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E&Y benchmark study2010 capex boosts reserves, production

Development spending in the U.S. by the 50 largest E&P companies, as measured by year-end 2010 reserves, rose 36% in 2010, and exploration spending rose as well. But, the substantial reserves and production increases that followed could not keep up with the pace of increasing costs, according to Marcela Donadio, Americas' oil and gas leader for Ernst & Young LLP's Energy Center.

End-of-year proved oil reserves grew 11% and natural gas reserves grew 12% in 2010, the strongest combined annual growth posted in five years, according to Ernst & Young's 2010 U.S. E&P Benchmark Study.

Ending oil reserves for the 50 largest public companies reviewed rose to 17.8 billion barrels, an increase of 11%. Oil production was flat at 1.3 billion barrels for both 2009 and 2010.

Ending gas reserves totaled 174.3 trillion cubic feet (Tcf), increasing 12%, mostly as a result of strong shale development. Gas production in the U.S. for the 50 companies was up 1% to 11.9 Bcf.

The benchmark study includes activity related to XTO Energy Co., which was acquired by ExxonMobil in 2010. The 50 companies range in size from ExxonMobil to the likes of Chaparral Energy Inc. and QEP Resources Inc. The 50 in aggregate account for 71% of U.S. natural gas reserves.

Reserve replacement costs on a total basis, including proved property acquisitions, were up once again, increasing to $15.26 per BOE in 2010 from $12.78 per BOE in 2009. Reserve replacement costs on a finding and development basis, excluding proved property acquisitions, increased to $17.84 per BOE, up from $13.01 per BOE in 2009.

The oil production replacement rate from all sources (including extensions and discoveries, improved recovery, reserve revisions, purchases and sales of proved reserves) was 234% in 2010. The all-sources natural gas production replacement rate was 252%.

"More importantly, production replacement rates, excluding purchases and sales, were also very strong in 2010, at 205% for oil, 249% for gas, and 232% on a combined BOE basis."

Production costs rose 9% to average $11.90 per BOE. Finding and development costs were $17.84 per BOE.

On a combined basis, the increase in exploration and development spending was primarily driven by ExxonMobil, Chesapeake Energy Corp. and EOG Resources Inc. Only four of the companies in the study saw decreases in their combined exploration and development spending in 2010.

"To a large degree, the increase in capital spending was driven by property acquisitions, and ExxonMobil's acquisition of XTO accounted for about half the increase from 2009 to 2010," Donadio says.

The full report is available at ey.com/us/oilandgas.

—Leslie Haines

BP's 60th world energy review records some firsts

British Petroleum Plc's recently released 60th annual Statistical Review of World Energy notes a number of firsts, among them China's ascendance as an energy consumer. China in 2010 surpassed the U.S. as the No. 1 consumer of energy. Using 20.3% of the world's energy, China eclipsed the U.S. by 1.3%, only a few percentage points behind the entirety of Europe and Eurasia.

The annual review depicts consumption growth across geographies and primary fuel types, including oil, natural gas, coal, nuclear energy, hydroelectricity, renewable energy and primary energy sources.

Global energy consumption in 2010 rose 5.6%—the most robust annual increase since 1973—prompted by the global economy's recovery following the 2008 collapse. Energy use grew in mature economies as well as in developing nations.

Though oil is still the world's go-to fuel, in 2010 it suffered another year of demand decline.

"Oil remains the world's leading fuel, at 33.6% of global energy consumption, but oil continued to lose market share for the 11th consecutive year," BP reported. Global crude consumption grew at 3.1% after two years of decline. This was the weakest growth among fossil fuels. Total global consumption increased to 87.4 million barrels a day; production was up by 1.8 million barrels per day.

U.S. natural gas production accounted for 19.3% of world production in 2010, which was also the highest gas production by a single country. The U.S. simultaneously accounted for 21.7% of natural gas consumption. World gas production rose 7.3%, led by the U.S., Russia and Qatar.

China took the energy consumption lead on the back of coal, having produced 48.3% of the world's coal in 2010, and using nearly all of that production, 1,713.5 billion tons of oil equivalent. The coal consumption of the U.S.—second in the world—was 524.6 billion tons of oil equivalent. In no small part because of increased Chinese consumption, coal use saw the largest increase of any fuel, comprising 29.6% of global consumption last year, up 4% from 2000.

