.

Despite getting the U.S. into two wars, President George W. Bush has always maintained that history will absolve him. That is, that the world will hate him for a short time but in the long run, the Middle East will be a better region after other leaders decide to follow the democratic model of Iraq (or at least the perceived democratic model).

That’s far-thinking though. For now, the blood and misery is a reality for people in the Middle East demanding a more honest government. I think the great poet Barry McGuire said it best:

The eastern world, it is exploding
Violence flarin’, bullets loadin’
You’re old enough to kill, but not for votin’
You don’t believe in war, but what’s that gun you’re totin’
And even the Jordan River has bodies floatin’

Figures also show a wider increase in traffic of 42% across the North American continent during the first six months of 2010, compared to the first six months of 2009. This increase is a result of OilCareers expansion at the beginning of 2010 with a new office opening in Houston and subsequent investment in a brand awareness campaign. Resumes uploaded increased by 33% from November 2009 to November 2010, demonstrating that users took the site to be a credible job resource.

From a global perspective, the job board’s talent pool of oil and gas specialists has grown to more than 780,000 users, and its global resume database has also experienced strong growth, up 23% on November 2009 to more than 465,000 resumes in November 2010.

The figures also highlight encouraging growth in a variety of roles, with increases in the logistics, administrative, health and safety, design, and trades fields.

Additionally the sales and marketing sector has seen a marked increase in opportunities, alongside operational, IT communications, HR, personnel and training vacancies, positions that are all considered leading indicators of increasing hiring.

It is a positive sign in an industry that, according to OilCareers.com’s Managing Director, Mark Guest, has clearly seen market vacancies affected by the economic recession over the last two years.

“Industry experts have projected an increase in oil exploration this year,” said Guest. “In theory, a consequence of this should be an increase in job vacancies, which will follow on from the improved signs in hiring we saw last year.”

“With strong oil prices, 2011 should offer great employment potential for people looking for positions within the oil and gas industry worldwide.”

On future trends, he added, “There is enormous scope for young and talented engineers to climb the career ladder, whilst concern for the environment is also expected to create new positions within the industry.”

Although the figures demonstrate areas of growth, OilCareers.com warned recruiters and candidates alike to approach the year with “guarded optimism”, following the release of its white paper, “The 2011 Oil and Gas Industry Hiring Outlook”.

The paper included a number of key observations, suggesting that businesses should focus on hiring in areas of demand, such as engineering, geosciences and undersea exploration and production.

It suggested that a near-term increase in exploration would see a rise in demand for drilling positions, however advised that a longer-term outlook was less positive, with a predicted 14% decrease in this area by 2018.

Another recommendation put forward is for companies to consider extra graduate hiring, recruiting ahead of demand and developing mentoring programmes to begin the transfer of knowledge to a newer generation of engineers and technical staff.

OilCareers.com also noted a potential increase in environmental positions, suggesting that companies may try to establish newly proactive positions in order to address public concern and potential new government regulation following the Deepwater Horizon incident.

Download the 2011 Oil and Gas Industry Hiring Outlook at http://www.oilcareers.com/hiring_outlook_2011/.

Tom Petrie: “Quite clearly some of the opposition to fracing is coming from those who have a different agenda—to curtail the development of shale gas in general.”

A rolling, 30-day moratorium in the Gulf of Mexico with as much urgency tasked to federal legislators as to industry would have been a more successful resolution to continued U.S. energy production from the prolific region while developing stronger environmental-remediation defenses.

This is according to Tom Petrie, vice chairman of Bank of America Merrill Lynch, at a recent Oil Council meeting in New York City.

“It should have been a rolling adjustment that would have cut the time down from five and a half months to three months,” he says.

John Maalouf, senior partner for law firm Maalouf Ashford & Talbot LLP, says regulation and pending regulation in the Gulf stunted new M&A activity in the region in 2010, after an active first quarter and start in the second quarter.

“The uncertainty has, at least temporarily, put the brakes on transactions. Regulators are prone to overreaction in the wake of a perceived crisis and, although an analysis of these new regulations reveal they will do little to help the environment, they will have a very negative impact on oil and gas companies of all sizes, particularly smaller companies.”

As a result, Gulf oil and gas and related assets have become undervalued, he says. “Hedge funds and private-equity investors are taking advantage of the situation and increasing their equity position in the energy sector.”

Bobby Tudor, chief executive officer of energy investment-banking firm Tudor, Pickering, Holt & Co. Securities Inc., says the natural possibility of a well blowout cannot be eliminated, as hydrocarbons are combustible. The issue, instead, is remediation.

“If we can’t eliminate the possibility of it happening, then we had better be able to remediate and quickly. What was exposed in the Gulf is that—in ultra-deepwater, in ultra-high-temperature and -pressure situations—the industry’s plans for remediation certainly were not up to the task.”

A moratorium was absolutely appropriate, he says. However, today, permitting of new Gulf shallow-water drilling remains sluggish, and permitting of new deepwater Gulf drilling remains unofficially suspended, as regulators are deeming remediation plans insufficient.

“I think the big gripe for the industry and for the people who live along the Gulf Coast is that the nature of what has happened politically is such that it has absolutely shut down activity across the board in such a way that it is hugely damaging to people who live in that part of the world.

“Whether the (Obama) administration understands that and doesn’t care or doesn’t understand it…, that’s where I personally have a gripe as do most of the people in the industry as well.”

On another environmental matter—more regulation of hydraulic fracturing—Petrie says, “This is a work in progress. Quite clearly some of the opposition to fracing is coming from those who have a different agenda—to curtail the development of shale gas in general.”

Regulators need to grasp what are the real risks of fracing and where there are risks. “Quite clearly, in the watershed of New York City there is an issue and I think many in the industry acknowledge that.

“To the best of my knowledge, there are very few other places where fracing is occurring today in shale-gas development where there is a comparable risk to the water table, but it needs to be fleshed out as soon as possible because it is a transforming, new (gas) supply option as long as it can be done without incurring unacceptable risks to other resources, like the water table.”

For more news from the Oil Council meeting, see

–‘Not A Bottomless Pit:’ JV Partners In U.S. Unconventional Resources

–U.S. Shale-Gas Plays Are ‘Criminally Destructive,’ Says Kayne Anderson’s Sinnott

–BP: Exporting U.S. Gas Depends Ultimately On If Foreign Buyers Can Compete With U.S.’ Own Market

–Transier: Divorces Among JV Partners Inevitable And Will Be Ugly

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

The U.S. E&P joint-venture deal with a foreign partner is not a bottomless pit, warns Bobby Tudor, chief executive officer of energy investment-banking firm Tudor, Pickering, Holt & Co. Securities Inc.

“There are only so many deals in North America that Reliance (Industries Ltd.) is going to do—or CNOOC or Statoil for that matter. So there is not a bottomless pit, if you will, of buyers for these asset-level deals and, at some point, the music stops.

“It’s just not yet,” Tudor said at a recent Oil Council meeting in New York.

JVs among leading U.S. unconventional-resource players have made international headlines in the past two years, including Chesapeake Energy Corp.’s recent deal with CNOOC Ltd. in Chesapeake’s Eagle Ford play. Deals with smaller independents have as well.

“Smaller independents with shale-gas positions have found difficulty with funding over time,” Tudor notes, as natural gas prices have softened from 2008 highs.

Carrizo Oil & Gas Inc. has done a deal with Reliance in the Marcellus. “Gastar (Exploration Ltd.) has done one (with Korea’s Atinum Partners Co. Ltd., also in the Marcellus). And they have all done exactly that, which is to use the attractiveness of their asset base to bring in a partner to help fund it to accelerate cash flow to get their borrowing base up so they can, effectively, live to another day.

“They’ve been able to, in effect, sell a piece of the company to make that happen. We think there will be more of those. The question is, ‘When does the buyer list run out?’”

Tom Petrie, vice chairman of Bank of America Merrill Lynch, said at the Oil Council meeting, “There is a risk of ‘deal fatigue’ on the JV side. The foreign buyers, in my view, and the ones we’ve been involved with in the past two years, wanted to come in not just to get access to the resource.

“In fact that was a secondary consideration. Most of them wanted to get up the (unconventional-resource) learning curve and be able to apply it back in their own domain, so we’re pretty well through the list of parties who want to do that.”

More North American unconventional-play JVs are to come, but there will be fewer, Petrie agrees. “It’s going to be very interesting—how future JVs get done.”

Tudor notes that a unique dynamic supports non-U.S. JV partners’ return-on-capital analysis. “If you’re CNOOC or Statoil, there are a lot of reasons why you’re doing this, frankly, and near-term economic return in the next year is low on your priority list.

“If you’re CNOOC, you have a 3% cost of capital and a 50-year time line. If that’s the case, what you want to be doing is learning how you can do shale gas, so you can do it in other parts of the world and you want your capital to be working, if you have a 2% or 3% cost of capital. Commodity prices can be low and you can still survive.”

Petrie notes, “In the better shale plays, even at today’s (natural gas) prices, it’s economic.”

For more news from the Oil Council meeting, see

–U.S. Shale-Gas Plays Are ‘Criminally Destructive,’ Says Kayne Anderson’s Sinnott

–BP: Exporting U.S. Gas Depends Ultimately On If Foreign Buyers Can Compete With U.S.’ Own Market

–Transier: Divorces Among JV Partners Inevitable And Will Be Ugly

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

Also, A Russian POV On China: “China will continue to pay high multiples for these shale-gas assets…So, the shale story may continue to play itself out despite the destructive value to present shareholders.”

The shale-gas revolution has been a game changer in the U.S., but producing this unconventional resource in Europe is less likely to provide significant new gas supply there, says Mark Gyetvay, chief financial officer for OAO Novatek, Russia’s second-largest gas producer, making 5.3 Bcf/day.

“In Russia, we obviously look at the events in the U.S. with great interest, as the changes observed there will have some impact on us—albeit smaller than most people predict—but, nonetheless it is a situation that must be considered in capital expenditures and supply/demand dynamics,” Gyetvay says in a guest article exclusive to OilandGasInvestor.com. (For the article, click Russian Gas CFO Discusses The Shale-Gas Boom, European Supply/Demand, Poland’s Unconventional, China.)

Gyetvay says that, if all 70 rigs operating in Europe began drilling for unconventional gas in Poland, “it would take approximately 10 to 12 years to reach productions levels of roughly 2 Bcf per day, or the equivalent of 4% of current European gas consumption.”

Keith Rattie, chairman of U.S. integrated-gas company Questar Corp. and chairman of U.S. gas E&P company QEP Resources Inc., notes that Europe’s interest in developing indigenous gas resources is motivated in part by the fact that Russia’s OAO Gazprom, the world’s No. 1 gas producer, has cut off gas supply to western Europe twice in the past decade during disputes with Ukraine through which Russian gas supply westward travels.

Tantalizing is that drilling in the Marcellus alone, in the eastern U.S., has grown the shale-gas play into the world’s second-largest gas field in terms of recoverable reserves—catapulted ahead of five Russian fields, all conventional. (For a table, click The World’s 10 Largest Gas Fields.)

Rattie says, “I tend to agree with Gyetvay that shale gas is unlikely to be a game changer in Europe to the extent that it is in the U.S. But it’s early: The resource base could be very large, and never underestimate the potential for new technology to disrupt.”

Gyetvay says Russia’s conventional gas resources are produced at a much lower cost than U.S. shale gas. Rattie notes, however, that production costs tell only part of the U.S. story.

“There is a high cost of transporting gas from the Yamal Peninsula via pipeline to European markets,” Rattie says. The distance from Yamal to central Europe is some 2,600 miles; meanwhile, to put this into context, the distance from the North Slope of Alaska to Calgary is some 1,700 miles.

“Producers on the North Slope of Alaska can also produce gas at a very low cost. In fact, they’re producing, separating and re-injecting 8 Bcf a day. But that doesn’t make Alaskan gas an economic option of the U.S. market: Alaskan gas can’t compete because it will cost $30 billion to build a pipeline to move that gas to the Lower 48.

“In the Barnett shale—or Haynesville or Marcellus—production costs are a lot higher than in the giant gas fields in Russia. But the U.S. shale plays are located close to the market, so transportation costs are low.”

For Gyetvay’s guest article, click Russian Gas CFO Discusses The Shale-Gas Boom, European Supply/Demand, Poland’s Unconventional, China.

For the table, click The World’s 10 Largest Gas Fields.

For more information on U.S. shale-gas resources, click the DOE’s Annual Energy Outlook 2011: Early Release.

For more on Europe’s lack of love for Gazprom, and on Gazprom’s lack of love for unconventional gas, see “Gazprom Humor,” May 27, 2010.

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

Editor’s note: Gyetvay can be reached at mgyetvay@novatek.ru.

The website AllVoices has implied that fracture drilling could be the cause for both the animal deaths and, while they’re at it, earthquakes too.

Theorists believe that there is a correlation between the spike in earthquakes and the New Year’s Eve raining of dead birds and the incidence of deceased fish in the Arkansas River. They also believe that hydraulic fracturing is quite possibly the culprit in all three phenomenon. Fracturing or fracking causes earthquakes and releases toxins into the environment. Fracking is a global practice. Could it be that the other wildlife floundering around the world is somehow connected?

Now follow me, gentle readers, down this twisted highway of logic. Because of fracture drilling, Arkansas is now in danger of becoming Earthquake central. Heh, let me break this down. The last major earthquake in Arkansas was in December 1811, bad enough that it actually reversed the flow of the Mississippi River. So major quakes in the area, while extremely rare, are not unprecedented. The New Madrid Fault Line could just be gearing up for a major shake. It’s something to be prepared for, but it’s a natural event that can not be controlled by human behavior. If the earth decides to have an earthquake, there’s not much we can do about it.

As for all the animals dying off? Yeah, that’s fracturing drilling too. Maybe. Kind of. The author of this story hopes so.

Could it be the increased need and development of unconventional gas in the Arkansas River Valley and the use of fracturing has caused more earthquakes in the area? Could it be that the gas wells contained in the area have polluted the river leading to the deaths of the fish? Could toxins have been released from the earthquakes, contaminating the air and killing the birds of Arkansas on New Year’s Eve?

I haven’t seen so many “Could you believe…?” in a row since Maxwell Smart was busy saving the world from Kaos. Even Don Adams would have found that paragraph ridiculous.

What’s killing the animals? Most likely a combination of unexpected cold weather, possible climate change events and possibly just natural diseases. Louisiana State Wildlife Veterinarian Jim LaCour said there have been 16 similar mass blackbird deaths in the past 30 years. Let’s see, the Haynesville shale has been being developed for, what, only two of those?

The author goes on to criticize a study by the EPA absolving fracture drilling of any responsibility for water contamination, instead choosing to rely on the more entertaining pastime of speculation and conspiracy theory.

Is this a cover up? Is it denial? Fracturing is unregulated and utilized globally. Is it possible that the turtle doves in Italy, the fish in Chesapeake Bay, the birds of New Zealand and Switzerland succumbed due to the use of fracturing? Until in-depth analysis of the dead wildlife is conducted, the world will not know.

See the language being used here? Fracturing is “unregulated” (it’s not), implying that energy companies are running rampant and only Uncle Sam can bring order to this chaos. The fact is, fracturing IS regulated by the Safe Drinking Water Act, legislation that has been around since 1974. Scaremongers love to play around with the “unregulated” label simply because fracture drilling was exempted in the “Energy Policy Act of 2005,” which deferred hydraulic fracturing to the earlier legislation. Trust me, no state authority is going to allow any industry to pump chemicals into the ground with complete abandon.

So what are we left with in the end? Post hoc ergo propter hoc fallacies trying to turn fracture drilling into a bogeyman out to kill our fish and rip our planet’s surface apart. I say we blame if for the Bermuda triangle and sunspots while we’re at it. Wait, is that a tidal wave I see coming my way? Darn you hydraulic fracturing!

Introduction

SemGroup, LP, a highly-leveraged oil & gas transporter and marketer that purchased oil and gas at the wellhead (a “First Purchaser”), was the 18th largest private company in the nation when it filed for bankruptcy in 2008.  Since then, the availability of cost-effective, asset-based financing for other First Purchasers has become increasingly limited.  The SemGroup bankruptcy was a stern reminder to the industry that states such as Oklahoma, Texas, and Kansas have unique Oil & Gas Product Lien Statutes (“OGPL Statutes”) that in effect give exploration and production companies (“Producers”) an automatically perfected purchase money security interest in the oil and gas they sell at the wellhead.

In other words, a lender’s Uniform Commercial Code Article 9 security interest in a First Purchaser’s inventory, accounts receivable, and bank deposits is subordinated to Producers’ purchase money security interest in those same assets.   While lenders have found methods to continue lending to First Purchasers, the additional security measures required often kill new lending transactions or prove too costly for prospective borrowers to take on.   Fortunately, tailored insurance products are now available that can give lenders the security they need to comfortably increase lending to First Purchasers again.

Background
The bankruptcies of several large crude oil purchasers in the 1980s led many states to enact OGPL statutes protecting Producers.  Intended to secure payment obligations owed to Producers for oil and gas bought by First Purchasers, OGPL statutes have had the unintended consequence of diminishing the ability of First Purchasers to obtain financing, since at any given time the purchaser’s inventory, accounts receivable, and a portion of its bank deposits are generally encumbered by the purchase money security interest of Producers.

When SemGroup filed for bankruptcy, its lenders fought the effect and applicability of Texas, Kansas, and Oklahoma’s OGPL statutes in Delaware bankruptcy court.  The Court ruled in favor of the lenders and gave their Article 9 security interests the traditional treatment received in the UCC.  While this was an unpleasant surprise for Producers in that case, the ruling is not binding precedent in states with OGPL Statutes.  Lenders’ attorneys remain concerned that their clients may not be so lucky if First Purchasers file for bankruptcy, or become enmeshed in lien-priority litigation, in states with OGPL Statutes.

Legal developments in states with OGPL laws have only intensified lenders’ concerns.  Following SemGroup’s collapse and the subsequent bankruptcy court ruling in Delaware, Oklahoma revised its OGPL Statute in a further attempt to ensure that the Producers’ liens on sold production and its proceeds have priority over the UCC Article 9 security interests granted by First Purchasers to their lenders.  In addition, Producers may attempt to obtain enactment of new OGPL statutes and to strengthen existing statutes in other oil and gas producing states in the wake of SemGroup.

The Status Quo
As a result of OGPL Statutes and the uncertainty created by the SemGroup decision, lenders have reduced confidence that their UCC Article 9 security interests in First Purchaser’s inventory, receivables, and bank deposits are senior to oil and gas product liens created by OGPL Statutes.  Lenders who continue to provide financing in the sector usually require a combination of the following additional security measures:

•    increased reserves against availability in the borrowing base
•    increased collateral for reduced amounts of advances
•    increased interest rates
•    increased borrowing costs

Under the status quo, lenders, First Purchasers, and Producers all fail to maximize their interests due to the risk associated with a First Purchaser’s bankruptcy or insolvency.  Certain specialized insurance markets have significant experience dealing with such risk.  Insurers regularly insure against the bankruptcy of counterparties with business credit insurance policies (essentially ensuring the collection of accounts receivable) and the uncertainty created by regulatory statutes with political risk insurance policies (mitigating the risk of unfavorable political or legal outcomes).  Using these proven insurance products as guides, lenders can now secure credit risk insurance policies from A-rated carriers ensuring against the insolvency of a First Purchaser, thus giving lenders the ability to offer more competitive terms regardless of the impact of OGPL statutes on their collateral.

First Purchaser Credit Insurance
The mechanics of these insurance products are straightforward: in the event of a First Purchaser’s bankruptcy or insolvency, the policy will cover the amount necessary, up to the limits purchased, to pay Producers’ OGPL statutory liens encumbering the First Purchaser’s assets.  As a result, a lender’s Article 9 security interest in a First Purchaser’s inventory will retain its traditional senior lien position over Producers’ OGPL security interests.  The insurer also agrees to subordinate its subrogation rights to the Lender via an intercreditor agreement.

Some lenders have asked why the policy is structured this way instead of just providing lenders with the cash proceeds from the insurance policy.  The answer is that many First Purchasers also own some oil and gas processing equipment.  In many cases, a small amount of processing can significantly increase the value of the oil or gas purchased at the wellhead.  So retaining the first-priority rights to processed oil and gas will be more valuable to lenders than the mere receipt of the purchase price of the raw material at the wellhead.

Conclusion
Insurance products can facilitate the completion of otherwise difficult financing  arrangements.  By transferring the risk of loss of senior rights in collateral associated with a borrower’s bankruptcy from the Lender to a third party insurer, the lender can attain greater security in collateral, increase the competitiveness of loan terms, and better complete deals in the midstream sector.  As a result, First Purchasers can have more flexibility in fashioning their capital structure and can avoid the necessity for posting letters of credit with Producers.

Josiah Daniel is an associate with Meyers-Reynolds, a risk management and insurance brokerage firm specializing in the energy industry.

And as the future world of Back to the Future Part II is now just around the corner, I feel sorry to report that we are desperately lagging behind in our hoverboard technology. And why aren’t people wearing spacesuits? Come on people, it’s the future! Get with it!

But oil is still here. In fact, I’m rather surprised. Hollywood promised me flying cars and teleportation. Heck, the timeframe of Blade Runner is now just around the corner and we don’t replicants yet, let alone police officers suffering from existential breakdowns as to whether or not they dream of electric sheep.

I’m going to make a prediction. Conservative for sure, but let me just ruin everyone’s dreams of the future. For the next 50 years, we’re still going to be using fossil fuels. We’ll still be drilling for oil, still running our stoves on natural gas and still fueling power plants with coal. Biofuels are cute and everything, but I’m just not seeing any major breakthroughs in the next half century.

Where there’s Carl Icahn, there may be smoke.

The hedge-fund manager recently disclosed that his Icahn Capital LP and affiliates have accumulated 38.6 million, or 5.8%, of outstanding shares of U.S. gas E&P giant Chesapeake Energy Corp., consisting of some 26.1 million common shares and 350,000 of 5.75% cumulative non-voting preferred that are convertible into 12.5 million common. (Click for the PDF of Icahn’s SEC form SC-13D filing regarding the Chesapeake holding, Dec.17, 2010.)

Icahn is well known as an activist shareholder, providing management with instructions, including pressure to sell. Icahn Partners LP, with Jana Partners LLC, was behind the break-up, and then sale, of Kerr-McGee Corp. to Anadarko Petroleum Corp. in 2006.

Icahn was also behind the turn-around of National Energy Group as NEG Holdings and its sale in 2006 to SandRidge Energy Inc., which was founded by Tom Ward, a co-founder of Chesapeake.

More recently, Icahn partnered with Seneca Capital Investments LLC, another major shareholder of Dynegy Inc., to prevent the sale of the electric-power company to The Blackstone Group in November and has followed up this month with an offer of its own. Blackstone offered $5 a share; Icahn is offering $5.50. Seneca stated, when opposing the Blackstone offer, that it believed Dynegy is worth at least $6 a share, and it is opposing Icahn’s $5.50 offer.

Michael Bodino, director of energy research for Global Hunter Securities LLC, notes that Icahn states, in his filing regarding the Chesapeake shareholding, that he believes the shares are undervalued and he intends to talk with Chesapeake management about maximizing shareholder value.

“While standard language, one cannot help but wonder whether this is just an investment or if this will put Chesapeake in play,” Bodino says.

“…From an NAV perspective, it is easy to argue that Chesapeake is worth more dead than alive, but kudos to management for capturing significant value through massive land purchases and for refinancing through the joint-venture market.”

Who would buy Chesapeake? “We have tons of ideas swirling around our heads,” Bodino says. “With all of Chesapeake’s joint ventures and its labor-intensive land department, is this really the business a larger company wants to own?

“Does it make sense to break the company up into an oil company and a gas company or basin-specific companies, or a production company and a land/lease maintenance service company?”

If not selling, Chesapeake’s stock price may more closely reflect its asset value if EBITDA grows, Bodino adds. “With so many projects in their infancy, drilling could be the best option for maximizing shareholder value.”

Or, is Icahn’s tactic that of greenmail, which is to force Chesapeake eventually to buy back the Icahn shareholding at a higher price to prevent a hostile takeover? “Or, is Aubrey (McClendon, chairman and CEO) ready to harvest the company after all of these years?”

The experience among managements in the past is that to partner with Icahn often proves to be like playing with fire.

Click for Icahn’s SEC form SC-13D filing regarding the Chesapeake holding, Dec.17, 2010.

For more on past Icahn and activist-shareholder activity, see “Know Thy Hostile Shareholder,” April 2008, and “There Goes Pogo,” August 2007.

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

More pressure-pumping supply is coming online in the first half of 2011, but the gridlock in well completions across the U.S. will meet with another problem: a shortage of proppant. Proppant holds the fractured rock open, increasing the flow of oil and gas, and the greatest use for this application is ceramic, resin-coated sand and sand.

Carbo Ceramics Inc., the leading provider of ceramic proppant, has been running full-out for several years. Brian Uhlmer, oilfield-services and -equipment analyst for Global Hunter Securities LLC, says the dry-gas rig count has peaked, “but strong demand in the growing (oily) Bakken, Eagle Ford, Granite Wash and Niobrara and more than 3,000 uncompleted wells bodes well for the company to continue to sell out capacity.”

