In The Pipeline

DUO 2011: Chesapeake's McClendon

bullish on gas-to-liquids technology

Gas-to-liquid (GTL) technology, which can be used to convert natural gas to transportation fuel, makes Chesapeake Energy Corp.’s chairman and chief executive, Aubrey McClendon, “optimistic about the U.S. natural gas industry,” he says. In fact, McClendon is “readying new investments” in the technology, he divulged to attendees at Hart Energy’s recent Developing Unconventional Oil (DUO) Conference. Currently, Chesapeake produces about 9% of all gas in the U.S.

Yet, GTL is not the only reason for a bullish attitude toward gas, he said. "We hear a lot of the same things you do, about being unrelentingly bearish about future natural gas prices. So we thought we would put together a few points here for people to think about, in terms of why you shouldn’t give up on natural gas."

For example, natural gas demand should rise from U.S. electric utility plants and heavy-end chemical manufacturing is increasing, he said. Also, his long-term optimism is underpinned by the likelihood of exporting liquefied natural gas.

“Probably the thing that I am most excited about are the opportunities that exist on the transportation side—that is, to convert the transportation network away from imported oil toward domestic natural gas in the form of compressed natural gas(CNG) or toward domestic gas in the form of GTL,” he said.

During the second half of 2011, Chesapeake will announce a number of investment initiatives or corporate acquisitions of companies with technological breakthroughs “that need to be tested on gas-to-liquids,” McClendon promised.

“Right now, the process is reasonably inefficient, because 40% of the natural gas is consumed in the process of making gas-to-liquids. But if we improve that process, then we will have a situation where, for the first time, we will be able to take American natural gas at room temperature, tank-ready liquid that you can burn in your car or truck, and also move through American pipelines," McClendon explained.

"We will stop the foolishness of burning food into fuel, which I think has serious moral issues in addition to financial and economic issues. Of course I am talking about ethanol," he said.

Economides: Natural gas to lead

new energy economy

A new, realistic blueprint for energy security must come to bear on U.S. energy policy–and soon–if the country is to begin weaning itself off of its dependency on foreign oil in the wake of sociopolitical instability in the Arab world.

Dismissing corn-based ethanol and carbon sequestration as "gimmicks" and contending that solar and wind power would be "thermodynamically impossible" to adopt, Dr. Michael J. Economides told attendees at the Offshore Technology Conference that he believes the predominant fuel of a "new energy economy" will be likely be natural gas, given its abundance and economic and environmental benefits.

In fact, due to large-scale LNG developments in Qatar, Egypt and Russia, Economides anticipates some 10 billion cubic feet (Bcf) of excess supply to be available in the coming years, with "a major Btu disparity" lasting decades. This, he added, will be due to technology challenges, and not just resource availability.

Also, although excess supply will have a considerable impact on near-term gas prices in the U.S. and Europe, particularly as more shale gas floods the market, prices will equalize in the long term, he said. Specifically, Economides expects to see $5 per thousand cubic feet a price of gas during the next few years, followed by a price hike to $8.

Meanwhile, oil futures remain in a constant state of flux. Recently, the U.S. and European benchmarks topped $110 per barrel, partially due to heightened geopolitical risk.

"The price of oil should really be around $80 per barrel," he said, noting that a series of headlining crises in early 2011 propelled oil to prices last seen in 2008.

Ever the realist, Economides pointed out that America has a long way to go before it is able to transform its energy practices. Based on his estimations, traditional hydrocarbons (coal, oil and natural gas) supplied some 87% of U.S. energy demand 40 years ago, and it is still supplying at that level today. Given that statistic, solar and wind resources (which account for roughly 1% of energy supply) simply "cannot cut the mustard" against combustible hydrocarbons and nuclear in the implementation of a new energy economy, Economides said.

DUG 2011: Midstream companies

target shale core areas

Booming gas production coming from shale plays is creating big opportunities for midstream companies, according to several featured speakers at Hart Energy’s Developing Unconventional Gas 2011 Conference in Fort Worth, Texas. By their data, shale plays will be producing 50% of all U.S. gas supply in 2020.