"Coal consumption grew by 7.6% in 2010, the fastest global growth since 2003. Chinese consumption grew by 10.1%," according to the report. Chinese energy consumption in aggregate was 11.2% of the global total.

In his introduction to the report, BP group chief executive Bob Dudley explained 2010 was also the first year that charts on renewable energy were included. Those charts indicate that despite growing by 15.5% in 2010, renewables as a portion of power generation make up only 1.3% of global primary power consumption.

Refining capacity continued to shift from the Americas to Asia, Africa and the Middle East in 2010. There was a modest increase in global refining capacity, and refining throughput for all capacity increased on a global basis by 2.4%. Middle distillates were the fastest-growing refined product around the world. Global refining utilization trended upward, although Africa and South and Central America experienced drops in utilization, bucking that trend.

The U.S. instead expanded biofuels production, leading increases globally.

"Global biofuels production in 2010 grew by 13.8%, or 240,000 barrels per day, constituting one of the largest sources of liquids production growth in the world," the report noted.

—Brian K. Tully

E&P spending predicted to sharply incline in 2011

Global exploration and production spending is expected to increase dramatically in 2011, according to a midyear update to Dahlman Rose & Co.'s Original E&P Spending Survey.

A higher oil-price forecast, modest increases in natural gas expectations and projections of greater cash flow are propelling an optimistic outlook among E&Ps.

The study of 445 companies suggests that worldwide E&P expenditures should climb by 14% this year, totaling $533 billion. Meanwhile, U.S. E&P spending in 2011 is expected to increase 22% to $122 billion.

In Canada, expenditure budgets are expected to rise 16% to $42 billion, and international E&P spending should increase 12% to $370 billion.

The projected increases are based on actual E&P expenditures reported toDahlman Rose in its 2010 end-of-year survey and are contrasted with companies' expectations for growth in 2011.

North American independents have increased E&P spending internationally since the end of 2010. Strong oil prices and a dwindling gap between oil demand and global oil production capacity are driving the trend, the report said.

The fundamental nature of the North American market has changed. James Crandell, managing director and global head of oilfield services research, attributes this shift to "drilling in the shales, horizontal drilling in the shales, and extending what were originally natural gas plays into crude oil.

"Business is much less volatile and cyclical than in the past, and I think we'll become a longer-cycle and more attractive business going forward," he told Oil­andGasInvestor.com.

Meanwhile, the study expects the number of rigs in the Bakken shale to hit 145 in 2011, up from 98 in 2010. The liquids-rich Eagle Ford shale is expected to have 155 rigs this year, compared with 73 the previous year. The Permian Basin, Niobrara and Granite Wash shale plays are also forecast to have good growth in horizontal drilling.

In 30 years of doing surveys, the 2011 midyear report is one of the strongest in terms of upward revisions of E&P spending, according to Dahlman Rose.

Furthermore, more than half of the companies surveyed think that E&P spending will remain strong in 2012.

"In 2011 and 2012, I think the major drivers behind E&P spending are an attractive level of oil prices for investment, higher cash flows for the industry to invest, and, particularly in the U.S., success drilling horizontally in the shale plays for crude oil and liquid-rich gas," said Crandell.

"Because companies consider (horizontal drilling) to be so attractive, I think it's going to be additive. One only needs to look at the breadth of the recovery to see that there are some 24 independents who've added at least $400 million to their E&P spending since the beginning of the year."

Companies that participated in the Dahlman Rose survey base their 2011 expenditures on an average crude price assumption of $87.31 per barrel and an average natural gas price of $4.53 per thousand cubic feet (Mcf).

On the international front, expenditures outside North America should show growth in 2011. Based on the responses of 153 companies that spent E&P money internationally, a 12% step-up is forecast for this year.

Dahlman Rose expects spending in Latin America to rise 26% in 2011, with production increases coming from Ecopetrol, Petrobras and Pemex. The gains from Pemex are expected to be concentrated offshore and in the southern part of Mexico.

The Middle East should continue to be a solid market in the last half of 2011, the report said. A 22% uptick is expected, and gains will be led by the Kuwaiti Oil Co. and, to a lesser extent, Saudi Aramco.