An expansion of Carbo’s Toomsboro, Georgia, plant, adding lines 5 and 6, is likely in the works for mid-2012 already, he suspects. “Selling out new capacity is not a concern. The company has proven that it can sell essentially all that it can produce.”

Carbo’s existing 20% company-wide capacity expansion via Toomsboro lines 3 and 4 is coming online at the same time as additional pressure-pumping equipment.

In the Bakken and Eagle Ford, producers are showing a preference for ceramics, rather than sand or resin-coated sand, “and have been forced to mix resin-coated sand in with the ceramic proppant due to lack of (ceramic) product availability,” Uhlmer says.

Jeff Tillery, oilfield-services analyst for Tudor, Pickering, Holt & Co. Securities Inc., says Toomsboro’s lines 1 and 2 make 500 million pounds of proppant per year or 40% of all of Carbo’s output. Companywide output in 2010 will be some 1.5 billion pounds—twice that of 2005—and Carbo may double this during the coming five years. To reach that, six more lines at Toomsboro, lines 5 through 10, would have to be completed, he says.

“Carbo is looking at the resin-coated sand business to supplement its current operations, which constitute exclusively ceramic-proppant production, but, if this path were taken, it would probably be developed in-house rather than acquired. The resin-coating process not very complex.”

Wunderlich Securities Inc.’s research team reported in August, after EnerCom Inc.’s oil and gas investment conference in Denver, “Technology and other efficiencies have helped reduce well costs. Multiple E&P companies discussed static—to declining—well costs using new technologies and better efficiencies.

“For instance, we spoke with multiple management teams with Bakken plays that discussed the use of sand rather than ceramic proppant that costs seven to 10 times as much, and some companies are looking to use sliding-sleeve fracture completions rather than plug-and-perforate completions, as the former costs about half as much.

“We believe that, even as service costs continue to creep up in the hot oil plays, the technological gains and efficiencies should mitigate these increases.”

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

Doer recounted one interesting encounter with Texas Governor Rick Perry, where one of Perry’s aids (whom Doer referred to as well researched) proudly shared that Manitoba, Doer’s home province, is the largest consumer of Slurpees in North America, a product made by Dallas-based convenience store chain 7-Eleven. Doer was happy to share, at a later meeting, that his staff had discovered that Texas is the largest consumer of Manitoba-based Crown Royal whiskey. This prompted a comment about the importance of international trade.

The Canada-Texas trade relationship, according to Canada’s Department of Foreign Affairs and International Trade, is valued at $21.1 billion and supports more than 625,000 jobs in Texas. There are 240 Canadian-owned companies employing nearly 39,000 people in 1,042 Texas locations. More than 8 million jobs in the total U.S. are dependent on U.S. and Canadian trade, with merchandise trading between the two countries totaling $392 billion.

Discussing carbon emissions in the Canadian oil sands, Doer says the government has agreed to reduce emissions by 17%, but he adds that doesn’t mean it’s 17% for all industries.

“We’ll continue to work with the industries to reduce emissions at the oil sands with them, but when we look at Canada’s policies on getting to our 17% target, some things will be harmonized with the U.S. like vehicles, but we have a lot of coal plants that are getting older, and that represents close to 19% of the emissions in Canada,” says Doer.

The new regulations will eliminate all but two Canadian coal plants, the rest replaced with gas-fired and hydroelectric plants. He adds that U.S. coal usage creates 60 times greater greenhouse gas emissions than the Canadian oil sands.

Doer shared one humorous account of the Copenhagen Summit in 2009, where a panel was discussing the need to end dependence on fossil fuels. He mentioned one actress, who he would not name but said she once played a mermaid, said during the panel that she had completely weened herself off of fossil fuels. To this, Doer remarked “That must have been a really long kayak trip from Hollywood to Copenhagen.”

Second, former SNL cast member Tina Fey received a special award at the Kennedy Center for being a staggeringly unfunny comedian with a sitcom that no one watches ridiculing Sarah Palin for the past two years. Basically, a group of celebrities got together to congratulate each other for being celebrities and sharing the same political views, and rewarded the one who best belittled a woman that didn’t get elected but somehow is still the bane of their existence.

Oh yeah, and the so-called media covered Hart Energy’s DUG East conference from last week with the typical degree of fair reporting.

In an act of unbiased journalism, the Real News actually gave Oil and Gas Investor editor Leslie Haines a sum total of two short sequences before changing into a commercial for Jason Fox’s documentary Gasland. Haines spoke a total of about 100 words on camera, while Fox got closer to 355. And that’s not counting all the other like minded people who made it in the story as well. The sheer attempt to disguise a one-sided attack as being legitimate news is laudatory in today’s political climate, so I salute The Real News for so cheaply covering their bases.

I suppose a group of angry, unemployed protesters and punk rocker Justin Sane singing (caterwauling?) a really bad protest song (Woody Guthrie must be spinning in his grave) are more visually appealing then the sight of businessmen conducting their affairs in quiet, professional way.

Oh, one final note: CBS will be airing a new episode of CSI tonight. The episode, titled “Fracked,” features this synopsis: “Two men are murdered right before accusing a natural gas company of poisoning the water in a farming town.” Sounds like another winner to me.

The U.S. shale-gas plays are “criminally destructive,” says Bob Sinnott, president and chief executive of private-equity firm Kayne Anderson Capital Advisors. The Los Angeles-based firm has some $10 billion under management in energy infrastructure as well as oil and gas.

“I believe the (gas) shale plays are criminally destructive,” Sinnott told Oil Council meeting attendees in New York recently. “They are throwing so much gas into the market that gas prices are now $3.65. (A fellow presenter’s slides) show the rate of return for the shale plays assumes $6 gas.

“It isn’t $6. It’s $3.65, and no one is making a dry-gas profit at that.”

An E&P operator was in his office recently. “He said their F&D cost for their next shale well was 98 cents, but their full-cycle economics was $3.80. So, I said, ‘At $3.80, you’re getting $3.65. Are you making any money?’ And he says, ‘I never thought of it that way.’”

That is the mindset today. Instead, “we should be curtailing. We should be limiting gas supply. We should be getting $6, $7. Look at oil: Oil has an economic value. Gas should have an economic value.”

Among the panelists, he said he is probably the oldest. “Back when Ken (Hersh with private-equity firm Natural Gas Partners and fellow presenter) and I started in this business, everyone curtailed when we were in these types of worlds. No one curtails much anymore.”

Some producers, such as Chesapeake Energy Corp., say they’re laying down rigs or that they will next year. “We should be laying down rigs (now). The problem is that the technology John (Moon with Morgan Stanley Private Equity and a fellow presenter) is talking about is coming along and every time (operators are) drilling a well, they’re lowering the cost a little more, so they want to drill some more.

“Or you’ve got international oil companies out here drilling in order to learn how to import that technology to their countries and to other places in the world.”

Meanwhile, “they’re all destroying capital in that part of the business.”

Kayne Anderson does like the economics of oil-shale plays, in which it is invested in California, he says. “But California is a much different world…It’s a very difficult operating area. We have one project that, if we can get the next well down at $2 million less than our first well, then we have 150 drillsites at $8 million a well.

“So I have $1 billion to spend in California, if it works, but I don’t know if I can get it done, can get it down another $2 million.”

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

Receiving U.S. approval to export U.S. natural gas as LNG is only one, possibly very small, step toward commercializing excess U.S. supply, according to Brian Specter, managing director, structured products, for BP Plc.

“Today, clearly natural gas has a much dearer home in Asia and in Europe where native energy prices are much, much higher,” Specter told Oil Council meeting attendees in New York recently.

“So I think gas will continue to be looked at to be pushed offshore. If the capital is put in and the ability to export it is there and the market remains there, then absolutely you can get more gas out of the shales, but I don’t think you can look at it just in terms of all of a sudden you can send it offshore so now you have a market there.”

Specter says talk of environmental regulation in the U.S. via a carbon tax, for example, bodes well for U.S. natural gas supply, which will create more demand domestically and strengthen prices. Meanwhile, carbon regimes in Europe will affect demand there.

A great deal is in flux in the midst of a very long-term proposition, such as building gasification facilities and securing contracts for delivery.

“You have to really put a different hat on when you look at the way LNG is priced because most of the rest of the world doesn’t look at gas supply the way we do. For them that gas supply is almost like coal. It’s a long-term commitment. There’s a large capital expenditure (on import facilities) in the front end of it. They’re willing to invest in it for the long term.”

In the U.S., natural gas pricing is possibly one of the most liquid commodity markets in the world, and derisking a long-term investment is easier. “It’s very liquid and it makes it easy for producers to do their investing because they can come to folks like BP and lay off this risk (through hedges). The LNG market is just fundamentally very different.”

Also, Qatar and other LNG producers are difficult to compete with; for these, the LNG they export has no domestic market. “It’s a commodity they’re pulling out of the ground and, in the case of some gas producers, it’s wrong to say it’s a byproduct, but let’s just say the condensate that is being yielded off some of these gas fields that are doing LNG is much more valuable than the LNG that they’re putting out today, so the economics of oil play a lot into it as well.”

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

Divorces among U.S. unconventional-play joint-venture partners are inevitable, says Endeavour International Corp. chairman, president and chief executive Bill Transier.

And these divorces are going to be ugly, even politically charged, he told Oil Council meeting attendees in New York recently.

“You would hope not but, in general, you’re definitely going to see that happen.”

Endeavour operates in the U.K. North Sea and in U.S. unconventional-shale plays in the Haynesville, Marcellus, Alabama and Montana, and it holds interests in South Texas and the Permian Basin.

“All you have to do is go around the world, and the way they think about the oil and gas business is dramatically different from the way we think about it in North America or even in the U.S.”

This disconnect will surface in time. “You’ve seen in these JV agreements that they’re highly complex in the way they’re put together. Some guys, like Aubrey (McClendon, chairman, president and CEO of Chesapeake Energy Corp.) do a really good job of weighting all of the terms to his benefit over time.”

Chesapeake entered a joint venture in its Eagle Ford shale play in South Texas in October with CNOOC Ltd., a first time the Chinese national oil company has held oil and gas interests onshore the U.S.

Chesapeake and other U.S. operators have entered JVs with Norway’s Statoil ASA (Chesapeake, Marcellus); the U.K.’s BP, BG and Royal Dutch Shell (Chesapeake/BP, Fayetteville; Exco Resources/BG, Haynesville; Exco/BG, Marcellus); Italy’s ENI Spa (Quicksilver Resources, Barnett); France’s Total SA (Chesapeake, Barnett); Japan’s Mitsui and Sumitomo (Anadarko/Mitsui, Marcellus; Rex Energy/Sumitomo, Marcellus); and India’s Reliance Industries (Atlas Energy, Marcellus; Pioneer Natural Resources, Eagle Ford; Carrizo Oil & Gas, Marcellus).

“For Statoil, CNOOC and now the Koreans (in a JV with New York private-equity firm KKR for a roughly one-quarter interest in Colonial Pipeline Co.), Eventually they will figure out it’s not really what they intended or the way they think about the business and that’s where you will get into these politically charged events. It’s going to end up that way.”

The cost of entry in these deals totals more than $18 billion, according to a Jefferies & Co. count. Additional capital is required in the JVs to fund further drilling of the acreage position.

“The balance in the U.S. with some of the capital that has flowed in through some of these ventures has kind of skewed the market, particularly natural gas in the U.S., and eventually you may see a response on the U.S. government side and you may see a response from some of these NOCs.”

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

Production from unconventional reserves have been on steep increase, as opposed to mature basins like Gulf of Mexico or more experimental (but politically taboo) locations like Alaska, has been increasing. About 50% of gas being produced in the U.S. today comes from unconventional reservoirs, says Goodrich.

Haynesville: Though it doesn’t get the same amount of press that it used to, the Haynesville is today, and is going to be, a very large source of gas for the U.S. “From a standing start in January 2008, the horizontal rig count activity in the Haynesville has been a monster, up from effectively zero to a peak in the third quarter of this year of 189 rigs.”

Goodrich says the play has started to plateau, but it is still a major contributor to both gas supply and also the effects on gas prices. From July 2008 to July 2010, Louisiana production was up dramatically , almost all on the back of the Haynesville shale. In one year, the state added 2 Bcf per day of gas production.

Barnett: Compared to the Haynesville, Barnett on the other hand has done almost the opposite.

“It’s gone from 182 rigs running in that time period down to about 77,” says Goodrich.

The drop in Barnett activity was part of an overall drop in Taxas gas production of about 1.5 Bcf per day between July 2008 and July 2010.

Marcellus: The wild card of the bunch. A gigantic natural gas play, it jumped from nearly zero rigs in January 2008 to more than 130 rigs running today. Because of the success of the Marcellus, Goodrich says this brings Pennsylvania and West Virginia into the fold as energy-producing states with significant political clout. Marcellus is was up 1 Bcf a day between July 2008 and July 2010, and Goodrich sees that number continuing to move forward in 2011.

“This is the one play I believe that continues to add rigs throughout 2011,” says Goodrich.

Or not. San Francisco Chronicle columnist Mark Morford spared no invective in his column yesterday as he blamed Tuesday’s radical shift in the Legislative branch to young voter apathy and vile fascist propagandizing. His screed, titled “Letter to a whiny young Democrat,” amounts to little more than an 1,100+ word assault on his peeps for abandoning their Fearless Leader Barack Obama in his time of need because he didn’t satisfy their instant gratification culture.

To Morford, the young generation were bored with politics once the sound and fury of the presidential election ended, and reverted back to their tweeting and Facebooking. And in that he does have a point, but for the wrong reason. To Morford, Obama is flawless and without blame in this recent political shift, being abandoned by an entitlement-focused base just when needed them the most.

Now, he tries to soften the blow by pointing his guns at the real culprits: Republicans.

After attending an industry soiree on Oct. 26, I now feel a little more optimistic about the future of energy. The Young Professionals In Energy, an organization that boasts 10,000 members worldwide (the majority of which make Houston their home), is one organization that has been formed to provide support for younger members of the energy industry, whether they belong to upstream, midstream or downstream companies or are in related financial, accounting or other industries that function with oil and gas.

More than 300 people turned out to hear Tudor Pickering’s Dan Pickering and Goodrich Petroleum’s Gil Goodrich discuss the natural gas industry, and what I saw gave me hope that there just might not be a talent deficit after all.

There have been concerns for a while that the average age of people in the energy industry, on both the asset owning and production sides, were getting older and not enough young people were wanting to get into the industry. Just who were today’s leaders going to pass the torch to, if an increasing number of college students were seeking careers in other fields? Well, if yesterday was any indication, they have plenty of talent from which to pull.

We don’t live a society that always grateful for the business that allows it to thrive, or even considers it unless it’s in the news, usually for the wrong reasons. When BP’s Gulf of Mexico oil spill can dominate the headlines for months, or shale gas can be treated a scary bogeyman out to kill puppies, it’s no wonder that many people grow up thinking that energy is a demon they must learn to live with instead of the thing keeping us out of the dark ages.

Not to say the energy industry is perfect or that every negative story that crops up is the result of a conspiracy to give the business a bum rap: spills, pollution and sometimes questionable relations between energy firms and governments are all real issues. But with such a steady onslaught of negativity in the media toward the industry, it led many to think that people would avoid joining the industry just on principle.

If last’s night audience was any testament, fears of a lack of future participation in the industry seemed like it would be in decent hands for quite a while.

The Rextag acquisition adds to Hart Energy’s growing content portfolio with the addition of digital GIS databases and mapping services, custom digital cartography, pipeline flow and capacity data, energy infrastructure wall maps and reference books, all covering oil, gas, and other liquid pipeline operations throughout the United States.

Read the full press release here:

http://www.prnewswire.com/news-releases/hart-energy-acquires-rextag-mapping–data-services-105680298.html

Pretty heavy stuff there. As someone who writes for a financial publication, I was taken aback by Moore’s thesis. Capitalism, evil? Could this be true? Is socialism the way? Should it be from each according to his abilities to each according to his needs?

Workers of the world, before you unite, think on this. Moore’s central thesis is wrong. Not exaggerated, not only slightly true. Flat out wrong. Capitalism is not evil. The reason why it sometimes comes across that way is because when done properly, it can be harsh and unforgiving to those who make mistakes. And yes, many capitalists are evil. But the majority of people involved in the trading of goods and services are not monsters. They’re people like you and me. In fact, they are you and me.

Now, far be it for me to defend all the bankers responsible for the recent economic meltdown. They had crumby lending policies, and if there was an justice, they would have to live with the consequences of their actions. Too big to fail was just a campaigning slogan used by the federal government to get us to overlook on of the basic fundamentals of capitalism: that there is negative price to pay for bad investment decisions.

However, despite the will of the American people, which told their Congressional representatives that they opposed the bailout, the federal government went ahead with the plan anyway.

All this is true, and it’s a black stain on our political system. But equally as true, just not mentioned in the same detail or with the same degree of vitriol as the banks’ actions, was that a lot of Americans took on loans that they could not keep up with because they fell in for fast-talking lenders, or refinanced their houses to go out and buy big-screen TVs, another car or lots of other junk they didn’t need, or just flat out got in over their heads with credit card debt during the free-wheeling 2000s.

It’s not popular to point fingers at the little man and say they made dumb choices. It doesn’t get you awards to expose people being evicted from their homes as having made terrible financial decisions. The little guy is somehow always right and never responsible for their own actions.

But, even now, as we deal with the aftermath of a $700-billion corporate bailout and a potential foreclosure freeze, what have we learned from this fiasco? Apparently, nothing. Speaking with a co-worker, who has a background in real estate, has been revealing. He says that in a properly run economic systems, everyone who made bad financial decisions would be forced to eat their losses. Individuals who took out subprime loans would lose the houses they never would have been able to afford to begin with, and the lenders who based a big chunk of their business on offering such loans would likewise have to deal with their stock value dwindling, or going bankrupt. Goldman Sachs does not have a divine right to exist. We human beings have lived on this planet for millenia without the existence of Washington Mutual, somehow we will continue to exists as a species without it.

But because we bailed out the banks and put a stop on foreclosures, we did not allow capitalism to act properly. We put our foot down because don’t like it when there’s negative consequences to our actions. To some of us, that’s the reason why government exists: to protect us from ourselves. We can’t be trusted to be held accountable for our behavior, and we need a wizard to wave a magic wand and erase our mistakes. Drizzle, drazzle, druzzle, drome, I won’t be evicted from my home!

Sorry, but you’re not Tooter Turtle, and the government isn’t Mr. Wizard the Lizard.

What does Moore offer in place of capitalism? Well, he offers democracy, which is not only ridiculous for the fact that democracy is not a financial system (with that logic, let’s replace our Nintendo Wiis with love!) but really because its based on the assumption that everyone deserves to make the same amount of money, regardless of their labor.

The problem that Moore, and a lot of like-minded individuals when it comes to economics, is they assume the best of mankind. At least when it comes to the commoners. People at the top of the financial chain are of course evil, lecherous fiends who dine on kittens and wipe their noses with puppy carcasses. They think that if given an even playing field (ie, a redistribution of wealth) , everyone will naturally assume an equal amount of responsibility and work for the common good. You know, the “Star Trek” scenario. Except there’s a reason why we list “Star Trek” in the science fiction section: that’s just not going to happen.

Lots of people are lazy. Lots of people are irresponsible. Lots of people want to skate through life doing as little as possible. Lots of people want others to do their work for them. Lots of people don’t want to work at all. Giving lots of money to people who haven’t earned it and don’t know how to behave in a rational financial sense is essentially the same as putting a five year-old behind the wheel of a car and telling him to go nuts. In other words, you have a recipe for disaster.

The unfairness of this is that in our society, we allow people at the top of the economic and political systems to make bad decisions and get away with it. That’s unfair, and I’m all for reforming that.

But if the problem with capitalism is that it keeps some people behind while allowing some people to have too much power, the problem with socialism is that it never allows anyone to get ahead. Basically, you have the whole system being reduced to the lowest common denominator, and then calling it equality. Which is really where Moore’s thesis is taking us.

Inpex pulled out of the Azadegan oil field project,  onshore western Iran near the border with Iraq and north of the Persian Gulf.  The field is believed to hold 42 billion barrels of oil, and was set to be developed by the Japanese corporation. However, AFP says the company reduced its stake in the venture from 75% to 10% in 2006, and now plans to completely remove from the project.

The U.S. has threatened to sanction companies doing business with Iran due to controversies surrounding the Middle Eastern nation’s nuclear program. Japan has also imposed sanctions on Iran due to the country’s nuclear ambitions.

Still, Russia and China oppose foreign sanctions against Iran and continue to deal with the country. But no surprise there. Russia’s still trying to be the dominant financial influence in the Middle East, and China will do business with anyone pumping petroleum. Heck, the Russian’s on the ones who built Iran’s Bueshehr nuclear power plant. But, seeing as how we started the who Iranian nuclear program in the 1950s, who are we to complain, right?

The ban, which was enacted in the weeks following BP Plc’s Macondo well blowout on April 20 and subsequent oil spill, brought deepwater exploration to halt for nearly six months, with the original plan to keep things locked up until late November.

However, the White House has made a drastic about-face. After five months of complaints from the oil and gas industry that the ban would be devastating to an economy already shaken by a recession, the White House reversed it’s controversial decision on October 12. A welcome return to reason? More likely, the upcoming mid-term elections, in which the possibility that Democrats will be made the whipping boys for a slow economic recovery, forced the administration to switch tactics in order to appeal to voters.

And please, whatever you do, don’t pay attention to the fact that the government’s vague rules for gaining permitting approval still allow for a de facto moratorium to remain in place in practice. This section has been censored to prevent you from putting two-and-two together.

Not that you’re supposed to think about that. It’s election season after all. Let unimportant topics like energy needs keep until 2011. After all, as with voting, dodging the bullet of actually dealing with U.S. energy supply and expanded oil drilling has become another American tradition.

Speaking of Putin, he recently got a little incensed at a press conference when the issue of breaking up former Russian oil company Yukos came up, according to Associated Press.

Putin is trying to spin Russia as a safe haven for foreign investors, but one attendee at a business conference Putin was speaking at got the former president’s ire when he brought up Yukos, an independent Russian oil company whose assets were seized in 2003 in a well-publicized legal battle.

Yukos was a unique Russian oil company for several reasons. Fist, it had several non-Russian (mainly American) corporate executives managing the company. The company had managed to bring in several international investors in the early part of the decade. Also, CEO Mikhail Khodorkovsky wanted the company to have a Western-style financial structure so that it could eventually trade on an American stock exchange.

This all came to a crashing halt in 2003. The Russian government maintained that Yukos was guilty of both theft by privatizing formerly state-owned resources, and also of tax evasion. The second is the most damning charge and the one the prosecution hung it’s case on. As former Yukos CFO Bruce Misamore told me in 2007, Yukos was made a scapegoat by being charge with failing to pay certain taxes, even though it was merely using the same tax incentives that other Russian companies had used.

Misamore said that Khodorkovsky was being punished for opposing Putin’s more state-heavy political views. A liberal, Khodorkovsky did not agree with Putin stocking up the Russian legislature with his former KGB cronies, nor did he like Putin’s political goals of reversing some of previous president Boris Yeltsin’s political reforms in the 1990s. Khodorkovsky was found guilty of tax evasion in a very controversial decision, and was sentenced to 8 years in prison. And by prison, I don’t mean one of those cozy white collar country club prisons like we have in the states. No, I’m talking about a gulag in Siberia.

Try to imagine Jeff Skilling stuck for a decade in frozen tundra. I know, too good to be true.

With Khodorkovsky in the hoosegow, Yukos’ assets were snatched up and disseminated to other Russian oil firms, namely Lukoil and Gazprom. Which brings us back to present. Putin doesn’t want any of that sweet, sweet foreign cash avoiding Russian coffers. But he doesn’t want to admit he hijacked the Russian court system to send a political rival to prison for using a perfectly legal tax deduction. My advice… until Putin’s influence is diluted, keep your money away from Mother Russia.

As for Mikhail Khodorkovsky? *checks* Yup, still in prison on trumped up charges.

“…There’s just not a lot of experience and expertise anywhere in how to complete these wells.”

Bakken oil-play results aren’t readily transferable to the Niobrara oil shale that operators are hotly leasing up and that Wall Street is cautiously optimistic will be the U.S.’ next great oil play. It’s simple, explains Chuck Stanley, president and chief executive of newly public and long-time Rockies-region operator QEP Resources Inc.

“The Bakken is not a shale,” he says in a second-quarter investor conference call. “It is sort of a misnomer.” The Middle Bakken, from which operators are turning in tremendous results, is “a complex carbonate and clastic or sand interval.

“So the Niobrara is a bit unique in that it is a reservoir filled with oil that is a shale and there’s just not a lot of experience and expertise anywhere in how to complete these wells.”

QEP holds 89,000 net acres in the Bakken play and has one rig drilling there. In the Niobrara play, It holds some 64,500 net acres in the Denver-Julesburg Basin and is drilling a Niobrara test there now in southeastern Wyoming.

Stanley notes that Union Pacific Resources drilled successful Niobrara horizontals in the 1980s in the D-J Basin in Silo Field near Cheyenne, Wyoming. “The average recovery per well in that field was roughly 100,000 barrels.”

At the time, however, the wells were not fracture stimulated. “One wonders what those wells would have recovered had they been completed with the current technology—multi-stage fracture-stimulation technology that we apply routinely today to gas shales and/or other reservoirs like the Granite Wash.”