“The midstream industry is meeting the challenge to move that gas,” said Don Raikes, vice president, transmission marketing and customer services for Dominion Transmission Inc., a unit of Dominion.

Robert G. Phillips, chairman, president and chief executive of Crestwood Midstream Partners LP, agreed, saying, “We think it takes several years to complete a full-cycle capital investment program in a shale play. We need to move right along with the producers from a play’s inception to its fast-growth phase to mature development.”

“Today we are living in one of the most exciting times in the history of natural gas,” Raikes told the estimated 2,500 attendees. “A couple of weeks ago, our current president actually mentioned natural gas nine times in his speech on energy at Georgetown University. The time for natural gas is now, but one thing we can’t be is too comfortable.”

The nature of U.S. natural gas supply has changed, he said, and the midstream is adapting to those changes. At one time in the not-too-distant past, people thought the U.S. would not have enough gas supply and some 40 new LNG plants were proposed to import liquefied natural gas. Yet, only four were built. Then, increased gas supply from the Rocky Mountain region was thought to be the answer.

“Now, the Marcellus shale in our own backyard is the answer. Three years ago, we asked, ‘Is it real?’ A year ago we asked, ‘How big is it?’ Now we are asking, ‘What are we going to do with all this natural gas?” Some experts think that by 2020, the Marcellus will be producing 10 Bcf per day.

Raikes said he thinks the Marcellus is the “kid brother” who will grow up to be the biggest factor in the shale family. And, a new baby has joined the family, the Utica shale.

Meanwhile, new infrastructure is being developed now, despite lower demand for natural gas at the moment, he said. Each midstream player, such as Crestwood Midstream, is developing its strategy to match individual shale developments.

“We don’t want to get caught up in just dry-gas plays or wet-gas plays. We like diversity,” Crestwood’s Phillips said. The company has assets in the Fayetteville shale core area. Four days after it acquired assets there, BHP Billiton announced it will spend $800 million to $1 billion annually in the play. “Even though that is mostly a dry-gas play, it is seeing accelerated production growth,” meaning plenty of midstream potential exists, Phillips said.

The company is also active in the Barnett, Granite Wash and Avalon shale plays, but the Barnett remains the young company’s core area.

Phillips said the Barnett is in the mid- to late-stage phase of development where the infrastructure is largely built out; the Fayetteville is in mid-stage; the Granite Wash is in early- to mid-stage; and the Avalon is in the early stage.

In the Barnett, operators are drilling fewer but better wells as they optimize the mature play that is yielding about 5.1 Bcf per day of gas. The infrastructure is also mature, and in some cases, even underutilized, he said, which can lead to consolidation.

In the Fayetteville, which produces about 3.1 Bcf per day, Crestwood is the only independent gas processor there. In the Granite Wash, which has several stacked pay zones, operators have only begun to scratch the surface, he said.

“We’ll see a tremendous amount of capital invested in this area to handle the natural gas liquids (NGLs) and a lot of the old legacy assets have to be re-plumbed to handle this new, high-pressured gas.”

PricewaterhouseCooper: Oil and

gas deals continue “at a brisk pace”

The “total value” of U.S. oil and gas mergers and acquisitions (M&A) during the first-quarter of 2011, increased 69 % over the same period in 2010, according to a recent PricewaterhouseCoopers (PwC) study.

Despite fluctuating commodity prices and lingering concerns surrounding global macro-economic events, industry dealmakers announced a number of large deals that contributed to the 76 % increase in “overall average deal” value during the first-quarter of 2011, the study noted.

Also, for the three-month period ending March 31, 2011, there were 47 deals with values greater than $50 million, accounting for $51.5 billion in deal value, which accounts for a significant increase from $30.4 billion during the same period last year. First-quarter average deal size also increased substantially to $1.1 billion from $620.9 million in the same period in 2010, driven by 23 large deals with a value more than $250 million.

“While it’s been a choppy and volatile first quarter for commodity prices, the number of deals in the oil and gas sector continued at a brisk pace. There was a significant jump in first-quarter total deal value and average deal size, compared to a year ago with large and ‘mega’ deals back in play, which we attribute to the dominance of corporate transactions in the quarter,” said Rick Roberge, partner in PwC’s energy practice.