E&P spending in Africa is expected to dip 15% this year, with unrest in Libya being the key factor in the expected decline.

"Libya has taken away a little bit of the growth from exploration and production spending. MOC, the Libyan oil company, will spend only a small fraction of the $2.5 billion we thought the company would spend six months ago. So the Libyan piece of it is a negative. On the other hand, oil prices are probably higher than where they would be otherwise if this hadn't happened," according to Crandell.

Spending growth by companies based in the Asia-Pacific region is expected to be 12% in 2011. Chinese companies CNOOC, PetroChina and Sinopec; Petronas of Malaysia; and ONGC of India are expected to propel the growth.

Companies based in Europe and Russia expect to spend 11% and 7% more, respectively.

Dahlman Rose said that the most appealing stocks are major diversified oil-service companies, equipment managers benefiting from the surge in offshore rig construction, beneficiaries of a secular increase in deepwater/ultra-deepwater drilling, and North American-focused land drillers that benefit from an increased demand for fit-for-purpose land rigs.

Buy-rated stocks in Crandell's universe include Schlumberger (NYSE: SLB), National Oilwell Varco (NYSE: NOV), Halliburton (NYSE: HAL), Weatherford International Oil Field Services Ltd. (NYSE: WFT), Tenaris (NYSE: TS), Seadrill (NYSE; SDRL), Transocean Ltd. (RIG), Baker Hughes Inc. (NYSE: BHI), Tidewater Inc. (NYSE: TDW), Rowan Companies Inc. (NYSE: RDC), Oceaneering International (OII), Fred Olsen Energy (FOE: NO), Helmerich & Payne Inc. (NYSE: HP), and Patterson-UTI Energy Inc. (NASDAQ: PTEN).

Crandell, however, cites two factors that could cloud high expectations for E&P spending during 2011 and 2012.

"Number one is another economic downturn, which could cause oil demand to slacken and perhaps prices to come off meaningfully. And the second thing is a large increase in production by Saudi Arabia and its Persian Gulf allies, which would perhaps knock some of the froth off the market and cause some hesitancy in spending if prices decline," he said.

—Michael Madere

Raymond James: Gas to put on sizeable supply in 2011

Though the first quarter of 2011 hosted a drop in natural gas production due to wellhead freeze-offs, domestic supply will be up at least 4 billion cubic feet (Bcf) per day for the year. In a recent report, Raymond James & Associates indicates that 2010 saw an average increase of more than 2 Bcf per day on a year-over-year basis.

The freeze-offs shut in as much as 5 Bcf per day on occasion, and the firm's analysts report corroborating information from the Energy Information Administration showing a drop of 1.3 Bcf per day in the month of February. But with winter over, the firm anticipates strengthened production.

"After compiling the domestic production data from publicly traded producers, we expect to see a sequential jump in March EIA-914 natural gas supply of 2 to 2.5 Bcf per day," the firm notes, adding that pipeline flow data appears to corroborate its supply expectation.

Publicly traded producers historically account for about half of U.S. natural gas production and will likely continue to do so, despite assertions that public companies hold more shale acreage, according to the Raymond James analysts.

"U.S. supply will still increase by an average of 4 to 5 Bcf per day during 2011, even with the shut-ins," say the analysts, who believe one-time issues with pipeline capacity, frac crew availability and the Gulf of Mexico declines will give way to firmer production. Without shut-ins, the firm believes supply increases would likely have exceeded 5 Bcf per day. Analysts also point out that even with these temporary losses, production still managed a net increase.

Given the aggregation of these circumstances, Raymond James analysts hint at possible $3 gas, but concede the gas rig count peaked in August of last year. Even as the rig count continues to drop, however, production can and will increase, they say. This is based on their proposition that the industry can grow production "with less than 700 active natural gas rigs."

—Brian K. Tully

ECC 2011: Peering inside institutional oil and gas investing

Long-term investments in real assets are hot, according to institutional investors speaking at Hart Energy's 2011 Energy Capital Conference in Houston. While diversification is in most institutions' mandates, resources such as oil and gas are quite attractive investments, and more funds are trying to get oil and gas exposure. For institutions, the question is how to get in.