The QEP test that was spud a couple of weeks ago “will be on a Silo Field look-alike, so it will be a structure rather than just being on the margin of the basin where the shale is in the oil window. We’ll have an opportunity to test a horizontal well and modern completion technology in a Silo Field-like setting.”

QEP also holds 50,000 acres in the Powder River Basin that is prospective for Niobrara wet gas. The Sussex and Frontier sands there are also prospective for gas. “A lot of it is held by production or has long-term leases that still have quite a bit of primary term left on them.

“We’re going to focus first on the oil play in the Niobrara to see if it’s a viable play. But it’s so early in this play history. We are not sure what makes the play work and what doesn’t make it work.”

According to UGcenter.com’s Niobrara center, the Niobrara has the potential to be the industry’s next large oil-shale resource play.” Thickness can range from 150 to 1,500 feet thick; porosity from 4% to 14%; total organic content from 1% to 5%; and vitrinite reflectance typically from 0.6 to 0.9.

Ben Dell, senior E&P analyst, says in an OilandGasInvestor.com article, “The reason the debate (over production oil from shale) is so divisive is simple. Of the five unconventional-oil plays identified today––the Bakken, Tuscaloosa, Waskada, Barnett and Niobrara––only the Bakken is currently producing meaningful volumes of oil economically. More importantly, while operators have garnered economic flow rates from the Bakken, the play is essentially not shale, it is a carbonate sandwiched between two shales. As such, it shares few geologic characteristics with the other plays.”

Irene Haas, an E&P analyst and managing director of Cannacord Genuity investment-banking firm, says in the August 2010 Oil and Gas Investor cover story “The Niobrara” that recent new drilling in the formation will improve the amount of information on sweet spots, and if drilling in structured areas is best. “We’ll learn a lot more about this trend in the next 12 months.”

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

Earlier this year, Cameron called the oilsands a “black eye” on Canada, citing images of mining pits as being nearly post-apocalyptic in nature. However, following a recent tour of the areas, Cameron has eased up on the heavier rhetoric, willing to take a more even-keeled approach to the topic.

Cameron told Reuters:

“I don’t see this as black-and-white as I did before I came here. You see pictures of the big holes in the ground and the giant tailings ponds, and you get briefed by environmentalists. It’s a total gloom-and-doom picture and one’s knee-jerk impulse is, well, you’ve got to just stop this. Of course it’s more complex than that. I’m much more appreciative of the boon, the upside of this whole thing in terms of energy independence for North America and all that.”

As a lifelong fan of James Cameron’s work, I’m happy to see him take a more open-minded approach to North American energy production. He still retains a cautious optimism, maintaining there is still potential for negative effects of energy production (and he’s right, there’s always going to be some negative trade-off when it comes to gathering natural resources), but at least he’s a big enough man to admit that he was wrong.

So kudos to you Mr. Cameron. If you won’t make any more knee-jerk comments on the energy industry, I’ll forget that you directed Piranha 2: The Spawning. Fair enough?

But that’s not what oceanographer Ian MacDonald told a Presidential probe on Sept. 27, arguing instead that more than 50% of the total discharge is a highly durable material that resists further dissipation.

MacDonald, who is professor of biological oceanography at Florida State University, was one of the loudest voices questioning BP and the Coast Guard’s data concerning the size of the spill while the Macondo well was still flowing. Now he maintains that some 2.5 million barrels of oil was still embedded in the Gulf ecosystem, out of the estimated 4.9 million barrels that gushed for 87 days before the well was capped.

“”Much of it is now buried in marine and coastal sediments, (and there’s) scant evidence for bacterial degradation of this material prior to burial,” MacDonald added.

So who’s right? Did the oil stay or did it go? MacDonald accuses the NOAA report of lacking critical review. Still, this is a much higher amount of remaining oil than he previously stood behind. Perhaps MacDonald can be accused of padding out his results as well.

Former Trammo Petroleum president Donald Schroeder and oil and gas broker Jonathan Dappen face up to five years in prison after pleading guilty to conspiracy to receive stolen goods after acquiring condensate stolen from Pemex pipelines and routed to Continental Fuels.

As was mentioned in a previous blog, the real danger here is the source of this illicit petroleum. Mexican gangs are illegally tapping into Mexican oil lines and selling the fuel on the black market. Which means Schroeder and Dappen are guilty of funding drug cartels, even if it’s just a small chunk. Which is pretty despicable when you think about it.

But it doesn’t end there.

Prosecutor James McAlister said he did not ask for jail time for either of the men because they were not selling something dangerous, such as drugs or guns. McAlister said Schroeder’s cooperation helped in the prosecution of other defendants in the case. Three other Texas oil executives and brokers arrested in the probe are scheduled for sentencing in October and November.

It’s always funny how criminals will rat each other out for reduced sentences, then blubber about how sorry they were they broke the law. Being sorry doesn’t just mean feeling bad about being caught… there’s usually some sort of penance to be paid here.

Now, I’m happy that we’ve found some American criminals to throw the book at here. But I certainly hope Mexico is capable of cleaning up it’s own country’s messes when it comes to stolen petroleum. God knows they can’t do without the lost revenues.

The main crux of Ahmadinejad’s little spiel during the U.N.’s three-day summit on global poverty was that capitalism was the cause of the world’s misery, and that a new order was needed to fix the world’s problems. American capitalism was pushing for a war between Iran and the U.S., according to Iran’s thief-in-chief, and the U.S. has never faced a threat like that of Iran.

“When has the United States faced a serious war?” the Iranian president asked the council during his . Gee Mahmoud, I don’t know. Why don’t we ask the Germans and Japanese…

But don’t worry, Ahmadinejad promised he isn’t considering attacking the U.S. and it willing to speak with us about how we should just get on board the Iranian train to financial freedom!

As for poverty, German Chancellor Angela Merkel said that free markets worked great and that it was the duty of developing countries to take the lead and push for better economies.

Merkel argued that contributions from the developed world will only work to a point, and that developing countries need to get their own acts together if they’re to succeed in a competitive market.

It was an accurate and well-thought out argument, so naturally Oxfam opposed it.

Spokeswoman Emma Seery said more had been expected from the Germans, who “failed to explain how they will meet their promises of aid to poor countries, and sidestepped their responsibility to make aid work by laying this at the door of the poorest countries.”

So of course the problem with poverty according to Oxfam isn’t due to bad policies of the governments of the poor countries (it never is, they really try their darndest!) such as allowing wealth to be stockpiled between a privileged few and keeping the rest of the country as a permanent peasant class. No, it’s because they rich countries with systems that work just aren’t giving enough. Everybody knows that when you swipe money from countries with stable economies in order to subsidize those that do not have them, you’re perpetuating bad government policy and dragging the working economies down to the lowest common denominator creating economic freedom!

Oh, as for Ahmadinejad’s alternative to the evils of capitalism? Well, he doesn’t really have one. Until then, he’ll keep on collecting money from the production and distribution of oil for profit. Now, what’s it called when you provide goods and services and expect to be compensated for your work?

“Phase 2 begins when the moratorium is lifted [beginning December 1]. This is the period of significant uncertainty and ambiguity as companies try to understand and meet the new regulations, all while the old MMS is being reorganized throughout 2011,” said Hofmeister, the founder of Citizens for Affordable Energy, and author of “Why We Hate the Oil Companies: Straight Talk from an Energy Insider.”

He said there will no doubt be delays in both shallow and deepwater well permitting as the government and the operators try to figure out what the new regs require for full compliance, in terms of additional paperwork, inspections and new equipment.

“Phase 3 is when the first permits are granted under the new specs. NGOs [non-governmental organizations] who are anti-drilling will file lawsuits against the Department of the Interior, much like they already do in the Rockies, to prevent well permits from going forward. The aftermath of the Macondo spill has led these people to believe the government has proved that it is unsafe to drill offshore.”

This phase could last to mid-2012.

“Phase 4 kicks in in June or July 2012, when your old wells in the Gulf of Mexico start to play out, and without enough new drilling to replace them, we see a 1- or 1.5-million-barrel drop in U.S. production. What happens when global demand is expected to go up by then, to 90- or 92 million barrels a day, yet world production is only 83 million, aggravated by this decline in U.S. production?

“The crude price rises. You get $125-$150 oil. What happens to gasoline? You get north of $4 a gallon. What else happens in the summer of 2012? You get a presidential election campaign. Phase 4 of the moratorium is the end of the Obama administration.”

Hofmeister said the BP incident put the president in a no-win situation. The Department of the Interior did not recommend the moratorium, political advisors to the White House did, to appease East Coast and West Coast opponents of offshore drilling. “And think about it–that is where most of the votes are.”

–Leslie Haines, editor-in-chief, Oil and Gas Investor

Oh wait, it’s not for us. The $1 billion will be heading south to fund Pemex’s operations in the Gulf.

The U.S. Export-Import Bank sent $1 billion to Mexico last year to support state-run oil company Pemex’s drilling program in the southern Gulf. The federal agency bank has another $1 billion in store unless Congress puts the stop to it. But of course, it’s hypocritical to say offshore drilling is dangerous and needs further study in our own country, only to turn around and encourage such hazardous behavior in other countries, right? Well, there’s a way around that argument.

The Bank’s activities are not affected by the Obama administration’s ban on offshore drilling because that ban applies only to deepwater drilling–drilling in 500 meters of water or deeper–and the PEMEX projects financed by the Ex-Im Bank are shallow-water projects.

Which is interesting for a couple reasons: first because you would think shallow water would be potentially the most dangerous place to be drilling seeing as how close it is to the shore should an oil spill occur. And the other, funnier reason is because it suggests the U.S. government’s ban on deepwater drilling somehow has an effect on Mexican policy. Mexico can take our money and then drill wherever they feel like. After all, it’s not like our laws against whaling seem to do much to stop Norway or Japan, do they?

This little logic hiccup follows the federal government’s plan to send $2 billion down to Brazil last year to fund THEIR offshore production. Keep in mind that last year at this time, the U.S. government wasn’t even considering offshore drilling beyond the traditional areas because the environmentalists were throwing hissy fits about spoiling the scenery along the Eastern Seaboard. Obama briefly reconsidered this position in early 2010, then the Gulf of Mexico Macondo spill happened and gave every anti-drilling advocate the best early Christmas present imaginable: enough bad PR for the industry to last a generation.

So with such negative hype surrounding offshore drilling, how did Brazil get such a nice chunk of government lagresse? Look no further then our favorite ultra-wealthy progressive, George Soros! Soros invested nearly $900 million in Brazilian national oil company Petrobras, and shortly after that, Uncle Sam got out his check book to help the new South American oil player.

But why does it matter that Soros invests in Petrobras, you might ask? Is he not allowed to send his money where ever he wants? The answer is, of course he is. It’s the American way. But we should be aware of Georgie Boy’s ulterior motives, and in this case it’s that with investments in foreign countries’ oil companies, he stands to gain a lot if they’re leading the way in oil production and America is not.

But once again, how is Soros to blame if he’s just trying to circumvent bad U.S. energy policies? Well, the thing is he’s one of the people trying to write those policies. Soros is one of the biggest financial supporters of progressive think-tank/activist group MoveOn. And what does MoveOn think about oil and gas? See for yourself.

And don’t forget, as was mentioned in a previous blog, the group’s opposition to U.S. Marcellus shale gas drilling coincides with Soros having investments in Indonesian gas operations.

Isn’t that hypocritical for Soros to try to shore up anti-energy sentiment in the U.S. only to financially support it abroad? Or for the Obama administration to be willing to send money abroad to support foreign offshore oil production while panicking about it domestically? Yes, but they really hope you don’t notice that.

Offshore, the national media has moved on from the aftermath of the BP oil spill, but the people of the oil and gas industry cannot. The drilling moratorium is causing havoc. There are close to 10 investigations ongoing about the spill, with stricter regs–and higher costs–to follow. Thankfully, though, the Macondo well is capped. The relief well is down. Damage to the marshes and the fishing and tourism industries appears to be abating, and is not as horrible as once feared. BOEMR director Michael Bromwich has declared that he will do what he thinks is right, regarding the moratorium, even if that does not make the industry happy.

Offshore producers don’t know where they stand. That uncertainty has them, and their investors, worried. You will learn more about it in our October issue cover story. Our editors talked to operators, M&A experts and analysts to survey the outlook.

As an aside, I recently visited George Mitchell, the legendary father of Barnett shale drilling, and the largest shareholder in Devon Energy Corp., which acquired his Mitchell Energy & Development some years ago. Mitchell said he told Devon not to sell all its offshore assets, but to keep a half interest in all of it, “and I told them, let BP prove up the reserves for you.” He sees the value of the Gulf of Mexico, and would not be deterred by recent events.

But people drilling shale leases know where they stand. It’s full speed ahead and damn the low-gas-price torpedoes! Expiring leases in certain shale plays demand their full attention.

Shale lease expirations are an interesting factor to track, according to DrillingInfo’s Ramona Hovey, who spoke at our recent A&D Strategies & Opportunities Conference in Dallas. The leasing frenzy of the last few years will lead to a lot of undrilled acreage coming up for renewal–or top leasing–next year. E&P companies just cannot get to all of it in time, even when they are backed by JV capital from a much-larger partner.

Its all in the timing, and the availability of rigs and frac crews.

It’s about choices, too. Which shale, when, which county? Now that Pennsylvania is allowing production data to be released every six months, we are learning what we wanted to know about the Marcellus shale. A recent study by the Powell Barnett Shale Newsletter indicates that the best wells in the Marcellus yield double the production as the best Barnett shale wells.

In the coming months, we could see rigs leave Texas for the Keystone State, if lease considerations are not preventing that exodus. Low gas prices don’t help.

–Leslie Haines, Editor-in-chief

“Many people talk about developing these shale plays as gas factories,” said Murray Roth, Transform Software and Services, during a kick-off speech for a technical session on North American unconventional gas. “But what we find is there are many different features, often a high degree of faulting and fracturing. If you are drilling a 5,000-foot horizontal, you need seismic.”

Every seat was filled during Roth’s talk, one of numerous technical sessions held simultaneously for the 2,000 attendees.  His particular topic highlighted the differences and similarities of five of North America’s main shale plays: the Barnett, Eagle Ford, Marcellus, Haynesville and Horn River.

Roth noted that the major economic shale plays are generally conformably deposited on carbonate platforms, and are in turn overlain by carbonates or shales. Reservoir thickness is generally 150 to 350 feet. “TOC, mineralogy, fracturing and stresses are the major drivers of gas in place within the shale reservoirs,” he said. 

Another talk by Basim Faraj, of Talisman Energy, focused on the heterogeneity of shales and the importance of natural fractures. “Faults are bad and fractures are good,” he said. Shales are heterogeneous, and microseismic is a critical tool, especially for piloting and for development work. According to Faraj, natural fractures seem to act as loci for creating dense fracture networks during stimulation, and dense fracture networks result in better wells.

Jesse Gilman, SM Energy, gave a talk on the company’s experiences in the Woodford shale in the Arkoma Basin. He highlighted the importance of questioning conventional wisdom, and took the audience through a number of attributes.

Some of SM Energy’s conclusions were quite interesting: thickness of the shale is does not appear to be a critical attribute in the Woodford. The optimal vitrinite reflectance range was higher than originally thought, and temperature gradient maps yielded good predictive results. Finally, drilling near faults made poorer wells than drilling in less disturbed areas.

To improve results, the company uses 3-D seismic to locate faults, and it drills long laterals with many frac stages. And, it lets its poor acreage expire.

“It’s OK to let bad acreage go. To drill a well on sub-average acreage just to hold it and come back later and drill more sub-average wells later on is foolish and a path to financial ruin,” said Gilman. “These are not simple, flat black, work-everywhere plays and they require geologic thinking.”  

by Peggy Williams,

Director, Unconventional Resources

pwilliams@hartenergy.com

The data collected will be part of a scientific study conducted by the EPA, whom Congress in 2009 directed to conduct to determine whether hydraulic fracturing has an impact on drinking water and public health of those living near hydraulic fracturing sites.

In making the requests of the nine leading national and regional hydraulic fracturing service providers – BJ Services, Complete Production Services, Halliburton, Key Energy Services, Patterson-UTI, PRC, Inc., Schlumberger, Superior Well Services, and Weatherford – EPA is seeking information on the chemical composition of fluids used in the hydraulic fracturing process, data on the impacts of the chemicals on human health and the environment, standard operating procedures at their hydraulic fracturing sites and the locations of sites where fracturing has been conducted.

Fortunately, this process is being conducted by the federal government and not private industry, so we should expect a response sometime between now and the next ice age. Okay okay, they promise to have the study done by 2012… just in time for the presidential election! Funny how that sort of thing works out.

All joking aside, the EPA is right to request such data, and it would be in the best interest of the companies listed to comply. Coming for a city whose river once caught on fire, I can certainly understand the need for safe drinking water. It certainly will help stave off some of the negative comments being thrown around to vilify the drilling and E&P industries. I doubt we can expect an Oscar-winning films about industry acting properly.

In the editorial, Alex Epstein said that former president Nixon’s reaction to the spill offshore California ultimately led to the country’s energy crisis in 1973 and has lasting impact to this day. At the time, the U.S. was preparing to open up Prudhoe Bay offshore Alaska, which was expected to add 1.5 million barrels per day to U.S. production. However, following the California spill, Nixon reacted by punishing oil producers, reducing offshore drilling and tainting the procedure for decades to come.

Nixon signed a moratorium on offshore drilling, created government agencies that allowed environmentalist to oppose drilling in “environmentally sensitive” areas and left the U.S. more dependent on foreign producers. OPEC eventually used its clout to increase its political influence throughout the world. It was only after people had to wait in line up to two hours for gasoline following the 1973 embargo that Nixon finally caved in, allowing the Alaska pipeline, but that oil unfortunately did not come to market until 1977.

Starting to sound a little familiar? The Obama administration, taking a page from Tricky Dick’s playbook, has ramped up government oversight, put the deepwater Gulf on standstill until November and has given the anti-drilling crowd political capital to further demonize the industry.

No one’s saying that actions didn’t need to be taken. A short-term moratorium, while hurtful, might not have been out of question during either the 1969 spill of the more recent one. And of course the government has the right to inspect things once crude oil starts interfering with your surfing competitions. But Obama should take a page from history and learn just what happens when you allow short-term environmental disasters to cause longer-term ones on the economy.

“As far as I can see…none will materialize….”

A global natural-gas cartel has yet to materialize, “and as far as I can see—the next five years—none will materialize for various reasons,” says Tom Petrie, vice chairman, Bank of America Merrill Lynch. OPEC controls a great deal of global oil supply—adding or curtailing crude oil onto the market as demand-driven prices wax and wane.

Several years ago, discussion reignited around a “natural gas cartel,” with Qatar and other prodigious gas producers at the top of the conversation. Qatar has practically zero production costs, plus proven reliability and hefty supply.

“The (gas) demand growth is really the issue,” says Petrie, speaking to attendees at the ninth annual A&D Strategies and Opportunities conference, hosted by Oil and Gas Investor and A&D Watch.

U.S. producers have proven they can make more natural gas from the U.S subsurface and for a hundred years, at least, working the unconventional resources that range from the original shale play—the Barnett—to the Marcellus, Eagle Ford, Haynesville, Woodford and Canadian shale’s too.

An advocate of greater dependence on indigenous U.S. natural gas and reduced dependence on crude oil for transportation is wildcatter Boone Pickens. Boone “is on the germ of a good idea…I think the problem (in Washington) is it’s Boone’s idea and not Washington’s,” Petrie says.

If there is a successful effort to increase the use of natural gas—and decrease the use of crude oil—for transportation fuel, “one could see over two decades a period a powerful impact,” Petrie says.

Meanwhile, in the U.S., coal will continue to compete with natural gas as a source of electric-power generation. “It is easier to be bullish, longer term, on crude than any other energy commodity…(Its) role as a transport fuel is not threatened in any meaningful way for decades.”

And, for those in pursuit of unconventional gas resources in North America, “one has to believe (gas) prices have to be higher.”

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

Also see http://www.oilandgasinvestor.com/Headlines/2010/WebSeptember/item66870.php and http://www.oilandgasinvestor.com/Headlines/2009/WebMarch/item31683.php.

Bill Marko: “They were the natural buyers. They’re not in that game anymore.”

Where have all the serial acquirers gone? To big-money unconventional-resource plays where many start-up, private-equity-funded E&Ps can’t handle the long-development-time, negative-cash-flow stories in their business models.

Just a few years ago, a start-up could plan an exit in a few years—or less, at times—to Chesapeake Energy Corp., XTO Energy Inc. and other avid buyers of proven, held-by-production acreage that just needed more wells to become easily meaningful to the public-company portfolio’s investors, who are focused on reserve and production replacement and growth.

Most of the serial acquirers are busy now with their existing unconventional-resource portfolios, says Bill Marko, a managing director for Jefferies & Co. Inc. They’re not buying conventional-asset packages. Chesapeake Energy Corp. is JV’ing, instead. XTO is now a business unit of ExxonMobil Corp. and, while former president Vaughn Vennerberg says XTO continues to look at bolt-on acquisitions, its focused is on unconventional properties.

“They were the natural buyers. They’re not in that game anymore,” Marko says. In the early 2000s, a start-up could build a package, and sell it in a few years. “Raise $50 million of private equity and build a $200-million company, and successfully sell it to Chesapeake, XTO and some of the other (larger, public) E&Ps.”

No more, for now. Instead, conventional-asset-focused, private-equity-funded E&Ps are targets of roll-up E&Ps that have their exit set on the IPO market, instead.

“This has fundamentally changed the private-equity model as the built-in exit to XTO, Chesapeake and others has disappeared. New acquirers are and will emerge, perhaps with more focus toward IPO or acquisitions-focused policies.”

Marko expects both more unconventional and conventional oil and gas assets will come onto the market, as unconventional-focused players seek to raise the $1.5 trillion he estimates is needed to develop North American shale plays during the next 30 years.

“Average that out and it’s about $50 billion a year.”

Equity and debt markets are open to producers seeking capital, and selling conventional assets is another fund-raising option. “But the two combined are not going to be enough to raise the money that’s needed to do all these developments. In the first five to eight years of a major development, there is a time period where you’re cash-flow negative and it is non-self-funding, so you have to raise money from outside sources to develop these plays.”

Owners of unconventional-resource plays are turning to the joint-venture market to provide cash for drilling and to hold acreage. “The market is really parsing into two groups: You have the shale-focused players and the conventional-focused players. I think there’s room for everybody.”

The shale-resource E&Ps have 5-, 10- and 20-year development horizons and the conventional-asset E&Ps may have a two-, three, five- or 10-year horizon.

“You will continue to see deal flow on the resource-focused side and add a lot more conventional assets on the market. Many of the larger companies are seriously focusing on shale-resource plays—Encana Corp., Chesapeake, Devon Energy Corp., Petrohawk Energy Corp. They’ve all done big transformations of their portfolios, some quicker than others, but they’ve been very consistent in their focus.”

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

The Environmental Protection Agency launched an art contest this week aimed at Native Americans youth that encourages children to illustrate what they perceive as environmental crimes.

The contest, open to all middle and high school students who are members of a federally recognized tribe, is a chance for young people to draw their visions of environmental damage from their viewpoint. EPA will use the winning artwork on its website and on posters encouraging the reporting of environmental violations.

Now, far be it for me to discourage the condemnation of crimes, but seriously? I believe in being a good steward of the land and what not, but must we continually treat pollution as though it’s some sort of horrible affront to nature? Plus, involving kids in something like this…

“The artwork will be judged on creativity, originality and how well it depicts the message of environmental violations.”

Look, it seems innocent on the surface, but just what is going to be accomplished here besides knee-jerk anti-industry tripe? Yeah, I know we’re supposed to think “from the mouths of babes” and whatnot, but that’s a lot of hooey. I remember being a teenager: they don’t have any complex understanding about the economic realities of business. This is purely an appeal to the emotion: the most in depth drawing we’re sure to get will be a unicorn crying over an oil spill and things of that nature.

Which brings me to the film “WUSA,” a strange curio from 1970 starring Paul Newman and real-life wife Joanne Woodward about a right-wing radio station in New Orleans named WUSA involved in shady shenanigans and culimates in a hatefest that’s being disguised as a political rally. Along the way Anthony Perkins shows up as a do-gooder social worker whose been duped into gathering information about welfare abusers which will be used as political ammunition against their opponents. While watching the movie, which is filled with dripping condemnation for conservative blowhards espousing the need to return the country to its roots, I couldn’t help but compare this film’s message on right-wing politics to that of conservative news commentator Glenn Beck’s recent rally in Washington, DC, which his detractors have tried to paint as some sort of racist rally.

And you know what? “WUSA” is full of crap.

I could condemn the movie for its meandering plot, or the fact that morally ambiguous main character Newman, playing radio show host Rheinhardt, never really becomes more then just a cipher despite the film’s two-hour running time, that even the supposed heroes are so bland or self-righteous you want to punch them or that the movie mistakes being cryptic about its messages with being subtle and thoughtful.

But instead, as I watched the movie unfold, I couldn’t help but realize that the vision of right-wing broadcasting that this film seems to have is matched by the views that the most vocal critics of the whole Tea Party movement seem to scream about today: that under the guise of patriotism, racism is the real motivating factor behind conservative ideology.