According to the study, 16 corporate transactions with values greater than $50 million, generated 68%, or $35.2 billion, of the total first-quarter deal value. About 30 asset deals with values greater than $50 million contributed about $16.3 billion. When compared with the first quarter of 2010, corporate-deal value more than doubled from $15.3 billion, while volume jumped 100%, up from eight corporate deals.

In fact, deal value from asset transactions in first-quarter 2011 increased 7% from $15.1 billion in first-quarter 2010, while the number of deals in this year’s first quarter declined from 41 deals.

Also, “combined with recent market support for $100 oil levels, helping buyers and sellers to agree on terms for potential asset transactions, we believe that the remainder of 2011 will be very robust for deal activity,” the company reported.

For deals valued at more than $50 million, upstream deals made up 73% of activity in the first quarter of 2011 with 27 transactions, accounting for $25.3 billion, or 50% of total first quarter deal value.

Oilfield services contributed almost 25% in value, with seven deals totaling $12.8 billion. Six downstream and six midstream deals contributed an impressive $4.6 billion and $4 billion in value, respectively.

“Deals in the upstream sector dominated first-quarter activity as more companies look to adjust their existing portfolios to align with current market conditions. Companies are working to close on these deals to take advantage of higher oil prices while managing the longer-term prospects of unconventionals,” noted Roberge.

Eight deals valued at greater than $50 million involved shale-gas developments and totaled $9.7 billion, including two deals involving the Marcellus shale totaling $325 million.

“Shale-gas plays remain very attractive to global oil and gas companies because of the abundant supply in the U.S.,” reported Steve Haffner, a Pittsburgh-based partner with PwC’s energy practice.

“The continued M&A activity in the Marcellus region has been mainly coming from the large, well-financed players, who have a longer-term vision, and can ride out the low natural gas prices we're seeing now.

“With the tremendous amount of shale-related deal activity over the past few years, companies are also focused on building the necessary infrastructure to maximize the full potential of unconventional assets,” said Haffner.

For deals valued at more than $50 million, foreign buyers announced seven deals in the first quarter of 2011, which contributed $17.6 billion or 34% of total deal value, versus 12 deals valued at $17.2 billion in the same period last year, the study noted.

Additionally, there were eight private equity-backed transactions, representing $4.8 billion, or 9% of total deal value, compared to just one private equity deal during the same period last year.

“Private equity firms continue to make a push into the energy sector, although they’re facing stiff competition from corporates with strong balance sheets and a desire to make big investments like those we’ve seen in the first quarter,” said Roberge.

Will MLP tax

treatments be nullified?

Are master limited partnerships (MLPs) and royalty and unit trusts in the U.S. in danger of losing the very tax treatments that have attracted so much productive capital from so many individual retail investors in the energy patch?

The National Association of Publicly Traded Partnerships (NAPTP) is monitoring moves by the Obama administration that may force these businesses to restructure themselves and begin paying their taxes as corporations, according to a May 2 report by The Hill news source.

According to the report, one NAPTP executive recently signaled that had "information indicating that the administration wanted large so-called pass-through entities–businesses that pay taxes through the individual code–to be subject to corporate taxation.”

The Hill was paraphrasing the email it obtained that was written by the NAPTP's executive director, Mary Lyman, which reportedly read, "Treasury Department staff are working on a tax reform proposal that reportedly would include corporation taxation of any pass-through entity with gross receipts of $50 million or more."

The Hill noted that recent comments by White House spokespersons and even Treasury Secretary Timothy Geithner indicated the administration was not only hammering out a corporate tax reform plan but also that Treasury officials "have discussed the issue with stakeholders."

The report noted that Secretary Geithner and the Finance Committee chairman for the U.S. Senate, Max Baucus from Montana, have expressed, "skepticism about allowing some businesses to pay taxes as individuals."

"I think, fundamentally, Congress has to revisit this basic question about whether it makes sense for us as a country to allow certain businesses to choose whether they're treated as corporations for tax purposes or not," Geithner reportedly said to the Senate Finance Committee in February, 2011.