The University of Texas' endowment is the largest public university endowment in dollar terms, but is managed by a relatively small staff. Because of that, says Mark Warner, managing director of natural resources investments for The University of Texas Investment Management Co. (Utimco), being a general partner with private-equity firms is a workable avenue to enter into oil and gas investments.

Citing the correlation between growth and resource use driven especially by emerging markets, he said long positions on energy and resources are solid.

"We take the view that the world is a going concern. It wasn't 100% clear that was the case in the first quarter of 2009, but as a going concern, it is biased to grow," said Warner. The fund has in excess of $20 billion to invest, requiring at least an 8% return, including all costs and a distribution.

Lisa Ferraro, managing director of TIAA-CREF, one of the largest teachers' pension funds in the U.S., agreed with Warner's outlook. Ferraro and her team manage $2 billion in private investments allocated in sub-portfolios of debt, oil and gas private direct equity, infrastructure direct equity, and fund investments. The fund has an engineer and geologist on staff.

"What we are doing with our oil and gas strategy is we want to take a less volatile commodity exposure than we would get in shorter-term markets," she said. The fund looks for long-term holds and is not particularly exit-driven. Its medium-term strategy includes stock trading, and in the short term, it engages in foreign exchange. But it invests directly in oil and gas assets in order to exercise discretion on when to monetize reserves.

"We have direct equity because we can have input on when we drill for the resource, and when we wait out the market to get better pricing. Oil and gas is commodity-price driven, whereas most other assets are inflation driven," she said.

Ferraro's fund invests in debt, mezzanine and equity, with escalating demands on return for each. In equity, the fund invests a minimum of $40 million to gain a bit of control on the asset. She described some of the constraints on the fund that make direct investing in oil and gas tricky.

"Direct investing is very difficult to do from our perspective, because we are not operators. We have to find an operator with goals aligned with us." This takes a lot of time and research, and success is dependent on finding the right partner, she said.

"We don't do direct investing as a principal," said Warner.

Because his team is only four people strong, with $4- to $5 billion to invest in the market, being a partner immersed in investment companies is impractical. The Utimco team looks for opportunities that fit a theme, have low beta and can achieve the biggest compounding possible, wherever they might be in the energy value chain. The key to meeting these goals is the discretion of the fund's general partner, a company like EnCap Investments LP, with which Utimco has partnered in the past.

—Brian K. Tully

NFR's Sambrooks: Industry not thinking of a return to gas, yet

Some in the E&P industry think now is the time to be contrarian and chase conventional or legacy natural gas assets. Others have already committed to natural gas, and are navigating current low prices with an eye on the future.

"In our business, one of our benefits and faults is that we forget history very quickly. We seem to always think that whatever environment we are in today, is going to be the environment forever and a day," said NFR Energy LLC chief executive officer David Sambrooks. He addressed a combined group of the Texas Independent Producers and Royalty Owners Association and Independent Petroleum Association of America recently in Houston. Recalling higher oil and gas prices just three years ago, he said of the industry, "It's very cyclic and things change.

"I know this is obvious to everybody here, but the biggest change in the last three years has been the explosion in shale gas." He noted that just three years ago, the Haynesville shale had not been heard of beyond a small circle within the industry. "Today it's the largest gas field in the U.S."

NFR was formed in 2006 and operates as a joint venture between private-equity giant First Reserve Corp. and drilling contractor Nabors Industries Ltd. It is one of the few E&P companies formed by a partnership between finance and oilfield service firms.

Sambrooks described the NFR strategy as aggregation and consolidation of positions in the East Texas basin. Several years ago, smaller companies held acreage alongside majors in the Cotton Valley play, and Sambrooks guessed the smaller entities would not make the transition to expensive horizontal shale drilling programs. With that in mind, NFR was designed as a larger, stable company that could weather the inherent industry cycles, he said. Today, NFR has 1.2 trillion cubic feet of proved reserves with hundreds of well locations in East Texas.

Sambrooks said acquisition has been, and will continue to be, a key element in NFR's strategy. As a decidedly natural gas development company, acquiring and adding value to natural gas properties takes skilled execution.

"We've been very effective at driving down our finding and development costs," he said of NFR's success, explaining that he focuses on making margins and keeping cash flow coming into the company. Hedging is critical for the gas-centric company: nearly 90% of the company's forecast production for 2011 is hedged at over $6.