Now of course, I’m not blind to the fact that a lot of racists have jumped on the Tea Party bandwagon. I’ll even spot the opposition the argument that it seems highly suspect that this movement waited until a Democrat was in the White House to suddenly show disdain with government spending run amok, seeing as how George W. Bush never met spending bill he didn’t like.

But the Huffington Post crowd’s attempts to paint a whole movement as some sort of Klan rally is disheartening at the very least, and eerily hateful at its worst.

Getting back to Newman’s nearly forgotten opus, I’d have to say that the world this movie seems to show as fact is thankfully that which only exists in the minds of our most paranoid society members. Of course, that’s if you can really decipher the film’s message at all. Almost all the film’s arguments seem to be delivered by second- and third-hand sources. We never really see any of these shady political goings-on that are supposed to be happening, though some cops show up to threaten Perkins at one point.

When the movie ends with Perkins and Woodward’s deaths (hope I didn’t spoil that for you), Newman is left to leave the Crescent City with a cinematically unearned sense of despair about the nature of things, returning to his near-meaningless travels in the world as a self-described “survivor.” Even Roger Ebert came to despise this sort of movie ending. In his review of Stanley Kramer’s equally obnoxious “Bless the Beasts and The Children,” Ebert said:

I’m getting a little sick of movies that end gratuitously with the Old shooting the Young to give us the impression that a point has been made. I left the theater in a nasty mood.”

I suppose if the film had bothered to actually show some of the evil speeches he supposedly was forced to deliver over the radio (which we for odd reasons never get to see) we might have had a greater understanding of his wounded spirit. But the movie doesn’t even directly address the evil arguments the villains of the piece are supposed to be doing. I guess we’re just supposed to figure it out for ourselves.

You know, I would have respected this movie it it had at least have had the guts to point fingers at specific arguments. Yeah, it would have dated the movie like other films from that era such as “R.P.M.,” “The Strawberry Statement” and “The Harrad Experiment,” but at least it would have been a more politically honest story.

We are left with a pipe dream about some evil right-wing conspiracy trying to do, well, something evil. That’s about the level of argument you get these days from folks like Al Sharpton and “The Daily Show’s” John Stewart, who spent last weekend clutching at straws trying to find something truly evil in Beck’s rally. The best argument they got was the timing, which coincided with the anniversary of Martin Luther King’s “I Have A Dream” speech.

So what is there to learn from “WUSA”? Sadly, very little from either side of the political aisle. Rheinhardt is no Glenn Beck, and FOX News certainly isn’t WUSA. I guess the ultimate message is conservatism wishes destroy us all… that’s a message I can’t very well stomach.

* A transformation is under way in the U.S. land-drilling business, said Mark Siegel, chairman and director, Patterson-UTI Energy Inc.  More than 65% of new wells are horizontal or directional. The preferred equipment for resource-play wells are rigs with 1,000+ horsepower drawworks, high-capacity mud pumps and top drives. Patterson currently has 105 rigs active in U.S. unconventional plays.

* Customer demand for rigs capable of drilling resource plays remains strong enough to support term contracts, said Siegel. Favorable trends are likely to persist, both in the oil and gas market, and more so in the oil and liquids plays.

* The current Gulf of Mexico environment is not a pretty picture, said Seahawk Drilling Inc. president and chief executive Randy Stilley. The federal NTL 6 regulations issued June 18 caught the entire industry by surprise. “We had been given signals from the Department of Interior that it would be aimed primarily at deepwater drilling; it turns out it applies to everything.” The new regulations require operators to include worst-case discharge scenarios for all new drilling permit applications.

* Only three new GOM drilling permits have been issued since the Macondo blowout. In the GOM jack-up market, companies have 34 cold-stacked and non-marketed rigs. It’s likely that additional rigs will migrate out of the U.S. in the next 12 months, said Stilley, “There is demand out there, but we need drilling permits.”

* International drilling is at a low point. The number of tenders is increasing, but customers are still not moving forward. “The recovery from the 2009 decline in E&P spending has been slow,” said Parker Drilling’s Dave Mannon, president and chief executive.  

* Extended-reach drilling will continue to increase. It provides the capability of developing offshore reserves from a land environment. Mannon mentioned that new areas where extended-reach drilling is being considered include the northern flanks of Arctic Russia and Amazon delta of Brazil.

* Three decades ago, international oil companies accounted for the majority of international drilling. Today, national oil companies account for 80% of international drilling. That means international majors have to look at areas where technical competencies and technical initiatives enable them to obtain concessions, said Mannon.

by Peggy Williams, Director, Unconventional Resources

pwilliams@hartenergy.com

The rig had been under contract to Petrosucre, a subsidiary of Venezuelan national oil company PDVSA, until Ensco terminated the contract for non-payment in June 2009. Petrosucre responded that it would continue to operate the rig without Ensco’s consent. After more than a year of occupying the rig, Ensco personnel were allowed to retrieve it and it is now stationed in Trinidad.

There’s an expression for when you take something that doesn’t belong to you: I believe it’s called stealing nationalizing private assets. Now as any Hollywood type will tell you, of course PDVSA has the right to not pay for the use of a vessel it signed a contract to utilize. Only evil capitalists honor financial commitments.

In a strange irony, anti-drilling advocates, who are often scoffed at by hydrocarbon supporters as being Rousseau-lite neo-primitives who want to switch the world back to a pre-Industrial setting, have swung the conversation around and argued that it is in fact the producers of oil and gas who are stuck in the past.

David Suzuki and Faisal Moola wrote:

Our earliest advances were based on burning wood or dung for fuel. Now we’re still using our paleolithic trick, burning decayed organic materials in the form of fossil fuels. Isn’t it time we moved on? We are far too numerous — and the impacts of our actions far too great — to keep on acting like cavemen. It seems to me that those who criticize us, the anti-environmentalists, are the ones who want to turn their back on their future so that they can just go on burning stuff.

Since debasing your opponents is a cheap ad hominem fallacy attack the only way to win an argument concerning the “big issues,” Suzuki and Moola feel that the best way to challenge their critics is to take to task their obvious ulterior motives for using oil and gas. Namely, desiring to destroy the planet.

Using all the careful logic and mental gymnastics of a typical “Captain Planet” cartoon, the eco-villains just want to run the planet into the ground in the name of the Almighty dollar.

Our human history is one of change, of coming up with new ideas and new technologies to meet the challenges of allocating resources to growing populations. As environmentalists, we embrace change for the better. But our critics want us to remain stuck in a time that has no future. They reject progress, arguing that we should keep on our destructive way, with outmoded technologies and energy sources.

The all-encompassing “they,” meaning people who make a living pulling oil and gas out of the ground, are clearly a threat to  Suzuki and Moola’s worldview, but just what are their alternative ideas?

A better world for us, our children, and our grandchildren is possible. Just as we’re seeing evidence of the damage caused by climate change today, we’re also seeing innovative ideas being applied to the problems. Many scientists, economists, environmentalists, business people, and citizens are proposing and implementing solutions. Their work is not only offering hope in the face of the catastrophic effects of climate change, it’s also offering hope for faltering economies by ushering in new technologies to replace the jobs and technologies that are becoming obsolete as supplies of polluting fossil fuels become scarce.

There some other bugaboos here and there about solar, wind and other renewable, but nothing concrete. This is a sermon, nothing more. We get no substantial argument about what innovations have been made to get us off of oil, only that “solar, wind, and tidal power” will help us with “advanced ways of thinking about our relationship with nature.” Once again, natural gas remains conspicuously absent from the conversation, instead we’re left having to extrapolate that harnessing the power of the waves will somehow move our cars down the street.

Suzukia and Moola might as well throw dilithium crystals and hyperspace drive warps into the mix while we’re at it (apologies to Star Wars and Star Trek fans for mentioning both in the same sentence, I know your geek brains just exploded from overstimulus.)

Basically, it’s another black-and-white take on the energy industry. The authors argue that traditional energy producers are callous toward the environment, motivated only by greed and lazy adherence to “the past.” The funny thing is, what they consider the past is a system that has been in place for only a little more than a century. The real past is this Henry David Thoreau gibberish they keep spouting about how new innovation can lead us to a brighter path, without once providing a single instance of a practical new technology that can replace our existing ones.

To the authors’ credit, they do acknowledge that there’s too many people in the world to revert back to wood burning, so that places them above most of the environmentalists who take a Malthusian outlook on the population.  Still, we remain on dangerous ground when they keep arguing that new technology is just out there waiting to be used, but oil companies are just too lazy to consider real, practical alternatives, whatever they may be.

This phantom technology the authors speak of might as well be Unobtainium from “Avatar,” because I doubt we’re ready to switch our cars over to unicorn giggles just yet.

In spite of reduced natural gas prices, shale plays dominated many conversations at the expo.

“We’re shooting lots of seismic right now, in anything that is a shale,” one service provider said during the expo luncheon. “With this country’s energy needs, and how much companies have already invested in the shale plays, it’s obvious that a good portion of the industry knows that we can’t completely give up on gas prices in 2011/2012.”

The Marcellus shale is one of the plays that has stayed in the spotlight for several consecutive quarters, but has the land grab finally peaked?

“A&D deals are harder to get done in the Marcellus now, although it’s still a hot area for development activity,” said a vice president of a Houston-based energy-lending firm. “Even though the area has still got plenty of eyeballs on it, it’s getting harder to find an A&D deal there that has all the right components in place at the same time.

“On the development side—as with any shale play that has its cycles—it will be really interesting to watch things play out in the Marcellus. Now that so much of the acreage has been acquired, there are questions about how it’s going to get drilled without running a bunch of rigs, most of which are already tied up drilling shale acreage.”

Though many industry watchers opt to also attend the larger version of the expo in the winter, several attendees appreciated the more intimate feel of this year’s summer show.

“It can be more difficult to get really good foot traffic when more of the bigger independents are here with booths,” one Tyler, Texas-based landman explained. “Summer NAPE gives the smaller guys a chance to take advantage of having all eyes on them. In a matter of hours, we’ve had substantial interest in our Haynesville leases, and we’re encouraged by the number of ‘sold’ signs that have already gone up.”

“This is a show that really let’s you talk to people, because folks don’t spend the entire time hunting down execs,” added a Dallas-based landman. “You don’t get as worn out as quickly as you do during the winter show. And that’s a good thing when there’s plenty of serious interest and available capital in the room.”

On the capital side, while many financial representatives walked the floor, only 13 firms had booths, just about one-third of the number present at winter shows in recent years.

“It’s still pretty hard to get anything done now on the conventional gas side, and it looks like it may be that way for a while yet,” one corporate energy lender confirmed. “Oil is where the real opportunities are.”

For more insight on the 2011 oil and gas outlook and the capital landscape, look for upcoming one-on-one video interviews from the show floor with Brian Lidsky, managing director of M1 Energy Capital in Houston, and Alec Neville, manager of Dallas-based PetroCap.

–Bertie Taylor, Senior Editor, Oil and Gas Investor, btaylor@hartenergy.com, 713-260-6497.

Vincent added that a good many environmental supporters are well-meaning and not influenced by ulterior motives, sincere in their desires to lessen mankind’s impact on the planet. But he said they act out of misguided and poorly conceived agendas.

On the other hand, pointing his fingers at groups like MoveOn.org and former U.S. vice president Al Gore’s entourage, Vincent said that organizations that seem to be the most against traditional U.S. energy sources tend to have their own long-term agendas while hoping to ride on public ignorance and distrust of the energy industry.

Vincent said, “Al Gore’s goal with ‘An Inconvenient Truth’ wasn’t to make money in the movie theater or win a Nobel Prize. It was to raise support for his constituent’s businesses.”

Gore was shoring up support for green technologies that were being designed by his constituents, including GE which is one of the major fabricators of the giant windmills being championed by the wind industry, according to Vincent. The money Gore made releasing his film was minimal compared to the amount he and his supporters stood to gain should major U.S. legislation be passed encouraging wind power technology development.

As for MoveOn.org, Vincent said the left-wing activist group has been active in the state of New York, spreading negative information about shale drilling concerning fracing and water issues related to shale gas production in order to prevent Marcellus production from heading north of Pennsylvania.

The interesting story behind this, according to Vincent, is that one of MoveOn’s biggest financial backers is billionaire investor George Soros, who is one of the shareholders in Papua New Guinea-focused E&P company InterOil. InterOil made headlines last year with its Antelope-2 well which tested at a world-record daily rate of 705 million cubic feet of gas and 11,200 barrels of condensate on Dec. 1.

Like a lot of companies with gas operations based in foreign countries, InterOil was hoping to benefit from selling gas to the U.S. market as LNG. The presence of shale gas in the U.S., however, lessens America’s need to import foreign gas supplies.

Therefore, Vincent said the Marcellus is harmful to InterOil’s bottom line, and places Soros in a position of needing to trash shale gas production through MoveOn for hidden business purposes while trying to appear altruistic and pro-environment on the surface.

Finally, Vincent launched into the activist documentary film “GasLand” released earlier this year, which focuses on the supposed dangers of allowing fracture drilling near communities in Pennsylvania and elsewhere. Vincent said the film is filled with numerous inaccuracies such as a scene where a resident displays that he has flammable drinking water coming out of his facet, an occurrence Vincent said was due to coal seams leaking into the water source, not gas.

Anti-drilling and anti-fossil fuel activists have made a good job of trying to scare residents against shale drilling by playing up the narrative of a “new and unknown” process to the public, trying to turn fracture drilling into a bogeyman that wants to kill them. The reason why they’re winning the debate, Vincent said, is due to a lack energy industry response to such baseless accusations with the same frequency and drive as the anti-industry proponents that make them.

He said that energy producers will always have to deal with–as part of the business–both irrational distrust of the industry by the public and vitriolic hated by those with an agenda against drilling. The best way to combat distrust and silence critics is for the industry to maintain a steady public education policy and make sure local residents understand the care the industry takes to avoid polluting the environment.

Vincent said, “It’s imperative that shale producers continue grass roots campaigns in the local community.”

The bill (S. 3663 aka The Clean Energy Jobs and Oil Company Accountability Act of 2010) was championed by Reid and seeks to introduce laws raising the $75-million cap on fines for offshore oil spills to an unlimited amount and extend the federal approval process from offshore E&P plans from 30 days to 90 days which can be increased an additional 180 days at the U.S. Interior Secretary’s discretion.

The bill failed to garner support in the Democratic-controlled Senate, though that didn’t prevent Reid from turning his ire to the opposition.

“”It’s a sad day when you can’t find a handful of Republicans to support a bill that would create 70,000 clean-energy jobs, hold BP accountable, and look at a future as it relates to what BP did. It’s clear that Republicans remain determined to stand in the way of everything,” the four-term legislator said.

Perhaps if Mr. Reid hadn’t have been in such a rush to throw a poorly conceived bill on the floor, he might have gotten more support from his party. But heck, it’s an election year for Reid, we have to say we tried, right?

Naturally, opponents of the bill in the energy industry were happy to see Reid’s legislation get put on hold.

American Petroleum Institute president and chief executive Jack Gerard said, “The bill proposed by the Democratic leadership is not an effective or reasoned response to the spill. Instead it will cost American jobs, threaten our fragile economic recovery and jeopardize our energy security.”

The removal of the cap on oil spill liability would, according to Gerard, force most E&Ps out of the Gulf of Mexico because they would be unable to purchase the necessary insurance to operate in the region.

The IPAA issued a Washington Report on Aug. 5 praising the Senate bill being placed on hold, while also criticizing the passage of the similar CLEAR Act in the U.S. House of Representatives.

The IPAA agree with the API’s view on eliminating the cap on spill damage. The report states:

“According to a recent IHS study, independent producers account for more than half of offshore jobs. Removing these caps puts those jobs and a considerable amount of offshore energy production at risk. Passage of this section would ultimately result in only super majors and national oil companies producing America’s offshore resources.”

Other portions of the bill the IPAA disapproved of include the vague language used to explain the amendments to the National Policy for the Outer Continental Shelf. The IPAA speculates that these statutes in question present opportunities to challenge virtually any administrative decision and opens them to endless litigation and appeal.

With the House passing a similar bill and the current one just being put on the back burner for a  month, it’s clear that Congress is dead set on revising offshore drilling regulation. The Macondo oil spill stirred up the hornets’ nest, and to be frank, deservedly so as far as BP’s safety record goes, but the problem now is a lot of poorly conceived legislation is in danger of being rushed through Congress in order to (1) give the appearence that Congress is in control of the situation, (2) appeal to wacko anti-business interests who view oil drilling as a sin against the Goddess Gaea (ie, Reid’s base) and (3) get PR-building good press for Senators and Congressmen facing the dreaded mid-term election coming up in November.

For the time being, we can take some comfort that there are checks to prevent some poorly conceived legislation from just strolling through the vetting process, but come late October and nothing’s been signed, you can bet something will be ready to run through Congress, well written or not.

Plus, More Details On Chesapeake And EOG’s Shifts In Emphasis To Liquids

If major U.S. gas producers increase their capex emphasis on drilling for oil, natural gas supply should fall as well as oilfield-service costs, resulting in improved gas prices and an improved profit margin too for players who tough it out.

But that won’t happen—at least not soon—according to Dave Pursell, managing director and head of macro research for Tudor, Pickering, Holt & Co. Securities Inc.

Pursell and the TPH team of analysts slashed their gas-price forecast today to $4.50 Nymex for second-half 2010 (from $6.50) and to $5 for 2011-2012 (from $6.50), drastically below the Wall Street commodity-price-forecast consensus and even the Nymex strip itself. Their 2013-and-beyond forecast is now $6 (down from $6.50).

Pursell says that, while producers are increasingly stating a shift in drilling emphasis from gas to oil, “independents cannot shift capex quickly enough…Gas production—in our coverage universe—is still expected to grow 10% year over year in 2010 and 16% in 2011.”

He adds that producers are taking 2011 hedges at between $5 and 5.50, “signaling a willingness to continue to invest at those levels.” Many of them plan to outspend cash flow. And, he notes “the realities of above-average storage levels, the stubbornly resilient gas-directed rig count and the corresponding production growth that is resulting from record horizontal drilling.”

Gas producers’ stock prices are experiencing “shale exhaustion.”

“Bottom line: This industry is drunk on shale liquor and can’t get sober fast enough to avoid a low-commodity-price hangover. In 2010, our coverage universe will spend $52 billion compared with $37 billion in 2009…In 2011, spending is targeted at $57 billion.”

Two major U.S. gas producers are reducing shale-gas spending. Chesapeake Energy Corp. stated last week that its emphasis will be a weighting to liquids by 2012. Also, EOG Resources Inc. now expects its 70%-natural-gas production profile of 2008 will be reversed to 70% liquids by 2012.

Chesapeake can move a gas market. It produces 2.8 billion cubic feet equivalent per day, 90% gas. It plans to take $400 million of capex planned for gas projects in 2011 and spend it on drilling for liquids instead. Operated net drilling and completion capex on liquids plays will grow from 13% of Chesapeake’s total 2008 capex budget to approximately 55% in 2012.

Going forward, at sub-$6 gas, it plans to drill gas wells only to hold acreage or if being carried by a drilling partner.

Meanwhile, EOG Resources Inc. reports it’s unlikely to increase its projected North American gas volumes if a gas-price recovery occurs. It expects its 2012 production of 70% liquids will consist 75% of crude oil and condensate, 25% natural gas liquids (NGLs).

Mark Papa, EOG chairman and chief executive, suggests noting whether a company’s increase liquids production is oil or NGLs. “…As other E&P companies have subsequently proclaimed themselves to be ‘liquids rich,’ the distinction between crude oil and lower-valued NGLs seem to have been blurred.”

Regarding NGLs, Pursell says, “We expect regional pricing dislocations driven by E&Ps chasing liquids-rich plays that will result in continued pressure on natural gas liquids as a percentage of crude oil prices. (Second-quarter) NGL realizations have dropped from 50% of crude (2009) to 47% of crude (2010).” The price may be 40% of crude in this quarter, he adds.

For gas-weighted producers, there is one hope: Since the TPH analysts erred on the side of bullish gas-price expectations a year ago for 2010 ($7.50, revised in May to $6.20), their slashing today to far below Wall Street consensus, and even the strip, may reverse the curse and push prices higher.

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

EOG Package To Further Test Market By Year-End

Appalachia’s prized Marcellus shale play may take on yet more shine as offshore producers and investors balk at what the Obama administration’s new rules for Gulf of Mexico E&P may be.

One executive of a privately held, onshore-focused, unconventional-resource E&P says the politically unstable, and potentially more costly, Gulf investment environment will push onshore U.S. property values upward.

“I think anyone who is involved in the Gulf, especially if the government removes the liability cap…there may be midsize independents that might say ‘Maybe we will continue to play in the Gulf, but let’s look harder onshore and see what’s available.’ I think we’re seeing that right now,” he says.

The Marcellus and the liquids-rich Eagle Ford in South Texas have been attracting the most brow-raising deal-making this year, in addition to continuing asset shifts in the Haynesville, activity in the Bakken/Three Forks play, and cease-less transactions in the Permian.

Last week, the price for Marcellus grew further, with India’s Reliance Industries Ltd. paying $327 million for Avista Capital Partners’ 52,200 net acres of leasehold in Pennsylvania and $65 million for 20% of Carrizo Oil & Gas Inc.’s other 52,200 net acres in the total 104,400-net-acre Avista/Carrizo joint venture. The sale represents Avista’s exit from the Pennsylvania acreage but it continues a co-shareholding with Carrizo in West Virginia and New York acreage prospective for Marcellus.

Earlier this year, Reliance paid $1.7 billion to JV with Atlas Energy Inc. in the Marcellus and $1.3 billion to JV with Pioneer Natural Resources Co. in the Eagle Ford.

The Marcellus deal with Avista represents some $6,300 an acre for Marcellus.

Speculation is high that more private-equity-funded Marcellus-focused E&Ps will be grabbed up since Shell Oil Co. paid $4.7 billion in cash in May for East Resources Inc.’s 1 million net acres (650,000 of these are over Marcellus), making 60 million cubic feet equivalent per day. East had received private-equity funding from Kohlberg Kravis Roberts only a year earlier.

A leading Marcellus player says he could see that coming: “There were so many sales and joint ventures preceding the East sale, so it was clear there was quite an appetite, and East was able to sell for a future value at a price everyone was happy with.”

Another test of the price players are willing to pay for Marcellus will come by year-end with bids for EOG Resources Inc.’s Appalachian package. The producer is offering 180,000 acres of shale-gas acreage there and in the Haynesville, and the liquids-rich Eagle Ford.

Mark Papa, EOG chairman and chief executive, says, “We considered a joint venture (in) this acreage, but decided on an outright sale because it’s cleaner and less complicated. This acreage package is larger than we contemplated three months ago. We spent about $1.7 billion over the last few years accumulating first-mover, horizontal, shale acreage, and frankly, we have more good acreage now than we can say grace over, given our manpower and capital-structure plans.

“So we’re going to monetize a bit of this acreage.”

EOG’s divestments there and in Canadian shallow, conventional gas properties are towards retaining a net debt-to-cap ratio of 25% or less through 2012.

More Marcellus acreage on the market is privately listed. Asset marketers expect deal-making in the shale to continue to post headline-making numbers.

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

Next up, California-based BNK Petroleum plans to drill a pilot on its Slawno concession. Final engineering design for the #1 Slawno well has been completed and BNK is preparing the drilling permit.

And in 2011, Talisman Energy of Calgary will likely drill on the licenses it farmed into with San Leon Energy. At present, the operator is looking for a drilling rig. Under the terms of its agreement, Talisman has committed to acquire seismic and drill three wells, one on each of the Gdansk W, Braniewo and Szczawno concessions. At least one well will feature a 1,000-meter lateral.

Exploration targets are Ordovician, Silurian and Cambrian shales.

by Peggy Williams

pwilliams@hartenergy.com

• 85% said their organization currently has an enterprise-wide climate change program or will launch one in the next 12 months.
• 80% expect climate change spending to increase between 2010 and 2012.
• 90% communicate greenhouse gas or carbon emissions data in an annual corporate social responsibility or sustainability reports.
• 72% of those have greenhouse gas or carbon data verified by an independent third party.
• Across the board, O&G companies are launching climate change initiatives to
  • generate new revenue opportunities,
  • respond to competitive threats,
  • respond to customer demand,
  • preserve and protect the company brand, and
  • reduce energy and carbon costs and prevent regulatory fines or penalties.

Herb Listen, the author of this report, is the the climate change and sustainability lead in Ernst & Young’s O&G Center. Access the full report at www.ey.com/ccassexecutivesurvey.

Anadarko Chief Adds, “What We Have Learned In The Past Few Months Causes Us Great Concern.”

John Hofmeister, former Shell Oil Co. president and founder of Citizens for Affordable Energy, says President Obama’s moratorium on offshore drilling will result in higher gasoline prices—and soon. “In 2012, when the pump price is $5, Mr. President, your administration and all of your dreams are toast,” Hofmeister warned today at the Rally for Economic Survival in Lafayette, Louisiana, protesting Obama’s offshore drilling moratorium.

More than 12,000 people gathered mid-day at the Cajundome to hear and contribute to more than two hours of messages for Washington from speakers ranging from the wife of an oilfield worker and mother of six children to Louisiana Gov. Bobby Jindal. The crowd consisted of business owners, out-of-work oilfield workers, and other voters. The program began with 93 seconds of silence for the 11 workers who were killed at the Macondo wellsite.