Under Section 7704 of the U.S. tax code, entities that are structured as MLPs do not pay corporate taxes themselves, but rather pass tax liability through to the partnership owners, provided that at least 90% of gross income meets the definition of "qualified income."

That section defines qualifying income as "income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy and timber)."

Investors provide their capital to MLPs knowing that the investment returns may be greater because aggregate tax rates and payments for a given partnership's owners could be less than the corporate tax rate or payment that would have occurred if such an operation had been treated and taxed as a corporation.

But that characteristic is also the attraction to legislators looking for new tax revenues.

Certainly, the potential restructuring of tax treatment for publicly traded partnerships, amid the already rancorous debate about oil and gas tax credits, will become a hot topic of interest this year.

DUO 2011: New Bakken

midstream projects on the way

Bakken oil and gas producers are struggling with limited infrastructure for production coming out of the Bakken play in North Dakota. However, help is on the way, according to a pair of midstream operators speaking at Hart Energy’s DUO Conference.

“We are investing in infrastructure to get production to market,” proclaimed Perry Schuldhaus, vice president of business development for Enbridge Pipelines Inc. “ We will be providing producers with access to the right markets and developing projects to access more markets and greater optionality.”

To that end, Enbridge plans several North Dakota pipeline capacity projects to grow regional take-away. The midstream operator’s Phase 6 project alone will bring some 51,000 barrels (bbl.) per day of much-needed pipeline capacity to the region. Building on that is its Portal Reversal project with about 25,000 bbl. per day of additional capacity.

Other projects include Enbridge’s Alexander-to-Beaver-Lodge project, its Berthold Truck Expansion and various system optimizations. Those current projects will bring some 145,000 bbl. per day of transportation and are expected to be in service by January, 2013.

Also, Enbridge plans to undertake a Beaver Lodge Loop Project, the Portal Reversal Expansion Project, the Bakken Expansion 16” Line, new capacity at its Cromer Terminal facilities and some “South of the River” initiatives.

To bring such projects to fruition, Enbridge is making good progress through its regulatory hurdles, said Schuldhaus. To date, the company has filed a Petition for Declaratory Order on Commercial Structure, which was approved by Federal Energy Regulatory Commission on November, 2010. It has affirmed with U.S. Department of State that the reversal of its Portal Link cross-border system did not require a new Presidential border-crossing permit. The section had originally transported Canadian production south.

Also, Enbridge filed a North Dakota Public Service Commission application last November, and expects a decision on that request “any day.” It filed a Canadian National Energy Board application in January, 2011, and has a hearing set on October 4.

Yet, such big projects are not the only constraints that Bakken producers face, according to Tad True, vice president for True Cos., addressing the DUO attendees. “Logistical constraints for Bakken production include both basin constraints, meaning getting barrels out of the Williston Basin, and lease constraints, meaning getting barrels off the lease.”

The midstream company, which has been in operation since1948, plans several new activities in the region, including its Four Bears and Bakken 300 projects.

“With Poplar, Belle Fourche and Four Bears, most producing wells in western North Dakota and eastern Montana will be no farther than 30 miles from pipeline access,” he said, and noted that some production moved by trucks is undergoing major traffic constraints. Trucking and railways are not as economical as pipelines for large-scale transportation.

Also, pipeline capacity constraints, along with alternative transportation methods, have an opportunity cost for operators when they cannot take advantage of today’s current high oil prices, because prices could fall again.

Yet, attempting to evaluate oil prices is a complex process, according to Conrad Barnes, manager of the Energy Pricing Center for Hart Energy, also speaking at the conference. Both quantitative and qualitative aspects of oil prices must be taken into account.

Quantitative parameters include purchasing power stability, the absolute and relative demand growth between the Organization of Economic Cooperation and Development (OECD) and non-OECD, the real-world scenario of the Organization for of the Petroleum Exporting Countries’ ability to replace supply disruptions, overall financial markets sentiments, foreign exchange rates and short-term demand and supply balances, he said. Qualitative parameters include geopolitical risk and value judgments.

Conrad noted that, overall, oil prices are higher than in previous years, despite increasing domestic supplies this year, which is reversing the falling U.S.-production trend of the years 1986 through 2008.