"That's what you need to do as a company to survive in the gas market in this environment." Despite low gas prices, he anticipates growing the company's production next year by 40% year-over-year, even as it reduces the number of rigs it is running.

With continued production, the U.S. can move beyond its past skepticism about gas supply, he said.

"The question you have to ask yourself is, do you think there is more upside in oil pricing or gas pricing? We think there is more upside in gas pricing, so we are going to continue to add through acquisitions. That's a tough game to play, because the view of the public investors is fairly negative on that."

—Brian K. Tully

Jefferies: E&P capex increases frowned on by market

Oil prices exceeding $100 notwithstanding, the market punished E&P companies for upward revisions in capital expenditures (capex) budgets during the first-quarter 2011 earnings season, according to a recent Jefferies & Co. Inc. analyst report. Venoco Inc., SM Energy Co. and Penn Virginia Corp. were all docked by the market for announced hikes in capex spending for the year.

There were more upward spending revisions than expected in the first quarter, according to Jefferies, and more may come. This could pose additional problems for companies should the price of oil slide further. The firm's analysts believe negative market sentiment towards capex increases is based on worries about increasing costs and declines in commodity price.

"The most likely candidates for further capex hikes are those that outspent their drilling budgets on a pro-rata basis in the first quarter of 2011. For instance, companies that spent 30% or more of their 2011 drilling budgets are at a greater risk of further capex hikes," said the firm.

Eight E&P companies, including Goodrich Petroleum Corp. and Venoco Inc.—both of which have already announced more spending and taken a hit from analysts—and Devon Energy Corp., spent more than 30% of their capex budgets in the first quarter. Only one, Devon, was given a "buy."

Of those companies, Jefferies analysts believe Devon has been unfairly treated for its aggressive first-quarter capex spend and is not likely to revise its 2011 capex budget.

"Although Devon has spent roughly 31% of its full-year budget in the first quarter, we do not think it is at high risk for a capex hike. Devon's budget is typically front-end loaded because of Canadian winter drilling."

The analysts do, however, expect Forest Oil Co. and Carrizo Oil & Gas Inc. to increase spending, both doing so because of Eagle Ford operations. Likewise, the analysts expect GMX Resources to increase spending due to less-than-expected decreases in Haynesville operating costs.

Petrohawk Energy Co. and Quicksilver Resources Inc. may be able to eschew capex increases, though the Jefferies analysts believe the former may be "significantly underfunding" capex in the second half of the year.

—Brian K. Tully

ECC 2011: Corporate confidence returns, but organic growth leads

While confidence grows and appetites for acquisitions are increasing in the oil and gas sector, still the majority of companies are looking to grow organically in the near term, according to a semi-annual study conducted by advisory firm Ernst & Young.

"It's a bit of a mixed message for M&A," according to Jon McCarter, a partner in transaction advisory services for Ernst & Young. "There's no doubt confidence is returning, with the board room priority being growth. But when comparing organic growth with acquisitions, it's steering more to the organic-growth side, and acquisitions are actually down a little."

McCarter presented the findings at Hart Energy's Energy Capital Conference in Houston.

Ernst & Young's Capital Confidence Barometer surveyed more than 1,000 executives globally from various industries, including some 60 companies in the oil and gas sector.

When queried, "How likely are you to execute on a transaction?" a third of the overall companies responded they are likely to acquire in the next six months, which E&Y interprets as reflecting a newfound confidence in the economy. In the longer term, nearly half the companies said they expect to be on the buy side. But the numbers have dropped off from previous years' surveys when two-thirds of respondents were looking to make acquisitions over a one- to two-year period.

"It's still a pretty significant percentage, but it has been ticking down over the last two six-month periods," McCarter said.

Half of all companies are focused on organic growth, a 100% increase over a year ago.

Looking at financing options for deals within the next year, some 60% of companies will deploy cash. Eighty percent of businesses in the survey have either completed or have no need to refinance.

"Companies have taken advantage of the open debt markets, more for refinancing than anything. We expect to continue to see refinancings," he said.

2010 was a strong year for oil and gas deal activity, McCarter reports, with $277 billion in total value, up 38% from 2009, even considering the pop from the $41-billion year-end merger agreement between ExxonMobil Corp. and XTO Energy Inc. The total number of deals was up 20% off the low.