Jim Funk, president and chief executive of the Louisiana Restaurant Association, buttered Hofmeister’s toast metaphor. “We could have burnt toast today in honor of someone in the White House,” he said, drawing one of many dome-raising cheers of the day.

Jindal said Obama suggested in one meeting with him that affected Louisiana energy-industry workers take checks from BP Plc to survive the six-month moratorium. And, if not from BP, then they could take unemployment checks. Jindal said he told Obama, “We don’t want a BP check or an unemployment check. We want to go back to work.”

Chants from the audience included “Drill, baby, drill!,” “Let us go back to work!” and “Lift the ban!” Some speakers repeated phrases in their messages in French, the favored (although fading, due to early 20th century efforts by Washington to Americanize the indigenous French culture) language of South Louisiana.

Don Briggs, president of the Louisiana Oil & Gas Association, which organized the rally along with the Lafayette Chamber of Commerce and supporting organizations, quoted Andrew Jackson: “Where one man has courage, he makes a majority.” Briggs said, “Today, we’ve had 12,000 people make a majority.” Another 3,000 people were watching the program online and millions more will see the proceedings on television, he added. Listen to remarks by Don Briggs.

More quotes:

Lt. Gov. Scott Angelle: “I believe we live in a country where we can do two things at one time (such as fix the spill and keep on drilling)…Mr. President, we need you to work as hard on this job as you did to GET this job.”

CJ McDonald with petroleum consulting firm McDonald Consulting LLC: As for the Louisiana way of life “all of this is changed by one decision by someone who knows nothing about how we make our living…We need to make it clear to Washington: They work for us. (And, to Obama:) No one person should have the power to diminish the liberties we enjoy.”

Hofmeister said he voted for Obama, drawing boos from the audience. “(Mr. President,) I didn’t expect the boot of your secretary on my neck and the industry I love when I did that…You are making a mistake of your seven predecessors…leading this country into an energy abyss….” His remarks and the audience’s concurrence could have made for a Tea Party rally. “This government is unfixable…Tell the government who works for whom…We’re going to take our country back….”

Stone Energy Corp. president and CEO David Welch: The mistake of the moratorium “is self-inflicted and can be changed with a mere stroke of a pen…Everything (in the Gulf) has been inspected. Mr. President, let us go back to work.” Listen to remarks by David Welch.

Billy Nungesser, president, Plaquemines Parish, and a regular on Anderson Cooper’s nightly news program: “Stand still? Can’t?” Obama says the U.S. can’t take the risk of trying to handle more than one Gulf oil spill at once. “None of these words correspond with the United States I know—or I thought I knew…We are in a stranglehold between our government and one oil company…Don’t make us wait and beat on us for six months. Put us back to work tomorrow…We don’t have six months to wait.” The state has been crippled by Katrina, Rita, Gustav and now the spill. “We can’t afford to be crippled (by the moratorium too), Mr. President, because of you…Say it, Mr. President: Yes, we can—drill!”

Jindal: “We will win this war, and this is a war…to defend our way of life.” The spill is a disaster. “The second disaster is the moratorium…We shouldn’t have to fight our own federal government…The fact that the federal government can’t do its job shouldn’t cost thousands of Louisianans their jobs.”

See all 50 tweets from today’s rally: http://twitter.com/NissaDarbonne. For all of Nissa Darbonne’s blog posts, see http://blogs.oilandgasinvestor.com/nissa.

–Nissa Darbonne, Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, OilandGasInvestor.com Today, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.com, UGcenter.com ]]> http://blogs.oilandgasinvestor.com/blog/2010/07/22/south-louisianans-say-to-washington-let-the-obama-administration-eat-burnt-toast/feed/ http://blogs.oilandgasinvestor.com/blog/2010/07/20/no-jobs-no-peace/ http://blogs.oilandgasinvestor.com/blog/2010/07/20/no-jobs-no-peace/#comments Tue, 20 Jul 2010 22:19:13 +0000 Stephen Payne http://blogs.oilandgasinvestor.com/?p=1605 The Cajundome in Lafayette, La. will host the Rally For Economic Survival on July 21, which will feature thousands of people who’s livelihoods have been affected by the federal moratorium on deepwater drilling in the Gulf of Mexico.

Not content to merely twiddle their thumbs and watch while the federal government fritters their jobs away, it appears Louisianans have decided to take a stab at that whole democracy thing.  Governor Bobby Jindal, Stone Energy president and CEO David Welch and various other local community leaders and national energy organizations representations will discuss their thoughts on how the Obama administration’s moratorium will negatively effect the economy in Louisiana.

County singer Sammy Kershaw, who tried unsuccessfully to run for lieutenant governor of the state in 2007, will be performing for the crowd. Kershaw is member of the Protect Our Coastline organization and plans to run again for the lieutenant governor chair in 2010.

I can already see the typical backlash against a pro-industry rally, with the typical claims of astroturfing and whatnot being lobbed by the Huffington Post crowd. Because as you know, a protest is only legitimate if it’s organized by someone that looks like they haven’t bathed in a month and has a homemade sign denouncing Israel or something.

Unlike the typical alarmism from the “Silent Spring” faction, the moratorium will have immediate and negative effect on the people in the Gulf Coast region. Having weathered the effects of the 2007-2010 economic crisis at a much better rate then other parts of the country, it would be devastating to Texas and Louisiana for their to be a major pullback in offshore business.

So if you’re in Louisiana and are a potential vicitim of the moratorium, swing by the Cajundome and find out just what is being done to combat the ban. Or, you can just wait for that hope and change to solve everything.

Quicksilver Resources is the target du jour. According to the Daily News & Analysis, in addition to a JV, Reliance might be interested purchasing a stake in the company or even the entire company. The Fort Worth producer holds sizable shale positions in the Texas Barnett shale and Canada’s Horn River Basin, but is tight on cash.

The Texas company has already partnered with Italian energy producer ENI for a portion of its Barnett holdings in a relatively small JV late last year, and at the time suggested it was pursuing partners for the remainder of its Barnett and possibly its Horn River assets, where it now holds some 130,000 net acres in British Columbia.

Reliance has satiated previous rumors by following through on deals with Atlas Energy in the Marcellus shale and Pioneer Natural Resources in the Eagle Ford shale, where it took nonoperated positions for a combined $3 billion. Internal sources have verified that the Indian energy giant was still actively seeking a greater position in North America.

Global Hunter Securities’ analysts have this view: “Our take is that a joint venture would likely be focused on the Horn River Basin or other emerging plays and not the entire company, based on Reliance’s entry into other early stage plays.”

In my view, a Reliance rumor is as good as gold. The only questions remain, how much gold, when and where?

“We need your help in every aspect–talk to your friends, your family, your neighbors and your in-laws.”

Felmy spoke on the rampant political pressures bearing down on the oil and gas industry of late, and the worsening impact of the BP oil spill. That must be counteracted by more education about the sources and uses of energy.

He pointed out that 9.2 million Amerians earn their livelihoods from working in the oil and gas industry–some 7% of total GDP–yet the industry continues to be demonized by politicians and pundits, and even more so since the disastrous BP oil spill in April.

“People say that we can transition off of oil by 2030–ain’t going to happen. There are 250 million cars in this country and most of them will last 10 years. Most energy transitions have taken a long time–from oil’s discovery in 1859, it took another 90 years for the use of oil to surpass the use of coal as a primary energy source! So how are you going to transition to using solar and wind? Let’s be realistic.”

The desire of many Americans to punish “Big Oil” or take money away from it is delusional. “Who owns Big Oil? Aliens? No. Americans as individuals own 23% of the shares and another 27% is owned by their pension funds. And, 14% is owned by their IRAs.”

Felmy said the Macondo spill’s impacts are many. While actual Gulf of Mexico production is not down materially–yet–and the shipping lanes through the area and to the mouth of the Mississippi River are still open, the industry itself will be greatly affected. If 33 deepwater rigs have shut down, there could be up to 50,000 jobs lost. Longer term, some 200,000 barrels a day of future production could be derlayed or lost.

If insurance costs and liability costs soar, then only the biggest companies will be able to afford to drill in deep water, shutting out the dozens of independents who currently hold the majority of the deepwater leases.

If the current mood in Washington leads to more finger-pointing, more regulation and more sentiment against fracture stimulation and well permits in the various shale plays, a huge economic opportunity will be lost, he said–especially in Pennsylvania, where Felmy is from.

“This is an opportunity we simply can’t afford to lose because of poor, hasty decisions. The policy discussions in Washington are so far removed from the facts.”

–Leslie Haines

“…Macondo was the result of human failure, not the failure of technology.”

Recently queried Keith Rattie, chairman, president and chief executive of integrated U.S. gas company Questar Corp., on what the environmental implications would be of a subsea gas-well blowout in the Gulf of Mexico, compared with a subsea oil-well blowout, and whether the Gulf oil leak bodes well for new or renewed Washington interest in greater use of U.S. natural gas as a transportation fuel and in electric-power generation.

Rattie wrote from the road, while providing details to the investment community on the roll-out of Questar’s E&P business, QEP Resources Inc., that will begin trading on July 1 (NYSE: QEP).

Rattie says, “Deepwater drilling—irrespective of whether the target is oil or natural gas—poses little risk to the environment, provided that operators adhere to good safety practice in both well design and drilling and completion operations. In this case, BP, in an effort to limit its liability for the Macondo disaster, has left the public with the impression that the industry’s practices were lacking and need changes.

“But Macondo was the result of human failure, not the failure of technology. BP personnel on the rig, for whatever reason, failed to heed clear indications that they had a bad cement job and thus dangerous levels of gas in the well bore.”

Questar is among founding companies of America’s Natural Gas Alliance, a consortium of U.S. gas producers that communicates natural gas facts to law- and policy-makers and to voters.

“I do believe that development of onshore gas resources will benefit from the Macondo disaster. The industry has gotten its act together on communicating the message of the U.S.’ abundance of natural gas, and we see signs of sustainable gas-market demand growth for the first time in nearly a decade. That said, many uninformed members of Congress conflate offshore oil-spill risk with a risk of groundwater contamination from fracture stimulation (of gas wells).

“Natural gas prices have strengthened of late, in part perhaps because the Obama offshore drilling moratorium not only destroys jobs in the offshore drilling industry, it reduces natural gas supply from the deepwater Gulf, the source of roughly 4 billion cubic feet per day of U.S. gas supply—all of which is still flowing; the market-price impact is partly psychological and partly due to an expectation that gas supply will be negatively affected by hurricane events this summer.

“The offshore-drilling moratorium is profoundly wrong-headed on many fronts: It destroys jobs, harms the Gulf Coast economy, reduces federal tax and royalty receipts, increases dependence on foreign on imports and drives energy prices higher. It might make sense if blow-outs occurred every few years. But Macondo is unprecedented, and the U.S. has not had a major spill related to drilling since the 1969 spill offshore Santa Barbara (California).

“Macondo is, without question, the result of a confluence of human errors. It was very preventable. The questions those of us in leadership roles must ask in its wake are: Do our people know that we’re serious about safety? Would one of our employees have ignored the warning signs that were flashing bright red in the hours before this disastrous explosion?

“We do not have all the facts yet, but the industry will—and the industry will—adopt whatever changes are necessary to ensure that this never happens again. In the end, the public’s only real protection is industry self-regulation, not bureaucratic rules administered from Washington.”

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

Royal Dutch Shell’s $4.7-billion bid for private-equity-funded start-up East Resources Inc. is further evidence of the transformation of the global oil and gas industry that is being fueled by development of shale technology, says John Moon, managing director of energy investor Morgan Stanley Private Equity.

“Shale technology has turned everything on its head,” Moon told attendees at Argyle Executive Forum’s energy-investment program in New York recently at which Oil and Gas Investor presented.

Morgan Stanley PE committed funding to Henry Harmon’s Marcellus-shale-focused start-up Triana Energy LLC roughly a year ago, shortly before Kohlberg Kravis Roberts invested $350 million in Terrence Pegula’s Marcellus-focused East Resources. They were followed in the fall of 2009 by Metalmark Capital’s investment in Mike John’s Marcellus start-up, Northeast Natural Energy LLC.

The KKR investment represents a portfolio-investment flip in fewer than 12 months and for substantially more than the committed capital.

Moon says the last E&P technology-changing event of this magnitude was the deployment of 3-D seismic technology in the 1970s. In that cycle, the major oil companies funded the development and application of the technology, as these large companies had the most money for access to (at the time, highly costly) computing power and for recruiting technology-leading geoscientists. As costs declined and best practices improved, the technology became accessible by smaller, independent oil companies.

In the case of shale technology in the past decade, it was a small operator, Mitchell Energy & Development Corp, that used horizontal drilling and fracturing to produce economic amounts of gas in the Barnett shale, Moon notes. “Shale technology was not developed by the ExxonMobils of the world.” Shales were not perceived to be sexy enough to merit the attention of the majors. “In this case, the technology was developed and applied first by the independents. That is a transforming shift in the way natural gas will be developed over time.”

Shell’s bid for East Resources, ExxonMobil’s conclusion just this week of its $41-billion, all-stock purchase of U.S. unconventional-resource independent XTO Energy Inc., and shale-play joint-venture deals signed in the past 18 months with U.S. independents by Total SA, Statoil ASA, BP Plc and other majors are testament to this, “that the majors are looking to the independents for access to that technology and not the other way around.

“For a while, the majors dismissed unconventional-resource development as a fad…That is no longer the case.”

Foreign oil companies are particularly motivated to “go to school” on unconventional-resource development in the U.S. to take that training to their portfolio plays abroad, he adds.

“Even 18 months ago, if you told someone outside North America who was knowledgeable about the energy business that shale technology was a really big deal, many would have looked at you like you had two heads.”

When the Morgan Stanley PE investment in Triana was announced, Moon received inquiries about the firm’s interest in the Marcellus from both national media and executives with major oil companies. “I was shocked, actually…An executive with one of the largest oil companies in the world wanted to know what we were up to.”

It was a leading indicator. “Shale technology has marked a seismic shift in the global oil and gas industry.”

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

The organizations report: “After months of researching the movie and following its screenings nationwide, IPAA and Energy In Depth have launched a major communications campaign to expose the film’s inaccuracies. One tactic in this campaign is a truth vs. fiction fact sheet that has been broadly distributed to congressional offices, state legislatures, industry, allied groups, interested parties and news media. I’d like to thank the companies and industry groups that are using this material and crediting this effort.”

Energy In Depth seeks to correct any misconceptions the documentary creates with the GasLand Debunked flyer. The organizations’ Energy in Depth website also provides info on this.

I do have the question the timing of this documentary. Natural gas is for the first time in years being considered as possible viable candidate to replace gasoline as a transportation fuel, and then this comes along? I suggest people follow the money on this one.

-Stephen Payne, Editor, Oil and Gas Investor This Week; www.OilandGasInvestor.com; spayne@hartenergy.com

Valuing U.S. E&P investments is challenged today by the eventual outcome of federal and state law and policy regarding future best practices in drilling in the Gulf of Mexico and elsewhere offshore the U.S. as well as onshore, such as the Marcellus shale, which has recently experienced well blowouts.

This is according to energy-industry executives and investors who were at Argyle Executive Forum’s recent energy program in New York in which Oil and Gas Investor presented.

Chris Ortega, a Connecticut-based director for energy private-equity investment firm First Reserve Corp., says, “It’s obviously something we’re following very closely. It’s premature to come to any conclusions (as data are changing), but energy demand is going to continue to increase, nevertheless…Regulation is something you have to think through no matter where you are.”

Changing Gulf and other drilling costs as a result of the ongoing leak emphasizes the importance of a diversified portfolio and of “portfolio construction,” he says.

First Reserve’s energy investments span the energy chain, from E&P, such as Gulf-focused Cobalt Energy International Inc. (NYSE: CIE), Deep Gulf Energy LP and Deep Gulf Energy LP II, and oilfield services, such as CHC Helicopter Corp., to solar and nuclear. And its investments span the globe.

The possibility of changing law and policy regimes is an important consideration when investing in a firm in any country, he notes. Australia’s natural resources tax is being debated, for example. “(Investors) have this sense that, because this is OECD, you don’t have to think about (game-changing) regulation.” But it is a possibility in any political regime, he says.

Christopher Manning, a partner with private-equity investor Trilantic Capital Partners, says issues in the Marcellus and the Gulf are of concern. “Our diligence on new opportunities will probably be different as a result of that.” Trilantic’s E&P investments include U.S. onshore-focused Antero Resources Corp. and Enduring Resources LLC and Europe-focused Mediterranean Resources LLC. Another portfolio company, Cross Holdings Inc., provides oilfield services in the Gulf of Mexico.

Marcellus drilling costs may grow as concerns about the use of hydraulic fracturing continue, he says.

As for the Gulf of Mexico, “right now, we would be very reluctant to invest until we have some transparency” as to what new rules and costs will be.

Craig Jarchow, a managing director for energy private-equity investor Pine Brook Road Partners LLC, says new rules as a result of the BP blowout will affect how industry participates in drilling wells in the future. “We’ll see more operators not interested in being operators.”

Pine Brook’s energy investments include Mike Harvey’s U.S. onshore-focused Stonegate Production Co. LLC, Andy Lydyard’s Comet Ridge Resources LLC and Roger Jarvis’ Common Resources LLC; Paul Favret’s Europe onshore-focused Source Energy Partners LLC; and Bill Flores’ Gulf-focused Phoenix Exploration Co. LP

He suggests that funding and insuring liabilities for oilfield incidents in the future may be handled as the nuclear industry insures catastrophic risk. In this, the first tranche is insured by the nuclear plant’s operator up to $300 million. “Above this exposure, the entire industry kicks in a retrospective premium and, since the whole industry is in, the insurance capacity is huge.”

He concludes, “Liability is going to be very interesting going forward.”

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

For now, frac math is the pastime this summer. The more fracs the better, one would think. But of course, it’s more technical than that. There is an optimum number to be done, and a limit to the dollars spent, versus the amount of incremental barrels and Mcfs recovered. Key operators in the Bakken are pushing the limits, with Brigham Exploration Co. having done as many as 36 frac stages.

“I think the upper limit has yet to be tested,” said Hamm during a Q&A session after his prepared remarks, at our Denver conference held in May, Developing Unconventional Oil (DUO).

“We have an ongoing internal study that we keep updating as we get new data.”

Whiting Petroleum Corp. CEO Jim Volker said his company also is experimenting. “It’s something we are wrestling with at Whiting today. We see a a range of options. A 22-stage sand frac can go to a 30-stage frac when using a lot more ceramic proppant in it.

“Going from 22 stages to 25 is an incremental cost of about $700,000. If we go all the way up to 30 stages, that would be an additional $2- to $2.2 million. So we have to recover a lot of additional barrels of oil to get to pay out. We are all testing this thesis that the more fracs, the better. We’ll let you know in about nine months!”

For more on the Bakken and other unconventional oil plays, and to purchase videos of individual speakers and panels, see our ad on the home page of www.OilandGasInvestor.com, or get Bakken reports and wall maps at www.hartenergystore.com.

–Leslie Haines

Stanislaw makes this argument in a new white paper titled, “Clean Energy 1.0: Moving beyond green to create sustainable jobs and a long-term energy strategy,” which focuses on the three interconnected mandates that are driving the evolution of clean energy in the United States: protecting the environment, creating enduring jobs and enhancing national security.

Stanislaw, who is the co-founder and former president and CEO of Cambridge Energy Research Associates, begins his white paper with historical context: “Just two years ago, when oil was levitating towards $100 a barrel and Russia was playing politics with pipelines — green energy was the holy grail of energy security. Then, when concern over climate change reached a fever pitch, it became the silver bullet to solve global warming. And, finally, when the ‘Great Recession’ struck, green energy was the panacea for unemployment and falling wages.”

This metamorphosis, he says, is part of a necessary maturing of the debate around energy because clean energy technologies must “evolve from their current 1.0 stage to a 2.0 stage and beyond.” He draws an analogy between clean energy and the high-tech industry: “Right now, clean energy is where the mobile-phone industry was in 1983, when Motorola released its two-pound, $4,000 DynaTac 8000x, or where the computing world stood that same year, when Windows 1.0 was launched.”

Stanislaw goes on to explain that the past two years alone have shown us that green energy is “no longer the magic bullet.” Clean energy, he says, can now take its “pivotal but mortal place in an array of energy forms and technologies that will power the world in the 21st century.” He claims that the ‘transition from green to clean’ will power the next phase of development of the world economy, as we race to create technologies that help us better produce energy and reduce its use.

The white paper points out that the stage is now set for a smart, long-term American energy strategy—for numerous reasons:
•    Energy is now top of mind: The federal stimulus bill has helped kick-start a massive investment in clean energy technologies and has shifted America’s psychology on energy.
•    Steering a new strategic course: Our recent immersion in clean energy has allowed us to better understand—through experimentation and debate—what our long-term energy strategy might be.
•    Clean beats green: We have come to understand that what matters most is not green energy but clean energy—whether it comes from the wind, clean coal, natural gas or nuclear. And, best of all, is Americans’ greater understanding of using less energy overall.
•    Energy is jobs policy: Policymakers have learned that energy policy cannot be separated from jobs policy—and that sustainable jobs matter most.
•    Energy improves the bottom line: The recession has underscored the pocketbook benefits of efficiency and clean energy for individuals and corporations, in addition to their positive impact on the climate change and national security. “Efficiency and clean energy are now firmly embedded in the consciousness of Americans,” says Stanislaw.
•    The public wants to go clean: Americans continue to insist that corporations “go clean,” thus shaping product development and capital allocation. “Americans should encourage policymakers to follow suit,” according to Stanislaw.

He advocates several steps to help move the United States along the clean-development continuum. First, he stresses developing a federal framework. “The absence of a federal framework is now an enormous handicap,” he says. “The federal government should not avoid mandating renewable power consumption nationwide. Whether the target is 20 percent of American energy coming from renewable sources by 2020, or something more modest, a mandate is important. Policymakers should not try to pick winners, but they should set targets.”

Stanislaw also stresses the need to reduce and manage energy demand instead of just producing clean energy. “Energy efficiency is perhaps the biggest untapped market for entrepreneurs, investors, and policymakers. It meets all the demands of those seeking to reduce emissions and increase national security, while having the potential to contribute mightily to the creation of sustainable, well-paying jobs.”

“And finally,” says Stanislaw, “research and development must rise again.” He cites an estimate that before the stimulus bill, the Federal government budget for energy research was the same today, adjusted for inflation, as it was in 1968 — about $3 billion. “This situation is made worse by a decline in energy-related research and development expenditures in the private sector over recent decades,” he adds.

“We should reverse this trend by creating market conditions to promote investments in research, development, and market penetration in energy efficiency, in new methods of consumption, and in all forms of energy, be they traditional — oil, gas, coal, nuclear — or alternative. “

Stanislaw concludes his white paper by reiterating that this is just the early dawn of the clean energy era. “Only in the past year or two has energy become a national state of mind,” he said. “But the historic importance of this can hardly be underestimated.”

He argues that businesses and governments should respond to this new reality by creating the products and services that will help Americans manage their energy consumption. Corporations, meanwhile, should realize that in addition to their core business, each and every one of them is an energy company, too — and that managing their energy usage can be critical to their bottom line. Last, policymakers can amplify these trends by creating the rules of the game and funding the research that will position the United States at the cutting edge of the clean energy evolution.

About the Author: Dr. Joseph A. Stanislaw serves as an independent senior advisor to the Energy & Sustainability practice of Deloitte LLP. Dr. Stanislaw is founder of the advisory firm The JAStanislaw Group, LLC, specializing in strategic thinking and investment in energy and technology, and cofounder and former president and chief executive officer of Cambridge Energy Research Associates (CERA). He can be reached via the firm’s website at https://www.deloitte.com.

Download Stanislaw’s full report, “Clean Energy 1.0: Moving beyond green to create sustainable jobs and a long-term energy strategy,” here.

The well-known keynotes on day two of the conference were author Robert Bryce and former NYC Mayor Rudy Giuliani. CNBC even had a news crew onsite for the show, which allowed interviews at our Energy Capital event to be part of CNBC’s ongoing commentary on energy that day. In case you missed them, here are some links to videos from the show:

–Check out “Oil Execs Take Heat On Capitol Hill“—it shows a brief clip of Jim Hackett, Anadarko Petroleum CEO, giving his acceptance speech following his award as Executive of the Year. The video portion covering CNBC general assignment reporter Bertha Coombs’ comments is also part of the clip.

–Here, Bertha Coombs interviews Rudy Giuliani during the show’s afternoon break on the show floor.

– This is the formal interview with Mayor Giuliani and Bertha Coombs at the show.

–Here, Bertha Coombs is being interviewed during CNBC’s Midday Headlines. (Her portion of this video begins at 2:30 minutes and runs till 4:00 minutes.)

–Finally, in this round-up discussion Bertha Coombs chats with two of our featured conference speakers: Neal Dingmann of Wunderlich Securities and Tim Duncan with Phoenix Exploration. The interviews took place after President Obama’s Oval Office Address on the BP Oil Spill aired.

It’s a lot to miss, I know. But don’t fret. Our conference team is already making plans for next year’s show, where we plan to take the quality of content, speakers and networking opportunities to a whole new level. Shouldn’t you be there?

–Bertie Taylor, Director of E-content, Oil and Gas Investor, btaylor@hartenergy.com, 713-260-6497.

]]> http://blogs.oilandgasinvestor.com/blog/2010/06/17/energy-capital-conference-attracts-cnbc-news-coverage/feed/ http://blogs.oilandgasinvestor.com/blog/2010/06/16/challenges-to-production-of-european-unconventional-gas-outlined/ http://blogs.oilandgasinvestor.com/blog/2010/06/16/challenges-to-production-of-european-unconventional-gas-outlined/#comments Wed, 16 Jun 2010 20:09:45 +0000 Peggy Williams http://blogs.oilandgasinvestor.com/peggy/?p=150 Five main challenges stand in the way of shale-gas development in Europe, said Alastair Nichol, executive advisor, Encana Corp., speaking to a crowd of 150 attendees at the Global Unconventional Gas 2010 conference in Amsterdam, organized by the Gas Technology Institute.

These challenges are surmountable, he noted:

1.  A lack of drilling rigs necessary for horizontal wells, and limited service company infrastructure. Although these factors are seen by many as constraints on European shale development, they can be addressed through alliances with U.S. service companies and E&P firms.
2. Restricted surface access. Europe’s population density is much higher than North America’s, but techniques such as pad drilling can help minimize footprints.
3. High water usage of shale completions. The development of nonpotable water supplies will be a strategy to overcome this objection to shale drilling, said Nichol. He pointed to Encana’s efforts to find a nonpotable water supply in the Debolt formation in Canada’s remote and fragile Horn River Basin as an example that could be applied to European developments.
4. Lack of pipeline capacity. In Europe, the bundling of transmission and utility functions has removed some competitiveness from the midstream sector. However, pipelines can be built if needed.
5. Finally, the regulatory environment in Europe is considered more stringent than in North America. This will be addressed if Europe’s citizens decide that they need and want shale-gas development within their borders, he noted.

“I believe all the challenges are solvable,” said Nichol.

 by Peggy Williams, Director, Unconventional Resources

 Contact me at pwilliams@hartenergy.com

If you’ll remember, Reliance took a 40% piece of Atlas Energy’s holdings in the Marcellus shale for $1.7 billion, completed last month, joining a growing line of foreign players coming to onshore America. And if you’ll remember, Pioneer has been not-so-quietly shopping for a JV partner this spring. The company has some 310,000 net acres in the Eagle Ford. An announcement is imminent by the end of June.

Wells Fargo Securities analyst Michael Hall pegs the metrics at $16,130 an acre, which he notes is higher than expectations of $12,000 per acre and better than Reliance’s bid for Atlas’ Marcellus shale assets at $14,167 an acre.

If so, Reliance joins ExxonMobil and Royal Dutch Shell as majors moving on large positions in the shales. The same rumors say Reliance is in further talks with other shale players.

Don’t be surprised if the Indian company, led by the world’s fifth richest man Mukesh Amboni, ends up with a dominant footprint in North American shale gas.

Gazprom and the powers that be in Russia would like an end to unconventional-gas drilling worldwide—for successful results to become fewer and for prohibition of drilling to become commonplace. While the former is yet to demonstrate probability, Gazprom is trying to affect the latter.

Gazprom deputy chief executive Alexander Medvedev was quoted by the Wall Street Journal earlier this year from a London press conference as prosaically saying, “Not every housewife is aware of the environmental consequences of the use of shale gas. I don’t know who would take the risk of endangering drinking-water reservoirs…

“There are shale-gas reserves in Europe, but I honestly don’t think anybody would launch themselves into production using existing techniques. Even the French would never agree with the replacement of their drinking water with wine.”

Making Medvedev’s statements so much more laughable is that Gazprom and its fellow Russian industries are widely known for reckless environmental disasters. While examples of environmental stewardship in the country likely exist, statistically, they are relatively rare and unremarkable.

Recently, a media-relations firm based in New York submitted an op-ed piece, “The Boom In Non-Conventional Gas: An Economic Mirage Or An Economic Peril?” to Oil and Gas Investor written by a France-based scientist. The communications firm represents Gazprom.

The scientist concludes, “Even if strictly applied environmental regulations…did allow profitable exploitation of shale-gas deposits in Europe, the question of the economic rationale still remains unanswered. Conventional gas is clearly less polluting and less expensive to produce than shale gas…To develop the extraction of non-conventional gas in Europe would involve an environmental sacrifice for the sake of an industrial fantasy on the part of the oil companies, and a geostrategic mirage on that of the politicians.”

Dan Whitten, vice president, strategic communications, for U.S. gas producers’ America’s Natural Gas Alliance, says, “To the extent Gazprom has expressed concern about the European market, it seems pretty clear that they view it as some kind of a competitive threat.”

ANGA’s 34 members include U.S. companies Chesapeake Energy Corp. and Devon Energy Corp., and non-U.S.-based producers Encana Corp., BG Group, Talisman Energy Inc. and BHP Billiton. It was formed in early 2009 to represent the industry in Washington and in gas-producing communities.

This spring, Worldwatch Institute, a seriously green group that, for example, advocates on its homepage cremation instead of burial, issued a report in support of natural gas. “…Natural gas could take us a big step closer to a carbon-free energy system,” says the organization’s president, Christopher Flavin, in a press release.

And, Sierra Club executive director Carl Pope is on record in a video interview with Investor from early 2008 in support of drilling for natural gas in the U.S. Pope says “Natural gas is the next-cleanest fuel (after renewables), then we have oil and then we have coal…We’re trying to make sure that we innovatively and creatively use whatever fuel we burn (and) that we rely primarily on the fuels that are the cleanest. And, among the fossil fuels, natural gas is at the top.”

He adds that producing indigenous U.S. gas has a smaller carbon footprint than importing it. “…Taking a bunch of natural gas from Indonesia and moving it to the United States is intrinsically not terribly efficient, so we would rather see what we can do with domestic production here in the United States before we start substituting imported natural gas for imported oil.”

ANGA’s Whitten says it is no surprise Gazprom would appear threatened by unconventional-gas production. “Hydraulic fracturing is a game-changer all over the world and it may well pose a threat to traditional gas supplies.”

Gazprom has shut off natural gas to Europe at least twice in this past decade, while in disputes with Ukraine through which Russian gas supply westward travels. Europe’s reaction the first time was to commence a heavy effort toward procurement of reliable supply via other means, such as LNG, and to promote development of indigenous gas resources. It had been fooled once.

The second time it lost this heating and industrial fuel, European leaders’ response was unyielding: “Shame on you.” Gazprom has been killing its customers—not a successful business model for most types of trades. That it is concerned with the world’s health and is carrying a green flag now is great comedy.

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

Americans—well, the world—loves cheap energy. Remind them of that, says Fox Business newsman and news-maker John Stossel.

Stossel addressed energy and other business leaders today on “Prosperity and Its Enemies” at the second annual Institute for Energy Research (IER) lunch forum in Houston on how prosperity in the U.S. is under attack, and at the greatest risk to those who are struggling the most to prosper.

His address is timely, considering newer government intervention in business—this time in offshore oil and gas drilling. One of the some 300 luncheon attendees asked how energy producers and other pro-business leaders can explain the importance of U.S. energy production.

Stossel says that explaining that more Louisiana Gulf Coast residents are employed by the energy industry than the fishing industry will fall upon unpiqued ears.

Instead, he says, emphasize that U.S. energy production contributes to Americans’ access to cheap energy. Oil is produced from thousands of feet below Earth’s surface, and at times under thousands of feet of water too; brought to the surface and put into thousands of miles of pipe or into ships; refined into gasoline; transported to fueling stations in trucks; and the price is less than $3 a gallon, with some 70 cents of that going to the government.

“It still costs less than the bottle of water they sell at the gas station,” Stossel notes.

Government interference in free markets is costly, inefficient and counter-productive. Americans yell for more government regulation, yet don’t recognize the affordable quality of life created by free markets, he says. Why?

“Maybe we take these miracles for granted.” After purchasing goods for a month with a plastic card, a statement arrives that accounts for each purchase, to the penny, he notes. Yet, “the government can’t even count votes.”

In interviewing domestic-energy advocate T. Boone Pickens on Fox News, Stossel broke a window to demonstrate how the unenlightened may think jobs are created (via destruction vs. production), such as the fallacy of thinking wind- and solar-power generation create more jobs than they destroy. It’s “the broken-window fallacy” noted by 19th century French economist Frederic Bastiat.

Educating voters that “wealthier is healthier,” Stossel says, and how the greatest wealth is created from free markets is “an endless fight. We have to keep fighting it.”

The free market is alive and well in Houston area where a neighbor just (1) changed electricity providers under Texas deregulation that allows the consumer to choose provider and price and (2) chose the 8.5-cent-per-kWh provider with 3% renewable content over the 9.5-cent-per-kWh provider with 100% renewable content.

Green is good, but reason always wins—well, in the free marketplace; maybe not in Washington.

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

Notes: The Institute for Energy Research (IER) is devoted to educating and informing policy-makers, media and American public on the benefits of a free-market approach to energy policy. It can be found at www.InstituteforEnergyResearch.com.

Stossel can be reached at http://stossel.blogs.foxbusiness.com. See the “broken window” video: http://stossel.blogs.foxbusiness.com/2010/06/04/the-bastiat-prize.

Here are a few notes for the young, new media covering the Gulf of Mexico oil-drilling tragedy.

–First, it’s not a spill; it’s a leak. When the oil gushing from Macondo is stopped, what has escaped can be defined as what has spilled. Until then, it’s a leak.

–And, concerning Macondo, that’s the name of the well. It’s the name of the oilfield development, to be exact. It’s the Macondo project. The well is not called the Deepwater Horizon; the semisubmersible that was drilling the well for BP Plc was named Deepwater Horizon. The operator of the development is BP; the operator of the semisubmersible was Transocean on hire by BP.

–Crawfish and catfish are not at-risk marine life. These are freshwater dwellers, and most commercial supply of these is from commercial ponds far inland. Prices for these could, of course, grow if supply of Gulf seafood is diminished and more consumers turn to crawfish and catfish to supplant their fish dishes. But prices for these would not grow due to new scarcity directly as a result of the Gulf leak. Any price hikes for these in the name of the leak is unreasonable.

–Finally, the Gulf leak will not end the use of fossil fuels—unless the world decides to forfeit incredible luxuries and quality of life that hydrocarbon-based fuels provide.

A “green TV show” producer called recently to do a “pre-interview” before a live segment. Print and radio journalists often receive these calls from TV producers, and often they are surreptitious screen tests to determine if the non-TV journalist might be a candidate to recruit for a TV post.

Often, they’re actually talking to journalists who are expert in their fields to have more talking points later on their programs and to be prepared for some hard answers.

“Will this spill (sic) result in the end of the use of fossil fuels?” she asked.

“No,” I replied. My response was more elaborate and articulate (of course) but it was essentially “no.”

After some silence and she stuttered a bit, I asked if she was okay. She stuttered a bit more and asked me if I said “no.” I replied that I did.

“Um, uh, um, could you elaborate on that?” she asked. I already had (really, I did), but it seems what I said was as startling as suggesting there may be life in other solar systems out there.

“Okay, well, think of air travel,” I explained. “Air travel provides great luxury and quality of life. Aircraft is fueled with a petroleum-based product: jet fuel. Air travel is not possible with coal; it’s too heavy and provides relatively too little energy, or Btu content.

“It is too dangerous to fuel an aircraft with nuclear power; a crash would result in nuclear explosion or release of radioactive materials.

“Wind and solar are too unreliable a fuel for air travel and, again, does not provide enough Btu. And, hydropower is out, since waterfalls don’t happen on planes.

“This leaves natural gas and crude oil. It may be possible to fuel and lift-off aircraft with natural gas or CNG or LNG. It is a reliable fuel stream. I’m not sure of the weight/Btu ratio or the safety rating, though.

“So, this leaves crude oil, or the petroleum-based product that is jet fuel, a super-high-octane, lightweight, constant-streaming fuel.

“That’s just one example of the luxury and quality of life crude oil provides the world’s constituents.”

I received an e-mail later that day that too many interviews had been lined up for the segment, thank you, and I’ll be contacted later for a future program. I’m not sure if the air-travel example will be brought to broadcast in the future, but there is a young TV news producer out there now who may have greater appreciation for hydrocarbon-based energy.

Meanwhile, I think I failed the screen test….

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

The company revealed that it had accumulated 250,000 net acres of leases. Its first well, drilled by subsidiary Petoskey Exploration LLC, in Missaukee County, produced at an average rate of 2.5 million cubic feet equivalent per day during its first 30 days on production. The well, drilled close to the depocenter of the basin, produced primarily from the Collingwood and had some contribution from the Utica. 

A report by Ross Smith Energy Group notes the Middle Ordovician Collingwood is sandwiched between the Trenton Black River limestone (below) and the Utica shale (above) in the northern third of Michigan. Potentially, the play could stretch across an attractive swath of Michigan’s Lower Peninsula; Encana’s leasehold spans seven counties.

In southern Ontario the Collingwood has been recognized as an oil shale reservoir since Colonel Drake drilled his Titusville well. According to a 1983 paper by J.F. Barker et al, shale oil was produced in Ontario from a plant near Collingwood on Lake Huron, where the shale outcrops. From 1859 to 1863, oil was retorted from the shale to produce fuel and lubricants. Ironically, it was the discovery of conventional oil in Ontario that rendered the retorting business uneconomic.

Barker and his colleagues reported that the Collingwood often included intervals of two to five meters with more than 3% TOC, and posited it had major economic potential for oil shale. Now it appears that Encana holds that same opinion of the shale, at least where it is gas- and condensate-prone in the depths of the Michigan Basin.  

by Peggy Williams, Senior Exploration Editor

Contact me at pwilliams@hartenergy.com

And, while the buysiders investing in energy aren’t immune to what’s creating industry buzz—unconventional assets and oil-weighted E&Ps—many are reluctant to exchange foundational beliefs for what’s in fashion. Now that institutional investors are looking again, are they valuing companies based on assets, balance sheets or just commodity prices?

In June, look for my U.S. buyside cover story in Oil and Gas Investor and on OilandGasInvestor.com . Six buyside firms discuss current investment strategies, holdings that are exceeding expectations and energy subsectors poised to outperform this year. More than 15 companies in various energy subsectors are identified as exceptional investment opportunities.

As a complement to the story, commentary from interviewees that had to be cut due to space limitations will be posted in coming weeks. Stay tuned.

–Bertie Taylor, Senior Editor, Oil and Gas Investor, btaylor@hartenergy.com, 713-260-6497.

This follows President Obama’s announcement Wednesday that the U.S. is putting a hold on the expansion of offshore drilling he suggested in a speech last month while the government investigates the spill, which occurred this week following the explosion on the Deepwater Horizon oil rig on April 20. The cause of the explosion remains unknown, though some sources such as FBR Capital speculate it could be due to failure of the blowout preventers due to mistakes in the cementing process.

At the time Obama’s speech, proponents of offshore drilling said the ruling didn’t go far enough. Now, at least three key senators opposed to expanded offshore drilling– Florida’s Bill Nelson along with Robert Menendez and Frank Lautenberg of New Jersey–now are calling on Obama to drop the plan.

Which means for the oil industry, this disaster couldn’t have come at a worse time. The well is spewing up to 5,000 barrels of oil per day into the Gulf, and the oil has now reached the Louisiana coastline, with just the beginnings of its effects on seabirds being realized.  Still, proponents of drilling feel the incident, while tragic, should not discourage further offshore exploration.

In an interview with the National Journal, Alaska Senator Lisa Murkowski said:

“I think what people need to be reminded is that for decades we have been drilling in the Gulf with very little incident, and this is a terrible tragedy and we need to get to the bottom of it and find out what happened and ensure that we don’t get ourselves in a similar situation.”

The long-term effects of this disaster are yet to be seen, both in the environment and U.S. energy policy. One thing’s for sure though: we’re all stuck in it.

-Stephen Payne, Editor, Oil and Gas Investor This Week; www.OilandGasInvestor.com; spayne@hartenergy.com

The economic vitality created by just one natural gas well may have steady, active job production for up to 20 years. A typical gas well will produce both gas and a certain amount of oil or condensate. Most wells require a chemical treatment program. The chemicals used address problems from scaling and paraffin build up to H2S treatments. It is quite normal to have some type of field compression for enhanced or better rates of recovery from the reservoir. Naturally, everyone is interested in measuring the amount of gas and associated oil or condensate produced as to calculate the revenue from the well’s production.

From these various functions and components it is contended here that a typical well contributes to the livelihoods of 115 people. (Click below for the full report that describes how this figure is derived.) Each of these 115 jobs directly associated with the economic job engine of a producing well supports the livelihood of three more people as these paychecks are brought home and become consumer dollars.

There are also considerable economic benefits in the form of excise taxes into the coffers of state and local governments and royalty payments to the mineral owners.

Economic models established to justify other community activity are excellent tools for the oil and gas industry to utilize in demonstrating the economic stimulus our endeavors create. At a time when every job has value, we can never lose focus on the high value jobs that the oil and gas industry supply to our nation.

–Mark Goloby

About the Author: Mark Goloby is president of TC Technologies, which delivers wireless data-monitoring tools for oil and gas production and assets needed to support production. He can be reached at tctcom1@pdq.net.

Download Mark Goloby’s full report, “The Oil and Gas Job Multiplier:” theoilandgasjobmultiplier

The first quarter of this year saw a drop in gas prices of about 30%, resulting in a shift in strategy for oil and gas companies who had been betting on an increase in the price of gas. At the beginning of the year, it seemed we were looking at prices of $6 to $7 per MMBtu. Unexpectedly, supply is high, and today the price closer to $4.

The drop in gas prices will make the economics of many current gas projects, including shale gas, marginal in terms of profitability. The situation is amplified by slow demand through the recession, well-stocked storage space and increasing international LNG capacity, so there is no quick respite in sight.

Meanwhile, the price of oil has grown to more than $80 a barrel. As a result, we are seeing an increased focus on oil and more investment in areas with oil potential (like EOG Resources’ recent announcement that it will develop 500,000 acres in oil-producing areas).

Companies with a strong focus on gas and gas shale will need to find ways to maintain cash flow through cost reduction, streamlined operations, and other ways to free cash. In addition to low prices for gas sold, the current business case to their investors is based on an estimated production for the relatively few wells drilled and some extrapolation. This means they are highly leveraged and need to ensure a strong cash flow to maintain the development pace to achieve a positive return to investors in promised time frame.

To address this, we should expect to see companies with large exposure to onshore gas like Cheasapeake Energy Corp., Petrohawk Energy Corp. and Cabot Oil & Gas Corp. sell assets to maintain operations and a renewed focus on cost-control and cash-release initiatives as well as shift focus to liquids production as much as possible. In fact, we have already seen that Petrohawk recently sold some assets, and Anadarko Petroleum Corp. recently made a deal with a Mitsui Oil & Gas Exploration company in Japan.

–Jan Erik Johansson

About the Author: Jan Erik Johansson is vice president, energy sector, for Celerant Consulting Inc. He can be reached at jan.johansson@celerantconsulting.com.

Foreign companies that perform offshore services for the oil and gas industry on the Outer Continental Shelf in the Gulf of Mexico are now on the IRS radar screen, and so are the U.S. companies that hire them. The IRS is taking the position that these foreign companies and their foreign workers have “U.S. source income” and may be engaged in a U.S. trade or business.

Therefore, the IRS contends the companies and their workers must file U.S. tax returns and pay U.S. taxes due on amounts earned from these offshore services. In addition, the IRS is likely to contend that the U.S. companies that hired the foreign companies should have withheld and remitted to the IRS 30% of the amounts they paid to the foreign companies.

The IRS has also made clear that, in addition to taxes and interest due, it intends to assert various penalties against both the foreign and the U.S. companies, as well as the foreign workers. The red flags recently raised on this issue were the IRS’s designation of Foreign Withholding as a Tier One Compliance Issue and the issuance of an Industry Directive dated October 28, 2009, which specifically targets activities on the Outer Continental Shelf in the Gulf of Mexico. Tier One Compliance Issues generally have the IRS’s highest priority and are subject to the greatest scrutiny by IRS auditors.

What Is U.S. source income? What are the broad definitions? Why are foreign-vessel owners are hearing from the IRS? Preparation Is essential. Find the full 1,200-word report by clicking below.

–Andrius R. Kontrimas and Nancy T. Bowen

About the Authors: Andrius R. Kontrimas and Nancy T. Bowen are partners with law firm Fulbright & Jaworski LLP. They can be reached at akontrimas@fulbright.com and nbowen@fulbright.com.

Click for Kontrimas and Bowen’s full report, “IRS Focuses on Foreign Companies and Offshore Services:”irsfocusonforeigncompaniesfulbrightjaworski

Is U.S. natural gas production really going up, or is it flat or down, compared to 2008 and 2009 data? That’s been the key question this year for producers, traders, speculators and end-users. With the lag in drilling last year, the sharp decline curves in the shale plays, and the overhang of uncompleted shale wells in second-half 2009, many people find it difficult to say.

Many analysts thought that production would start to decrease this year, thereby enabling prices to rise later in 2010.

The supply picture is cloudy due to many factors—but that may be about to change for the better.

Pending revisions to supply data, as compiled by the Department of Energy’s monthly EIA-914 production report, “cast uncertainty on a primary source” for gas supply data that affects gas markets, says Barclays analyst James Crandell in a recent report.

The EIA’s data has increasingly come into question, especially now that fast-paced drilling in shale plays is adding significantly to U.S. supply. But on April 29, EIA is expected to announce a revised methodology. The agency also says it will release revised monthly production data for all of 2009.

“We examine other sources of production data for comparison, including government sources and commercial vendors,” Crandell says in his weekly natural gas report. “Typically, they rely either on state-administered surveys in which data are reported with a lag, or on pipeline informational postings. Data tend to converge between methods with enough time lag, but incomplete reporting afflicts recent months and makes comparisons between methods another ‘estimation’ process.”

Crandell says EIA-914 data tend to be best for states where survey coverage is high. “We expect data revisions to be focused in a few states, namely Texas and Louisiana, where the industry composition has changed drastically since the survey was instituted.”

Meanwhile, the horizontal gas rig count is now higher than it was during the last peak in 2008.

–Leslie Haines

According to EOG, the Barnett Combo play works for several reasons. First, the resource base is enormous–in fact, it ranks as one of the largest in the world. Oil in place ranges from 40- to 200 million barrels equivalent per square mile. Many old vertical wells, with long production histories, were drilled in the area, and these gave solid indications of the potential of the play. Rock work–cores and logs–showed that pore throats are large enough to produce oil.

At present, EOG is running nine rigs in the play, and it plans to grow that  to 14 rigs by year-end. It has scheduled 234 net wells in the Combo area in 2010, split almost equally between verticals and horizontals. That will rise to 300 wells in 2011 and 2012.

EOG’s average costs are $2 million for a vertical well and $3.4 million for a horizontal well. Verticals are employed in Cooke County, in a narrow area rife with thrust faults and fractures.  EOG’s recoveries are currently 167,000 Boe gross in reserves for a vertical completion. Horizontal wells in the Montague County core area are expected to recover 337,000 Boe gross.

-Peggy Williams, Senior Exploration Editor, Oil and Gas Investor

pwilliams@hartenergy.com

Federal tax favoritism of trusts north of the border is expiring at the end of this year, changing the fundamentals of what these oil and gas producers can and will own in the future. Until now, the trusts have mainly held assets in Canada, as income from assets elsewhere, such as the U.S., are subject to taxes in those jurisdictions, diluting a Canadian trust’s distributions till.

During the growth of the trust era of the past decade, resulting in more than 30 in the oil and gas business alone, most U.S. E&Ps divested their holdings at record premiums, while so many of the hungry, exploit-and-produce trusts competed for domestic properties. The North American oil and gas industry became bifurcated, both geographically and geologically: Canadian E&Ps became primarily exploitation-only, Canada-only companies, while most U.S. E&Ps have continued heavy investment in exploration and in almost any region of the world but Canada.

Crossborder deal-making may resume soon in force, though.

John Dielwart, chief executive officer of ARC Energy Trust and ARC Resources Ltd., says, “Today we are a distribution-paying trust but, in nine months, we will be a dividend-paying corporation.” Dielwart participated in a Q&A session with Hart’s Developing Unconventional Gas 2010 conference attendees in Fort Worth in March. Some trusts are converting to non-dividend-paying models, thus will spend all of their cash flow as a traditional E&P company does, so this will result in some increased spending on E&P north of the border, he says.

New technology will be deployed rapidly in the country, both in British Columbia’s Montney shale-gas play as well as in Alberta’s tight-oil reservoirs, he adds. The trusts have chewed up a lot of oil and gas producing properties over the years that remain ripe for new exploration efforts, especially using the latest horizontal and completion technologies that have exploded upon the U.S. market in the past decade.

And, there is another development that is expected to further open exploration in Alberta, in particular, to new domestic and crossborder investment: “Thankfully, the Alberta government recently fixed the mess they made of our royalty structure.”

And, oil plays are especially important now. “We will continue to advance our tight-gas plays, but every opportunity we have to use this same technology in oil, we as an industry will be doing that, and that’s where you’ll see a lot of companies moving some of their capital.”

New, crossborder investment will represent competition for assets, but also partners and endorsements, he adds.

“The fact that Shell could spend its money anywhere in the world and it chose to spend $7 billion entering the area we’re in (in the Montney) is wonderful. They are helping to advance delineation of this play much quicker than we could as a company of our size.”