Upstream deal value totaled $182 billion last year, up 23% year-over-year, with 733 total deals, up 28%. Midstream (84%), downstream (44%) and oilfield services (159%) all experienced significant increases in total deal values.

"We're in a more healthy oil and gas transaction market for the next 12 to 18 months," said McCarter. "It's going to remain fairly robust, with measured growth. It will depend on how much private capital comes back into the market."

—Steve Toon

McClendon: Industry's fast turn to oil will pivot returns, boost gas

Aubrey McClendon, the chairman and chief executive of Oklahoma City-based Chesapeake Energy Corp., the No. 2 producer of natural gas in the U.S., self poses the question: "Why are we drilling for oil?"

The answer: "You hope to do something with your life other than produce $3 natural gas."

The leader of the historic gas-centric producer summed up the sentiment of the 1,900 attendees of Hart Energy's Developing Unconventional Oil (DUO) conference in Denver. The company that produces 9% of the total U.S. gas supply is turning to oil. And fast.

He compared drilling for gas to a manufacturing line producing $4 per thousand cubic feet equivalent (Mcfe) widgets. By shifting to an oil and liquids focus over the coming years, the industry is retooling to produce widgets valued at $10 to $17 per Mcfe per widget on an equivalency basis.

"The industry's returns and profitability are about to pivot upward," he said. "Why would they go back, even if gas prices increase to $5 or $7 per Mcfe? This is the single biggest misunderstood aspect of the future bull case for natural gas."

Chesapeake is accelerating its liquids-focused capex to 75% by year-end 2012, up from 10% in 2008. In that time, McClendon anticipates company production from liquids will approach 20% to 25% of its total, with wet revenues potentially topping 40%.

"Our goal is to be a top-five oil producer in three years," he said. The company currently ranks 14th, with some 5 million acres with liquids and oil potential. "We are trying as quickly as possible to turn around 20 years of focusing exclusively on natural gas to now focusing more on oil."

In addition to other oil-focused assets it has added in the past year and a half, Chesapeake now has 1.2 million acres in the condensate and oil regions of the Utica shale, a growing 1.1-million-acre position in the Mississippi lime play in Oklahoma, and 200,000 acres "and building" in the Williston Basin, where it plans to begin production by year-end.

"The Bakken shale represents to the oil side of the business what the Barnett shale represents to the gas business."

Today's success in oil shale reminds McClendon of an era he thought long past—wells producing in excess of 1,000 barrels a day onshore U.S. "Almost everywhere that we're drilling, we've got thousand-barrel-a-day wells."

By year-end 2016, the company models production of 250,000 barrels of liquids per day, up from the current 67,000 barrels, to be about 35% of its total volume.

—Steve Toon

DUO 2011: Is the Bakken the one and only?

As the industry searches for the next big U.S. resource play, "There's just one Bakken," says Continental Resources Inc. chairman and chief executive Harold Hamm. Speaking at Hart Energy's second annual DUO-Developing Unconventional Oil Conference & Exhibition, in Denver, the executive emphasized the Bakken oil shale play's transition from unconventional to conventional as horizontal drilling and fracture stimulation become the norm.

More than 90% of the wells now drilled in the play are horizontal, and operators continue to take multi-stage fracturing technology to higher levels. Hamm lauded the industry's success in unlocking vast amounts of domestic oil and gas reserves in the process. He said that the U.S. portion of worldwide technically recoverable reserves now approaches 10%.

"There has been a technology revolution that has enabled us to unlock tight oil and gas reserves," he said.

The USGS has recently agreed to reassess the Bakken's potential, updating its 2008 number of 4.3 billion barrels of technically recoverable reserves. The study should take about two years. Last year Continental conducted its own study and Hamm said he estimates a large increase in the figure—to 24 billion barrels—which he thinks the USGS will agree with. "We'll be waiting," he said.

There are currently 4,000 horizontal completions in the play, with the industry adding another 2,000 wells on average per year.

"People often talk about the fact that there is an estimated 100 years or more of natural gas reserves now in the U.S., but now we're beginning to see big numbers for oil reserves as well," Hamm said. "It's taken some time, but people are targeting liquids-rich formations—and that was to be expected—we have $100 oil, not gas."

Horizontal land rigs now outnumber vertical rigs at work, at 1,093 horizontal versus 662 vertical; likewise, there are 901 rigs targeting crude, and 864 targeting gas.

Today, Continental, which drilled the first commercially successful horizontal and fracture stimulated Bakken well in 2004, in Divide County, is the top producer in the Williston Basin. Its production expanded by 34% in first-quarter 2011 compared with the year-ago period. It's accelerating production growth by 35% to 37% annually and has a plan in place to triple production and proved reserves from 2009 levels through 2014.

"We're 18 months into that program now, and we're right on track," said Hamm. The company operates 88% of its PV-10.

In late 2010, while assessing development challenges and infrastructure investment needs, Hamm said the company arrived at its figure of 24 billion barrels of oil equivalent recoverable Bakken reserves, over 14,700 square miles of continuous oil accumulation for the play. The figure was based on 320-acre spacing and 500,000 barrels of oil equivalent estimated ultimate recovery per well.

"There are an estimated 48,000 total wells to be drilled, with 93% remaining. We're just at the beginning, " he said. Continental raised its first-quarter 2010 Bakken production by 67% year-over-year, and has 308 producing wells with 24 rigs running over its 900,000-net-acre position. It plans 151 net wells for 2011.

—Susan Klann

Halliburton's Probert: 'Green' fracing needed to meet demand

Due to rising energy demand and declining reserves worldwide, the oil and gas industry will be asked to produce more. At the same time, however, it must proactively gain the public's confidence by using technology that addresses environmental concerns.

Along those lines, serious work is under way in developing environmentally friendly fracturing techniques. This is according to Tim Probert, Halliburton's president of global business lines and chief health, safety and environment officer, in a keynote speech presenting a macro energy picture to attendees at the recent KPMG energy conference held in Houston.

Based on International Energy Agency numbers, Probert suggested that total Btu needs worldwide would increase substantially by 2035, and that liquids and natural gas would be asked to provide an additional 10 quadrillion Btu. Compounding the problem, the oil and gas industry has not been spending enough, due to the nature of cycles it has weathered in the past few decades, Probert said.

"The reality is that we have probably been significantly under-investing in the base requirements to grow production to the level that we need to, if you buy into the fact that we are going to see significant growth by the 2030 time frame," he said.

Fourth-quarter 2010 saw world oil demand grow by 3.9%, and the year's average oil demand growth was 3.4%.

"When we are talking about 90 million barrels a day, 3% growth will get into the realm of large numbers. We are looking to find somewhere between 2- and 3 million barrels a day," he said.

That growth in production is not likely to come from OPEC, he noted. It peaked in 2009 at 6 million barrels per day and is on its way down rapidly. It is likely somewhere around half that number today, due to the uprising in Libya.

Probert believes unconventional shale opportunities could offset some of that demand. Shale gas is already 23% of U.S. output, and companies have been investing through the down cycle, despite the soft price.

China may have the most shale gas in place globally, with more than 1,200 trillion cubic feet (Tcf). Europe has an estimated 624 Tcf of shale gas, and most countries rely heavily on Gazprom for their current natural gas needs. Recalling the incident in 2009 when Europe's gas supply was significantly reduced during a contract dispute, Probert suggested these countries may be incentivized to develop domestic resources quickly. Others, like France, have banned fracing altogether.

Probert gave what he called a "forward-looking view" of hydraulic fracturing. He discussed a suite of four technologies that address key concerns involving water: water recycling, food-grade frac fluids made of food-industry ingredients; eliminating biocides; and BTX- (benzene, toluene, xylene) free blending. He says these technologies are being used currently in the Haynesville and should help development of shale resources here and in Europe, where there has been some public opposition.

"We have a lot to do as an industry to gain the confidence, not of the regulators, but of the public. It's things like this that we can do which, if we communicate well, can reduce the anxiety around a technology that provides tremendous potential for us to have a long and positive view of a relatively low-cost energy source."

—Brian K. Tully

Hedge fund managers pick their favorite oily stocks

Hedge fund managers are envied on Wall Street for their historically high performance, and their seemingly uncanny ability to pick good stocks in any industry. So that begs the question: What oil and gas companies do hedge fund managers like these days?