More partners, and with global ties, may help Canadian producers find more markets for their gas, he notes. “The challenge the area has is that it’s the furthest distance from (the leading U.S.) market. It’s not like being in the Marcellus or the Utica, where the market is right there. We have to worry in Canada about diversifying our markets because we’re captive to the U.S. right now.

There is a hope that the Kitimat, British Columbia, LNG facility will be built. “The Apaches of the world are strongly stepping behind it for (marketing) their Horn River Basin production, and it’s a very good thing: If the bigger companies can come in and get that infrastructure built, it will help all of us.”

As for new Canadian E&P investment south of the border or elsewhere, Dielwart notes that Enerplus, which has been a Canadian trust, recently bought into the Marcellus play in Appalachia.

“The players are looking for a resource play because, if you’re not in a resource play today, the market doesn’t really care much about you.”

Prepare for more competition for U.S. assets in the coming months and year. And, pack a bag ready to shop again up north.

–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Hart Energy Publishing; Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com, UGcenter.com Today, EPmag.com, E&P Buzz, PipeLineandGasTechnology.com, PGT News, HartFUEL.com, FUEL.

Mark McConville and Keith Barfield have converted the GTO to run on natural gas, and hope a revitalization of Route 66 as an alternative fuel-friendly thoroughfare will attract drivers back to the classic American highway.

Route 66 was originally created in 1926 as a semi-intercontinental highway designed to bring travelers out West and provide a feasible travel for a section of the country that was still vastly unpopulated and unpaved. With the advent of the U.S. Highway system in the 1950s and ’60s, the route eventually faded in use, being decertified by the United States Highway System in 1985.

McConville and Barfield hope that Route 66 will before a tourist route for drivers with CNG vehicles, and hope to bring attention to this fading piece of Americana.

And I say, right on! So check out their site, check out their car and cheer them on as they plan to embark along the mythic road that helped shape this country.

-Stephen Payne, Editor, Oil and Gas Investor This Week; www.OilandGasInvestor.com; spayne@hartenergy.com

While the shales typically have gas-in-place, they are expensive to drill. This, coupled with steep well-decline rates, launched vigorous debates about the shale plays’ economics last year. Some analysts suggest the shales have to carry a hefty reserve requirement to truly be economic. Also, these plays require a lot of drilling to give operators running room to shorten their learning curve, a daunting challenge with Henry Hub gas prices still trending around $4 per MMBtu.

While newer shale plays sparked intense interest among the “shale-haves” in 2009, the Haynesville remains in the Top 5, post recession, thanks in part to impressive geological characteristics and stellar well results on the Louisiana side of the play. Convinced the East Texas portion also holds a wealth of potential, operators have been busy locking in acreage and refining their development approach—and they’re already seeing encouraging results.

In May, look for my East Texas Haynesville cover story in Oil and Gas Investor and on OilandGasInvestor.com to hear from operators, analysts and the midstream sector about how this side of the play has incredible potential—even in times of lower commodity prices!

As a complement to the story, an exclusive audio interview with Hill Vaden, Gulf Coast upstream analyst for research and advisory firm Wood Mackenzie, is now posted at OilandGasInvestor.com. Vaden discusses Haynesville economics and the state of natural gas demand.

–Bertie Taylor, Senior Editor, Oil and Gas Investor, btaylor@hartenergy.com, 713-260-6497.

In 2007, shale deals began to impact the market, and by 2009 shale deals accounted for more volume than non-shale deals.  “We now have a shale market that is equal to or greater than the rest of the market,” Polzin said.

Today, 55% to 60% of the deal volumes have a shale orientation, and half the number of deals done are shale.  The discrepancy between volume and numbers comes because shale deals are generally larger, he noted. Furthermore, the new tranche of shale deals are coming from every shale basin. “There’s not one shale dominating the volume: there’s a buyer in every one of those positions.”  

The rise of the shale joint venture is another notable development. Some $15 billion worth of shale joint ventures have been consummated during the past few years, and this trend is increasing. “We are seeing two to three significant-sized JVs being announced every quarter,” said Polzin. The JVs fit well in today’s market: buyers like the repeatability and scale of the shale JVs, and sellers like the ability JVs give to hold on to large land positions and accelerate value.

Even in a tough environment, the shale plays stand out. Private equity, foreign buyers and public companies are all quite active in shales—today, shales are the place to be.

-Peggy Williams, Senior Exploration Editor, Oil and Gas Investor

pwilliams@hartenergy.com

Traditionally, each of any 42 E&P companies’ stock-price performances, when graphed for any period of time, would shadow the others’ rise or fall across the grid, along with oil and gas prices, with some exceptions, such as company drama, good or bad. Increasingly, performances are decoupling and not just based on increasingly divergent oil and gas prices.

 Investors’ view of oil- versus gas-weighted stock values during the past 15 months often has less to do with the price of the commodity. Instead, it appears potential upside based on strength of management and the story is playing a role. And, at times, there is still little apparent reason, except that the story is already played out in up- or down-trading, and the stock is fully valued or discounted.

One independent E&P company’s investor-relations chief says, “It’s war out there.” E&P stocks are trading on “hand-grenade marketing tactics” with every small doubt and rumor as to an E&Ps’ viability causing the stock to flatline.

In an OilandGasInvestor.com comparison of 15-month stock-price performances for 42 E&P companies­—a list randomly borrowed from Bernstein Research’s universe of E&P stocks—more oil-weighted producers have shown tremendous growth than gas-weighted producers. Yet, a handful of each is in the bottom 10 as well. Here are some stock-price anomalies ripe for growth or decline.

–Shares of Devon Energy Corp. have grown roughly 0% between January 2, 2009, and March 17, 2010, the timeframe for which the 42 stocks’ prices were reviewed. Oil was approximately $46 and natural gas was $6 at the beginning of the timeframe. At press time, the April oil contract was trading at $82; natural gas, $4. Devon is approximately 67% weighted to natural gas, yet it announced recently it is entering a Canadian oil-sands joint venture with BP Plc.

–Six of the Top 10 stock performances are oil-weighted, and the No. 1 improved stock is Bakken oil-shale-weighted: Brigham Exploration Co., with a 400% return in the 15-month period and 55% weighting to oil production. Others are Berry Petroleum Co. (69% oil), up 260%; ATP Oil & Gas Corp. (60% oil), a conventional Gulf of Mexico oil producer, up 205%; and Pioneer Natural Resources Co. (approximately 50% oil), up 200%.

Another Top 10 Bakken oil story is Whiting Petroleum Corp. (78% oil), up 120%. Meanwhile, 53% oil Callon Petroleum Co. posted a 90% stock-price improvement on its push during the review period to onshore the U.S., particularly the oily Permian and the gassy Haynesville.

Four gas-weighted stocks appear in the Top 10 too. Newfield Exploration Co. (71% gas) posted a stock-price improvement of 160%; Quicksilver Resources Inc. (75% gas), up 150%; Cimarex Energy Co. (95% gas), up 118%; and Exco Resources Inc. (71% gas), up 100%.

–Meanwhile, six of the Bottom 10 stocks are gas-weighted, including Devon Energy Corp. Also posting 0% price growth in the 15-month period is Penn Virginia Corp., which is 84% gas-weighted. The other four are Haynesville players Goodrich Petroleum Corp. (98% gas), down 40%, and Comstock Resources Inc. (94% gas), down 30%; PetroQuest Energy Inc. (88% gas), down 20%; and Encana Corp. (now 95% gas, but whose price results are not comparable since it split from its oily half, Cenovus Energy Inc., in December).

The four oily Bottom 10 stocks are Cenovus (newly split from Encana and 53% oil); Murphy Oil Corp. (72% oil), up 19%; Clayton Williams Energy Inc. (57% oil), down 20%; and W&T Offshore Inc. (approximately 50% oil), down 40%.

–Falling in the middle include oily names such as Denbury Resources Inc. (83% oil), whose stock price has grown a mid-range 22% in the past 15 months, yet it has also shed its Barnett shale-gas assets and traded the cash for oily Encore Acquisition Co. and privately held, oily Conroe Field.

–Uber oily Occidental Petroleum Corp. (76% oil) has seen stock-price growth of a mid-range 32%, despite news in July of its discovery of the largest new oil field in California in 35 years.

–Gas-weighted (76%) EOG Resources Inc.’s stock price has improved a mid-range 40%, despite its announcement last fall that it is reprofiling its portfolio to a greater weighting to oil.

Stock-picking is easier with a rifle, instead of hand grenades. For a table containing the full review results, click here: march1710stockperformance.

–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Hart Energy Publishing; Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com, UGcenter.com Today, EPmag.com, E&P Buzz, PipeLineandGasTechnology.com, PGT News, HartFUEL.com, FUEL.

Communication problems are as old as human history. Bridging gaps is a continual challenge, and industry leaders need to know how to capitalize on overcoming those gaps.

Within the oil and gas industry (as well as in other industries), there are four generations of talent: Traditionalists (birth years 1925-1945), Baby Boomers (1946-1965), Generation X (1966-1980) and Generation Y (1981-2000). Since the 1990s, professional journals have alerted oil and gas leaders that the Baby Boomers, now the largest percentage of the workforce, are exiting the workforce at an alarming rate. The potential consequences include:

–Increased competition for talent. Due to the decrease in skilled talent following the retirement of the Traditionalists and Baby Boomers, competition for workers with required professional degrees and experience will increase.

–Shifting geography. Technology enables talent to work from anywhere and teleworking is becoming more commonplace; therefore, organizations will be able to source talent globally. This shift will affect organizational communication, strategy and business processes.

–Shifting generation. The corporate leaders of tomorrow will most likely be talent from Generations X and Y. Currently, organizations are balancing the activities of retiring two groups and preparing the organization for two others, while not neglecting any.

–Aging workforce. A majority of Baby Boomers are predicted to exit the workforce by 2015 and are followed by a much smaller group of talent, Generation X. In addition, the next generations of talent have different learning styles, communication preferences and work/life balance requirements than their predecessors. To recruit, retain and develop the next generation of talent, organizations must recognize and adapt to these styles.

–Lost information and tacit knowledge. As Traditionalists and Baby Boomers exit organizations, some for the last time, so will their communal know-how—their tacit knowledge—especially if it has not been adequately identified, captured, codified and stored in corporate knowledge repositories.

–Preparing and training talent. The fact that Traditionalists and Baby Boomers are retiring does not mean that they will not re-enter the workforce in some capacity, such as starting a new career, or working as a consultant or part-time employee. In some cases, organizations will be able to leverage veteran expertise in this way. As a result, organizations will need to update the skills of these workers, or train them along with other new hires. Thus, learning/training departments may simultaneously have to train several generations, each having distinctly different learning styles. This can perplex learning organizations that do not understand the needs of each generation.

–Sebastian Francis

About the Author: Sebastian Francis is senior consultant, commercial business services, for SAIC Corp. and specializes in knowledge management and organization learning within SAIC’s oil and gas practice. He can be reached at Sebastian.L.Francis@saic.com.

Click for Francis’ full report, “Better Knowledge-Sharing: Fill The Dry Knowledge Well With These Practices:” knowledgewellsebastianfrancissaic2010

Well, with conventional oil, you drill a hole in the ground and pump the oil out of it. Time-tested principle, works really well. But oil isn’t always available in traditional formations, and if you want to get it out, you have to put some extra effort into it.

According to the International Energy Agency, there are five types of unconventional oil. However, two of them come about from non-E&P formats, namely biofuels and the creation of liquids from gas processing, so let’s just stick to the three types of unconventional oils found in nature.

The first, and so far the big one at the moment, is oil shales. Like unconventional gas shales, oil from these formations are extracted from sedimentary rock structures. The oil contains a chemical compound called kerogen, which itself can also be converted to oil shale. Oil shale must be converted to oil refinery quality crude through either pyrolysis, hydrogenation, or thermal dissolution.

Just so you know, this isn’t a new process. Oil shale has been being converted to oil ever since the Middle Ages.

The second and more well-known is oil sands recovery, very popular in the Canadian Athabasca Sands in Alberta. In this case, instead of being drilled, oil is dug out of the ground, not unlike a surface coal-mining operation. Once the oil-soaked sand is extracted, it’s taken to a special facility called an “upgrader” that separates the oil from the sand. Like with oil shale, the oil is then ready for the refinery.

The last natural form of unconventional oil is coal liquification. In this case, the product starts out as coal and is then converted to a synthetic fuel by going through a low-pressure carbonization process that heats coal and collects the oily liquids and gas that seeps out.

Hope that helps you on your way! Class dismissed!

For Worldwide Geochemistry LLC founder and visiting scientist at Institut Francais de Petrole in France Dan Jarvie’s thoughts on unconventional oil, click for the complimentary webinar Oil-Prone Shales: Their Nature, Location, Production Potential now available on demand.

-Stephen Payne, Editor, Oil and Gas Investor This Week; www.OilandGasInvestor.com; spayne@hartenergy.com

Except few of the combinations make sense, he says. “In the few completed transactions we’ve seen, there is no evidence of an appetite for big premiums to NAV.”

While buyers are willing to look ahead a year or so, no valuation is being given to probable reserves beyond that point, he observes.

Rumored targets such as Petrohawk Energy Corp., Southwestern Energy Co. and Tullow Oil Plc trade at “significant premiums” to 2011 proved NAV, effectively eliminating them as likely targets. Ultra Petroleum Corp., however, does not.

Chandra says the CEO of Petrohawk stopped by his office this week—that would be Floyd Wilson—”stating unequivocally that buyers have expressed zero interest, terrified by the premium that may be required.”

Potential buyers have similar dissuading issues. ConocoPhillips carries the “searing legacy” of the Burlington acquisition. ChevronTexaco consistently denies wanting to make a corporate shale transaction. Devon Energy Corp. staunchly states it is not seeking a suitor, thus making a high premium a credibility killer. And BP Plc “has clearly demonstrated an appetite for assets over companies, in the U.S. at least.”

Private company acquisitions, on the other hand, are very much alive. “With baited breath we await the results of the Common Resources data room and a possible deal for Ellora Energy.”

As for Devon, Jefferies analyst Biju Perincheril believes the company received a “good, not great” price for its international and Gulf of Mexico portfolio, but says, “for a company dedicated to North American onshore plays, Devon’s portfolio outside of the Barnett and Cana shales has holes—the company may be forced to pursue acquisitions.”

He adds: “Reminds us a lot of another large-cap North American onshore name in early ‘08.”

I’m guessing XTO. And we know the end to that story.

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Kansas Oil: Production Since 2000
	Oil
	Production	Wells
	(bbls)
2000	35,174,434	42,165
2001	34,124,322	41,545
2002	33,379,734	41,383
2003	33,972,033	41,206
2004	33,878,472	41,920
2005	33,619,258	43,012
2006	35,668,804	43,924
2007	36,590,204	43,413
2008	39,582,384	45,106
2009*	32,762,190	44,483
*2009 data incomplete at this time.
Source: Kansas Geological Survey

The new flows of crude are coming mainly from counties in western Kansas and on the Central Kansas Uplift. In these regions of the Sunflower State, prospectors can image closures as subtle as 10 to 15 feet on 3-D, and that’s enough to make an oil well. Economics are strong, as the wells are shallow and inexpensive to drill and complete.

For more on Kansas, look for the article “Little Kansas Bumps” in the upcoming April 2010 issue of Oil and Gas Investor.

-Peggy Williams, Senior Exploration Editor, Oil and Gas Investor

pwilliams@hartenergy.com

Oil and gas markets have experienced significant changes during the past two years. Between crude oil moving from $146 to $33 in less than five months and gas going from nearly $14 to $3 over the course of a year, the past 18 months have been incredibly volatile to say the least. Adding insult to injury, the state of the capital markets has left many producers without access to much needed capital.

In these times of significant change and uncertainty, it is essential that oil and gas producers employ solid hedging and marketing strategies. These strategies will not only allow producers to survive the most challenging times, but will also allow them to excel in the best of times as well.

Houston-based EnRisk Partners, an energy hedging, trading and risk-management advisory firm, recently surveyed 38 U.S.-, Canada- and Australia-based small and midsize independent oil and gas producers about hedging activity in 2009.

The primary focus of energy risk management as it relates to oil and gas producers is hedging.

Consequently, this subject forms the basis of this study, which strives to analyze the current hedging practices and strategies of producers. Some of the key survey findings are:

–41% of study participants regularly hedge their production, while 29% never hedge.

–Only 13% are required to hedge by their lenders and/or investors.

–The majority of the participants that hedge on a regular basis stated that, on average, they hedge between 51% and 71% of their current PDP (proved, developed, producing) volumes.

–36% of the participants stated that their CEO or CFO makes the company’s hedging decisions.

–Swaps and collars are the most popular hedging instruments among the study participants.

–Only 34% of the participants indicated that establishing stable and predictable cash flow is the most important goal of their hedging activities.

–67% said they would characterize the success of their company’s current and past hedging initiatives as good or excellent.

—Mike Corley

Click for Corley’s full report, “2009 Crude Oil & Natural Gas Hedging Study:” enriskpartners2009hedgingstudyresults.

For more on current hedging trends in E&P, look for the upcoming article, “Hedging Horizon,” in Oil and Gas Investor’s April 2010 edition at OilandGasInvestor.com.

Booking proved undeveloped petroleum reserves has become a give-and-take exercise under new U.S. SEC regulations. Oil and gas companies are reporting both upward and downward year-end PUD revisions in the same properties.

– Based on a new “reasonable certainty” standard, companies are reporting PUD locations at distances greater than one legal offset from economically producing wells in their year-end 2009 results. That has boosted PUD reserves, especially from shale-gas locations.

– Reporting companies took PUD wells off the books if they were scheduled to be drilled more than five years from initial PUD assignment. Few exceptions were made, but more were expected in 10-Ks to be filed on or before March 15.

Cabot Oil & Gas Co. reports it made an exception for 16 Bcfe of PUD reserves delayed by “external factors.” However, it removed 120 Bcfe of PUDs that fell outside of the five-year development window by reclassifying them to probable. That was consistent with a reallocation of its capital program to develop assets in Pennsylvania and East Texas.

Across the industry, proved reserves, including PUDs, also dropped because average commodity prices for the year were lower than year-end prices. The SEC changed the rules from a one-day year-end price to an annual average to lessen the effects of volatility.

Some companies detailed the extent to which the five-year limitation decreased PUDs and multiple offsets increased them. For Bill Barrett Corp., the net effect was to boost PUDs. The company said it included additional offsetting locations, where warranted, in the Williams Fork formation in Gibson Gulch, a basin-centered, “continuous” accumulation of gas. That increased PUDs for the field by 64 Bcfe. The five-year limitation “had a nominal impact of reducing reserves by 7 Bcfe,” the company reported.

For The Williams Cos. Inc., the net effect was a “wash.” Williams reclassified 496 Bcfe of reserves from PUD to probable because of the five-year limit, while adding 454 Bcfe of PUD reserves through additional offsets.

Companies also assigned PUD locations more than one direct offset from a producer not only in shale, but also in conventional accumulations. Barrett’s Williams Fork produces from sandstone reservoirs.

–Mike Wysatta

About the Author: Mike Wysatta is business-development manager for Ryder Scott Petroleum Consultants based in Houston. He can be reached at 713-651-9191 and mike_wysatta@ryderscott.com.

Click for the PDF of Wysatta’s full report on this, including how the new SEC reserve rules were incorporated in year-end results for Newfield Exploration Co., Pioneer Natural Resources Co., EQT Corp., Petrohawk Energy Corp., Noble Energy Inc., Range Resources Corp., Bill Barrett Corp., Ultra Petroleum Corp., OAO Novatek, Rosneft, Petrobras and Chesapeake Energy Corp. and other reserve-analysis articles in the March-May 2010 issue of Ryder Scott’s Reservoir Solutions newsletter: reservoirsolutionsryderscottmarch2010.

Castlen Kennedy, a University of Texas student, is currently driving a converted 2009 Chevy Tahoe during the trek, and reporting his experience in a blog titled “The Green American Road Trip.”

Yesterday, Kennedy arrived in Houston to gas up (heh, that expression has new meaning here) at a natural gas station on Washington Avenue.  She demonstrates the way a NG pump differs from a regular gasoline pump. Well, at least you don’t have to worry about spills.

Currently, only Honda’s Civic GX comes from the factory with a natural gas kit. Other cars require an EPA-approved conversion kit. So why did Kenney go with a Tahoe? Well, I’ll let her tell her own story.

First and foremost, I’m a Texan y’all. Its one thing to show people you can run your car on natural gas but its another to show them you can do it with a variety of vehicle types - and there’s probably one that will suit your preferences. If you’re from Texas and you like big cars, or you have five kids and you need a big car, CNG will still work for you. You don’t have to all pack into a clown car to feel like you are making a good choice.

Second, I need the extra space for tank capacity. Remember 6th grade science class when we learned that gas molecules like to be farther apart than liquid molecules? Well apply that here - CNG takes up more room than gasoline so I need the physical space for the tanks. I’ll do a post just on the tanks soon.

Third, I’ll be using a domestic fuel, so why not a domestic car. Please don’t send me Honda hate mail, I know some are manufactured here but you get my point. I like Hondas, in fact I have an Accord, but for this Great American Road Trip, the Chevrolet is a great fit. This collection of Chevy commercials I found on YouTube helps sum up the “American” - Chevrolet connection pretty well. (At least according to Chevrolet!)

And finally, the good people at Apache Corporation who are letting me borrow the car for my trip wanted a Tahoe. They will put it to good use after my trip, and that’s the most practical vehicle for their needs. So there you have it. Its been ordered and is being ‘converted’ as we speak. When its ready, I’ll post pics here. Stay tuned.

So that’s it for now. I’ll stay tuned in, and you should too.

-Stephen Payne, Editor, Oil and Gas Investor This Week; www.OilandGasInvestor.com; spayne@hartenergy.com

–on a path of more than doubling its size on a production and reserves basis over the next three to four years.

–a likely takeout candidate for $20-billion-plus companies looking to enter the U.S. shales.

–achieving some of the best rates of return in the business for its core development as oil prices continue to stabilize.

–setting its sights on the Cana shale, after years of skepticism about unconventional assets.

–off to a great start opening a massive trend in the Gulf of Mexico.

–using its experience in working high-decline assets in the Rockies to turn solid profits in the Marcellus shale.

–based in U.S. but blazing an impressive exploration trail overseas under the guidance of an E&P veteran.

–making the most of $70 oil in the Permian Basin.

–combining low operating costs and 20% production growth rates that can be repeated for the next three years.

As a complement to the story, an exclusive audio interview with Fadel Gheit, managing director of oil and gas research, Oppenheimer & Co., is now posted at OilandGasInvestor.com. Gheit discusses investor sentiment toward energy, favor for oil-weighted E&Ps and top stocks’ characteristics.

–Bertie Taylor, Senior Editor, Oil and Gas Investor, btaylor@hartenergy.com, 713-260-6497.

“…A Barnett package of assets would probably be a lot easier to value at this point than an Eagle Ford package….”

Discount rates among shale plays continue to be diverse, based on which plays have proven to perform, says Jim Parkman, co-founder and managing director of energy investment-banking firm Parkman Whaling LLC.

“I’m not sure that we totally understand how to value the shale reserves yet because we’re not sure what the ultimate (recoveries) are,” Parkman says in the complimentary webinar “Jim Parkman’s Observations On The Recent Reorg Cycle, And Forward Markets” hosted by OilandGasInvestor.com and now available on demand.

“We don’t have a clear picture of the decline rates and, of course, you don’t know what your total reserves are so, any time you have that level of uncertainty, you tend to see, from the practical point of view, the discount rate moving up. That’s going to vary by company and company.”

An energy investment banker for nearly 30 years, Parkman is a leader in energy-company workouts and capital-structure reorganizations, with recent assignments including the restructuring/reorgs of Energy Partners Ltd., Edge Petroleum Corp., Foothills Resources, Beryl Oil and Gas, Bigler, Storm Cat Energy Corp. and four other energy companies.

“In my practical experience, you can have some wildly different analysis in a competitive situation for shale-type assets and that’s probably a result of one party looking at a 25% pretax discount rate and another party looking at a 15% pretax discount rate. So, for shale-type assets, you would expect a huge variation of valuation and, as time passes, that would tend to narrow as industry develops a consensus on how the various shale-type investments will perform….

“For example, a Barnett package of assets would probably be a lot easier to value at this point than an Eagle Ford package of assets…I’d expect a good deal of variability within and among the different shale plays.”

Parkman describes three stalking-horse transactions in the webinar. Does the stalking-horse process work for small deals, say between $1- and $10 million?

“I don’t think there is any difference with the size,” he says. “I think the stalking-horse transaction can be designed at any size. You probably have more competition with the small transactions, so I would say ‘yes, it probably works,’ except for transaction cost because, of course, there usually is a break-up fee related to a potential purchaser taking a stalking-horse position and, if the break-up fee is not large enough to cover the transaction cost, it may not be too appealing.

“So, in theory, there may be a lower limit on whether or not the stalking horse process is functional.”

Hear these and more of his remarks in the complimentary webinar “Jim Parkman’s Observations On The Recent Reorg Cycle, And Forward Markets,” which includes a PDF of Parkman’s slides.