Investors poured big money into hedge funds through the first quarter of 2011. With the sell-off in June in equities, those inflows may not continue. For now, though, the official tally for hedge fund inflows is a record-breaking $2.02 trillion, according to Hedge Fund Research.

Big institutional investors think highly of hedge fund managers; many believe that hedge fund pros will go the extra mile in digging up profitable companies, and are more likely to pour extra research dollars into the chase than mutual fund managers. Hedge fund managers had better go that extra mile, because the fees they charge are high—even by Wall Street standards. Management fees clock in at about 2% (compared with 1.3% with the average equity mutual fund), with "incentive fees" of 20% of profits, with some hedge fund managers commanding 50% incentive fees.

With $2 trillion on the line, not to mention all those fees, what oil and gas companies do hedge fund managers favor these days? Here's an overview of the "top five."

ExxonMobil (XOM) Paul Tudor Jones has amped up its stake in Exxon by 50,000 shares, to 53,100 shares, an increase of 716% (Jones charges 4% for assets under management and 23% of all fund profits). Oil and gas comprised 3.1% of the portfolio through the first quarter of 2011.

With volatility the watchword for oil stocks—and ExxonMobil the poster child for volatility—some money managers are paring back on big oil companies and are turning to smaller oil and gas companies, often through exchange-traded funds that specialize in targeting smaller producers, like Jefferies TR/J CRB Wildcatters Exploration & Production Equity ETF (WCAT).

But not Jones. While he has sliced his oil and gas exposure back from 5.2% in the fourth quarter of 2010 to the 3.1% figure mentioned above for first-quarter 2011, he is going all in on Exxon—an oil company that maybe he figures is "too big to fail."

Plains Exploration (PXP) SAC Capital Advisors founder and manager Steven A. Cohen has beefed up the natural gas company's presence via his $12-billion fund. Cohen, speaking at the SALT Conference last month, noted that the recent sell-off in oil and gas represents a good entry point for buyers.

PXP is a good example of that investment strategy. Cohen originally bought PXP in 2009, and added 800,000 shares in the first quarter of 2010. When the BP Gulf oil spill spooked the commodities market in the summer of 2010, Cohen didn't blink; he bought 1.7 million more shares in the aftermath, and at cheap prices. Since then, he has bought 7.5 million shares, as the company's stock prices doubled, and then cut his PXP holdings by 45% late in the first quarter, according to a regulatory filing. Analysts at Halliburton say the Gulf of Mexico drilling situation is improving, a year ahead of schedule.

British Petroleum (BP) The financial web site "Seeking Alpha" reports that 16 hedge fund firms included BP in their "top 10" holdings. Big stockholders include Mason Capital and Luxor Capital. BP successfully, albeit reluctantly, raised $30 billion through divestments this year. The cash is expected to help cover the costs related to the Gulf of Mexico oil spill in 2010, which the company estimates to be approximately $40 million. How BP is recovering from that massive spill is a big reason why hedge fund managers are bullish on the third-largest oil and gas producer in the world.

Williams Cos. (WMB) SAC's Cohen is also a big holder of Williams' stock, and he's not alone. Hedge fund firms Kensico and Karsch Capital also hold ample positions in the natural gas company. Anthony Scaramucci, managing partner at SkyBridge Capital, has said that the company stock should be trading at between $37 and $45 (it's trading at around $30 lately). Barry Rosenstein's hedge fund, JANA Partners, also recently added Williams to its portfolio, in late 2010 (it had owned the stock previously). JANA says in a recent research report, "We expect that WMB will find a way to separate their large exploration and production portfolio from their pipeline assets."

Chesapeake Energy (CHK) According to Seeking Alpha, Chesapeake is a favorite of 12 hedge fund managers—hedge funds own 5% of the company's stock. The word among Wall Street insiders is that T. Boone Pickens' apparently successful lobbying efforts on behalf of natural gas in Washington are paying off big. The Congressional bill he's unofficially sponsoring—HR 1830, the New Alternative Transportation To Give Americans Solutions (NAT GAS) Act of 2011—is expected to pass, and will speed up domestic natural gas development. Hedge fund managers are lining up to plant their stake in Chesapeake, which should be poised to take off once HR 1830 passes.

—Brian O'Connell