Does he expect E&P bankruptcies this year? “There is always the risk of bankruptcy or meltdown of E&P companies, especially given the widespread adoption of hedging strategies,” he says, “because, if there is counterparty failure or default…, there can be a liquidity crisis and a consequent meltdown scenario…

“There can always be, in any conditions, potential bankruptcy…There are some companies that have been able to accrete through the downturn without requiring restructuring or bankruptcy…but, compared to this time last year, we’re in a far better position because, this time last year, I would have said there would be at least 10 bankruptcies before the end of the year and I’m certainly more optimistic about that (in 2010).”

–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Hart Energy Publishing; Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com, UGcenter.com Today, EPmag.com, E&P Buzz, PipeLineandGasTechnology.com, PGT News, HartFUEL.com, FUEL.

“Institutional investors want to know that their equity isn’t locked up—this is the primary catalyst that shut down the PIPEs when the financial market crashed,” explains Adam Connors, director with California-based C. K. Cooper & Co.

Consistent PIPEs in the E&P space started to dry up in late ‘08/early ’09, then all equity financings essentially disappeared. In late 2009 public offerings and registered direct deals reemerged and flourished, largely because these issues were readily trading; companies that weren’t shelf eligible just weren’t generating interest due to the illiquidity risk, Connors says.

“The shift is a product of two things. One, there’s a lot of volatility in the markets. We see it in how bipolar commodity prices are and in the macro-economic trends that have emerged during the past few months.”

People are still skittish about the economy overall. When news is released these days, especially of a geopolitical nature, there is a much greater variance in commodity price swings. As a result, the safer bet for institutions to appease their needs/investors is to stick with more liquid options.

“They really like companies that have adequate volume. This would let them rapidly get out of their position—if they had to—with a velocity that would meet their fund’s appetite for risk. The retail folks are more flexible, but as companies mature they tend to want the institutions to make up a larger portion of the shareholder base.”

Are PIPEs a thing of the past in E&P finance? Not necessarily. Endeavour International Corp. just announced one of the first E&P PIPEs to cross the finish line in months: a $21.1-million PIPE via investments from Smedvig Capital, Pelmer Securities, Sanders Morris Harris and others, which included some of the E&P’s officers and directors, individual investors, trusts, pension funds, and foundations.

“This one is a little different because it’s participants are already well invested in the issue. They’re fine with having their shares being locked up—typically six months or so, per the SEC—because they are essentially locked up anyway.”

Connors concluded, “If there’s more stabilization in the economy and funds’ appetite for certain investments, PIPEs can get some of their appeal back. However, when this happens, investors will be commanding higher discounts for the offerings to manage that liquidity risk.”

For more of Adam’s comments, see his recent video interview with Oil and Gas Investor’s E-Editor Nissa Darbonne at the Winter NAPE Video Interviews section of OilandGasInvestor.com.

–Bertie Taylor, Senior Editor, Oil and Gas Investor, btaylor@hartenergy.com, 713-260-6497.

Boone Pickens started his campaign in the summer of 2008 in Washington for legislation that incents natural gas as a transportation fuel. Now, Congress will consider HR 1835 that does this. He’s confident the legislation will be passed, he told Texas Independent Producers and Royalty Owners Association (Tipro) members at their annual meeting in Houston recently.

Reasons include the obvious—encouraging greater use of domestic natural gas as a fuel choice in lieu of imported oil just makes sense. Pickens, chairman of Dallas-based energy investor BP Capital, is confident for another reason: After 30 years of lobbying Washington, he hasn’t been successful. This time, he says with his trademark, wildcatter-style, poker-table-type courage, “what the hell? I spent $62 million. I should get something done.”

More Boone-isms from his remarks at the Tipro meeting:

–His last book is “The First Billion is the Hardest: Reflections on a Life of Comebacks and America’s Energy Future.” He says his next book will be “I Can Show You How to Get Rid of $2 Billion Faster Than You Made $1 Billion.”

–He was introduced at the Tipro program as an advocate for natural gas and as a “wind man,” the latter of which was withdrawn for its gastronomical humor. He replied, “You don’t want to be introduced as a ‘wind man,’ but you don’t want to be introduced as a ‘gas man’ either, so I still like to be known as an oil man.”

–Washington needs an energy policy. His father explained more than 60 years ago that “a fool with a plan is better than a genius with no plan.” America has been “a fool with no plan…We are not going to be a fool without a plan. We don’t want to be a fool with a plan, either.” HR 1835 is “genius with a plan.”

–A former, leading U.S. State Department member told him some time ago that America’s dependency on imported oil reduces its leverage. “With our dependency on oil, we lose a lot of flexibility at the State Department.”

–While Washington worries about healthcare, education and other issues, these won’t matter without an energy plan “because you won’t have any money for any one of them,” while sending billions of dollars overseas for oil.

–Estimates were a couple of years ago that the U.S. has more than 2,000 trillion cubic feet (Tcf) of recoverable natural gas reserves, a great deal of these as a result of technological and economic breakthroughs in surfacing shale gas, and a newer estimate is of more than 4,000 Tcf. The difference may be a matter of decades, and both the low and high number is far more than 100 years out at current demand. “No one will ever know you made a mistake. I’ll (at 81 now) be gone.”

–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Hart Energy Publishing; Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com, UGcenter.com Today, EPmag.com, E&P Buzz, PipeLineandGasTechnology.com, PGT News, HartFUEL.com, FUEL.

In the blog, I quoted Mr. Moffett as saying, “Porosities are 13% to 22%. You get different readings from different logs. But downdip, the porosities go to hell, so we have a lot to learn. The challenge starts now. This looks a lot like the fields we drilled when we were young.”

Seems I tripped up a bit here and so, I’d like to apologize and make it right. According to MMR spokesman Bill Collier: “The first two sentences are specific to the initial results McMoRan has obtained on Davy Jones thus far [big porosities and yet, different readings from different logs employed].”

“But, the third sentence [downdip] was a general comment about porosity based on our experience working shallower fields.  Because we have only drilled one well, we do not know what the porosities are downdip at Davy Jones at this time.”

Indeed, McMoRan intends to spud a second well later this year, and to flow-test the disocvery as well.

Collier goes on to say: “Our experience from analyzing shallower fields suggests that porosities are preserved updip in hydrocarbon columns where water cannot compromise the rock porosity.  Downdip, when water occurs in the pore space, ‘diagenesis’ (a change in mineralogy caused by fluids migrating through the pore spaces with precipitation of minerals in the pores) can come into play, which can cause a reduction of porosity.

“As we stated in our January 11, 2010, press release, the zones encountered at Davy Jones are full to base, meaning we have not encountered a water level in the various zones encountered to date.

“We plan to commence drilling an offset delineation well at Davy Jones in the coming weeks. The important information to be gained from the flow test on the discovery well, results from the offset well, and future drilling will be vital as we continue to define the ultimate size and productive capabilities of this exciting discovery.”

And there you have it. Everyone in the industry looks forward to the announcement of results from the flow test oif the first well later this tear, and from second, delineation well later on.

Leslie Haines

Tudor, Pickering, Holt & Co. analysts think a wave of oilfield service consolidation is premature thinking. “It doesn’t really change the landscape that materially—the biggest player is getting bigger—and it doesn’t force anyone to combine defensively.”

But Pritchard Capital Partners analyst Brian Uhlmer sees the landscape differently and painted a picture of the possibilities.

“There is always potential to ride the acquisition speculation in several names. The ones at the top of the list in our opinion that are most likely are in the pressure pumping/well-servicing space. For management teams that are seeing pricing leverage in certain plays beyond what the stock market is pricing in, there may be opportunities for accretive transactions.”

The first on the list, he says, is Superior Well Services Inc. With its newer fleet of equipment and footprint in the Marcellus, it is a potential target for both Patterson-UTI Energy Inc. and Nabors Industries Inc. as well as certain Canadian listed players.

The next potential is for Complete Production Services Inc. to merge with Basic Energy Services Inc., benefiting by expanding the Texas market, although Uhlmer sees this combo as a long shot.

The offshore drillers have a need to consolidate, he says, and the likely suspects are Ensco International Inc. with Noble Corp. and Pride International Inc. with Seadrill. Pride already has the take-out premium in place and “would be bought out (in the) $35 neighborhood, while Ensco lost its premium with the move to the U.K. and would be around a $55 acquisition price and thus be a more attractive speculative buy.” Both transactions would be primarily stock if they were to happen, he surmises.

For manufacturers, T-3 Energy Services is an excellent candidate either for National Oilwell Varco to grow its BOP capacity or the LeTourneau/Stewart & Stevenson three-way merger talk could begin again later this year.

Tesco Corp. is another name that circulates, “but there is not a considerably large market for acquirers who need to add top drives to their existing suite of products.” Then there is Dril-Quip, always discussed either to be acquired by National Oilwell Varco, General Electric Co. or FMC Technologies, all of who could use the complimentary products and manufacturing capacity.

Finally, the piece de resistance: a SIPES luncheon where Jim Bob Moffett, co-chair of McMoRan Exploration Co.,  spoke on the huge Davy Jones find on the Gulf of Mexico shelf. How’s that for a great run?

At NAPE it was clear that the industry’s mood is lighter again, and were it not for the uncertainty about natural gas prices, people might have been jubilant. The reason? The shales just keep coming, and some big finds elsewhere are about to jump-start the next leasing frenzy.

First, the shales. Many exhibitors at NAPE showed Eagle Ford and Marcellus deals. But we noticed oily-shales such as the Niobrara starting to command more attention. (A landman friend called to say that the courthouse in Converse County, Wyoming, is overrun with landmen and every restaurant in town the same…and they are chasing the Niobrara or Mowry shales in southern Wyoming.)

Now the rumor is that Rosetta Resources has a big shale well like the Bakken out in Glacier County, Montana, some 400 miles west of the main Bakken fairway. If that pans out and more wells are drilled, then boy howdy–a little side trip to Glacier National Park is in order.

The Bakken play, meanwhile, continues to allow operators to showcase what horizontal drilling and frac stages can do. Brigham has reported several wells flowing more than 1,500 barrels per day and has reported fracing one well 32 times as the lateral legs keep expanding further from the wellhead, said CFO Gene Shepherd Jr., speaking to the Houston Energy Finance Group.

The company’s #1H State 36-1 flowed 3,807 barrels of oil equivalent per day from Middle Bakken, in the eastern portion of its Rough Rider project area. “Our four most recent wells IP’d at 3,300 barrels a day,” he said. The comoany has 700 potential horizontal locations in its core area.

Out to the Shelf. McMoRan’s Davy Jones find on South Marsh Island Block320 looks like a big one. The next hurdle is getting a flow test done.

Co-chairman Jim Bob Moffett was in fine form as he told an overflow crowd at a Houston SIPES luncheon that the only question is, should the test equipment be good for 20,000 pounds of pressure, or 25,000? If the latter, the equipment needs to be ordered and the MMS has to OK it, so the test won’t happen until well into the second half of 2010.

“440 degrees is the highest temperature we’ve seen but that doesn’t bother me. We’ve see that elsewehere, like at Mobile Bay, but when you combine it with these high pressures, this is a challenge,” he said. “It takes moxie, but winners never quit and quitters never win. These things are all too damn close to call. But these are the cleanest sands I’ve ever seen–no  bitumen, no feldspar, no H2S.

“Porosities are 13% to 22%. You get different readings from different logs. But downdip, the porosities go to hell, so we have a lot to learn. The challenge starts now. This looks a lot like the fields we drilled when we were young.”

–Leslie Haines, Editor-in-chief, Oil and Gas Investor

lhaines@hartenergy.com

–Cameron Smith, Formerly Managing Director, The Rodman Energy Group: Cameron Smith, the founder of COSCO Capital Management LLC that became The Rodman Energy Group, discusses his view of the capital markets and his plans to check off “bucket list” goals in the coming year.

–Bryant Patton, Principal, BryCap Investments Inc.: Bryant Patton, principal of oil and gas investment firm BryCap Investments, discusses his interests in producer Sendero Energy Partners LP, midstream firm Teak Midstream and producer Cinco Resources, into which his Camden Resources was merged, and using unconventional-well technology in conventional plays in West Texas and Oklahoma.

–Tim Murray, Managing Director, Guggenheim Partners: Tim Murray, managing director for energy mezzanine-investment firm Guggenheim Partners, describes the recapitalization of Gulf Coast Basin-focused Milagro Exploration, the firm’s investments through this past capital-markets cycle, conventional vs. unconventional plays and what the firm is investing in in 2010.

–Neil Carpenter, SVP, Worldwide Sales, Wellpoint Systems Inc.: Neil Carpenter, senior vice president, worldwide sales, for Wellpoint Systems Inc., discusses energy producers’ concerns with costs and contrasts how downstream vs. upstream energy companies deploy technology.

–Charlie Chambers, Founder & CEO, Chambers Oil & Gas: Charlie Chambers, founder and CEO of Chambers Oil & Gas, and former acting president of Rosetta Resources, describes his plans for his new family-owned E&P company.

–Bill Weidner, Managing Director, The Rodman Energy Group: Bill Weidner, managing director, The Rodman Energy Group, discusses his 2010 outlook for private equity’s opportunities and challenges for the upstream energy sector as well as his view of the growing importance of midstream infrastructure in new shale plays.

–Murphy Markham, Partner, EnCap Investments LP: Murphy Markham, a partner in EnCap Investments LP, describes the firm’s private-equity midstream investments with investment partner Flatrock Energy Advisors, its approximately $2 billion available to place upstream, and raising a new upstream fund that may bring total capital available to deploy to some $4 billion.

–Bret Bolin, President & CEO, P2 Energy Solutions: Bret Bolin, CEO and president of P2 Energy Solutions, discusses the need for greater integration to enable companies to become more efficient and profitable. A single technology platform provides an elegant infrastructure.

–Eric Thurston, Vice President, P2 Energy Solutions: Eric Thurston, vice president of P2 Energy Solutions, discusses Excalibur, the company’s newest offering. Excalibur is a comprehensive suite of more than 30 modules that address all the critical business requirements and workflows of an oil and gas producer.

–Marc Lawrence, SVP, Division Manager, Data Licensing Division, Fairfield Nodal/Fairfield Industries: Marc Lawrence, senior vice president and division manager, data-licensing division, for seismic firm Fairfield Nodal/Fairfield Industries describes current demand for seismic data and analysis, and renewed interest in shallow-water, deep-shelf Gulf of Mexico exploration due to huge Davy Jones and other prospect results.

–Greg Pipkin, Managing Director, Investment Banking, Barclays Capital: Barclays Capital managing director, investment banking, Greg Pipken delivers his perspective of corporate M&A, including his involvement and unique perspective of the Denbury Resources/Encore merger and ExxonMobil’s acquisition of XTO Energy.

–Gerry Conroy, Vice President, Product Management, P2 Energy Solutions: Gerry Conroy, vice president, product management, for P2 Energy Solutions, describes producers’ emphasis on cost management during this commodity-price cycle, estimates for the industry needing to drill 30,000 shale-gas wells and what top oil and gas producers do that make them successful.

–Dan Steele, SVP and Manager, Energy Lending Group, Bank of Texas: Dan Steele, senior vice president and manager for the energy lending group at Bank of Texas, shares his views on capital-raising activities in 2010 and how the next round of credit redeterminations should be less painful for many producers this year. 

–Bruce Vincent, President, Swift Energy Co.; Chairman, IPAA: Bruce Vincent, president of onshore U.S.-focused Swift Energy Co., discusses the company’s work in the Eagle Ford shale-gas play and in Louisiana conventional-oil plays, investor interest in oil-weighted E&P companies, and his work in Washington in explaining how proposed new law and policies would affect the U.S. oil and gas industry to Harry Reid and Nancy Pelosi, and to President Obama via energy czar Carol Browner.

–Aliza Dutt, VP & Senior Equity Analyst, IHS Herold: Aliza Dutt, vice president and senior equity analyst for IHS Herold, describes her outlook for equities and the industry this year. Herold finds capital spending is going up again.

–Scott Noble, Founder & President, Noble Royalties Inc.: Scott Noble, founder and president of Noble Royalties Inc., gives his take on changes in minerals valuations from prior years, the revived pace of A&D and geographic areas that are causing the most buzz for buyers.

–Nathan Oliver, VP, Gulf of Mexico, Multi-Client Data, PGS/Petroleum Geo-Services: Nathan Oliver, vice president, Gulf of Mexico, multi-client data, for PGS describes the resurgence in the Gulf of Mexico driven both by recent large discoveries and by new technology such as wide-azimuth seismic acquisition.

–Steve Kennedy, SVP and Energy-Group Manager, Amegy Bank: Steve Kennedy, senior vice president and energy-group manager for Amegy Bank, describes his view of the pace of energy capital investments and his long-term outlook for oil and gas in the U.S.

–David Preng, President & Founder, Preng & Associates Inc.: David Preng, president and founder of energy-focused recruiting firm Preng & Associates Inc., describes oil and gas producers’ renewed demand in 2010 for both executive and technical personnel, and continued demand for value-adding energy-company board members.

–Mike Ming, President, RPSEA (Research Partnership to Secure Energy for America): Mike Ming, president of RPSEA (Research Partnership to Secure Energy for America), describes his organization’s commitment to research in ultra-deep water, unconventional resources, and small producers and promotes more government funding for oil and gas research.

–Adam Connors, Director, Corporate Finance, C.K. Cooper & Co.: Adam Connors, director, corporate finance, for investment-banking firm C.K. Cooper & Co., describes stock investor interest in traditional and highly-liquid energy securities currently, a decline in interest in PIPEs and other securities with monetization restrictions, and what oil and gas stories are winning investment-market favor today.

–Bryan Chapman, EVP, Energy Lending Manager, Iberia Bank: Bryan Chapman, executive vice president and energy-lending manager for Iberia Bank, discusses the bank’s recent entry into the energy-lending space, his team’s strategy for connecting with clients in 2010 and his outlook for oil and gas.

–Adrian Goodisman, Managing Director and Co-Head, U.S., Scotia Waterous: Adrian Goodisman, co-head, U.S., and managing director, Scotia Waterous, provides his insight on the state of the A&D market and particularly for the Gulf of Mexico and international.

–Mike Lakin, Managing Director, Envoi Ltd.: Mike Lakin, managing director of Envoi Ltd., sees U.S.-headquartered companies taking their unconventional expertise overseas to prospect for shale gas on distant shores.

–Ward Polzin, Managing Director, Tudor, Pickering, Holt & Co.: Tudor, Pickering, Holt & Co. managing director Ward Polzin explores whether any momentum remains in the JV market, who is buying and selling oil and why, the value of an oil PUD, and how oil metrics compare to gas.

–Andy Clifford, President, Saratoga Resources Inc.: Andy Clifford, president of Saratoga Resources, describes the company’s efforts to emerge from Chapter 11, and that it is looking for partners for its offshore prospects, which may be on trend with McMoRan Exploration’s recent discoveries.

–Jim Sledzik, Partner and President, Houston Office, Energy Ventures AS: Jim Sledzik, partner and president, Houston office, for oilfield-technology investment firm Energy Ventures AS, discusses new products that are being put to work in developing unconventional-resource plays by portfolio companies Ingrain Inc., Oxane Materials Inc., Fotech Solutions Ltd. and Ziebel AS, ranging from nanotechnology proppant to fiber-optic formation monitoring, and he describes the recent monetization of Fund III investment NovaDrill, and the advancement of other investments toward business-plan maturation and sale.

–Phil Martin, CEO & Founder, New Century Exploration Inc.: Phil Martin, chief executive officer and founder of onshore U.S.-focused New Century Exploration Inc., describes public vs. private E&P companies’ access to shale-gas plays, New Century’s plans to grow its shale-gas portfolio and how he has formed a retail electric provider, True Electric, that serves as a hedge against natural gas prices.

–Ramona Hovey, SVP, Products, DrillingInfo: Ramona Hovey, senior vice president, products, for data- and information-services firm DrillingInfo, discusses producers’ continued interest in shale-gas drilling data, results in the Barnett oil play, and how analysis of operator differences suggests a best or “better of class.”

–Tim Rotchford, Chairman, Arena Resources Inc.: Tim Rotchford, chairman of publicly held, Tulsa-based Arena Resources Inc., describes investor interest in the company’s 85% oil-weighted portfolio, its large holding in the prolific Fuhrman Mascho Field in West Texas, and its attention to new oil-shale plays.

–Kamil Tazi, Vice President, Engineering &  Planning, Cordillera Energy Partners: Kamil B. Tazi, vice president of engineering and planning for private E&P company Cordillera Energy Partners III, talks about the Denver-based firm’s focus on the multiple stacked pays of the Texas Panhandle and western Oklahoma, particularly the Granite Wash, Tonkawa and Cleveland reservoirs. These “gas-plus” plays offer high NGL yields and premium economics.

–Kurt Abraham, Vice President, Texas Alliance of Energy Producers: Kurt Abraham, vice president, Texas Alliance of Energy Producers, analyzes industry issues and describes the group’s 2010 media campaign to educate the public and lawmakers about the oil and gas industry.

–Nissa Darbonne (ndarbonne@hartenergy.com), E-Editor, Hart Energy Publishing; Oil and Gas Investor, A&D Watch, Oil and Gas Investor This Week, OilandGasInvestor.com Today, OilandGasInvestor.com, A-Dcenter.com, UGcenter.com, UGcenter.com Today, EPmag.com, E&P Buzz, PipeLineandGasTechnology.com, PGT News, HartFUEL.com, FUEL.

When discussing natural gas prices, people may think of Henry Hub or another gas-trading hub. However, when discussing natural gas costs, there is no accepted measure to turn to. A simple analogy to consider is to examine the cost of a backyard do-it-yourself BBQ hamburger that you cook at home with the family. The layers are fairly simple: a bun, green lettuce, red tomato, meat, pickle, and cheese to top it off. The cost to buy these ingredients might come to $1.25.

Similarly, the cost of the natural gas hamburger includes royalties/taxes, operating costs, finding and development expenses, overhead, some profit (the return to investors) and the cost of transportation to get the gas to market. The total of these increments added to more than $7 an Mcf in 2008, far more than the price realized at the trading hubs.

A good handle on the relative cost to explore, develop, produce and market natural gas across the various gas basins in North America is important to an investor who wants to determine where to direct funding for the best return. For years, getting accurate cost data for gas from various producing basins was very challenging, if at all possible.

Based on ground-breaking research, in early 2008, Ziff Energy published the first complete, full-cycle gas analysis of 85 plays from two dozen gas basins. The next cost study of North America gas basins is currently being finalized using cost data as of late 2009 (the current low gas price/low cost environment). Economic ranking of the gas basins across North America will determine which regions producers are funding and which basins will see continued slowdown.

For mergers, acquisitions and divestitures, is it better to buy gas reserves, or is it better to explore, develop, produce and market?

The answer depends on the specific gas basin. This age-old question is being asked by boards of directors and by executive managements conducting due diligence on pending deals. Even service companies, such as drillers, pipelines and suppliers, would benefit by knowing the economic ranking of the major gas basins so they can focus their services and equipment to where producers need it most.

State and provincial governments will be better stewards of their producing communities if they understand the relative economics of basins. They will be better able to assess the impact of tax/royalty options and development issues which will impact (positively or negatively) incremental investment by operators, and therefore increase regional gas production.

Exploding growth among various shale-gas basins leads to a similar question. Which shale-gas basin is most attractive to invest in from a total cost perspective? Cost assessments of Barnett (Fort Worth), Arkoma, Haynesville, Marcellus, Appalachian and Canadian shales will be included in the upcoming study.

Graphically impressive, the new edition of the North American gas-basins study will help to explain the cost structure of all the significant conventional and unconventional gas basins.

–Bill Gwozd

About the Author: Bill Gwozd, P. Eng., is vice president, gas services, for energy-research and -consulting firm Ziff Energy Group. He can be reached at 403-234-4299 or bill.gwozd@ziffenergy.com.

What can we say about the T indices for the petroleum complex? For the Nymex heating-oil and gasoline futures markets, the T indices are within range of what had not been considered excessive for the agricultural futures markets.

For the very brief time period that we have ICE Futures Europe data, the conclusion for the ICE WTI contract is the same as that for the Nymex heating-oil and gasoline contracts.

As long as one includes options positions, the T indices for the Nymex oil futures markets are not excessive, again, provided that it is acceptable to use the historical agricultural futures markets as a guide to the adequacy (or excess) of speculation. It is also noteworthy that from the summer of 2007 to the summer of 2008 the Nymex WTI oil futures market did become more speculative (relative to hedging), even if the data for futures and options combined showed that the peak T index would not be regarded as excessive using our historical benchmarks.

Now, to be circumspect in our conclusions, we must note that if we exclude the option positions in the Nymex oil data, the futures-only data would potentially indicate excessive speculation in the U.S. oil futures markets.

We must clearly be careful about how strongly we word our conclusions. Within the closed system of the US oil futures and options markets, we find no evidence of excessive speculation, at least not when we use traditional metrics and when we include options positions with outright futures positions.

Also, if excessive speculation can be defined differently than as in our paper, then obviously we cannot say for certain that there has not been excessive speculation in the oil derivatives markets. Nor are our conclusions necessarily incontrovertible, if it is inappropriate to use the historical balance of agricultural speculation versus hedging activity to categorize this balance in the oil markets.

In addition, we have not examined whether futures-spreading activity over the past three years could have constituted excessive speculation. Finally, we cannot say there has not been excessive speculation in the oil markets through other venues.