Whiting’s Volker, Pioneer’s Sheffield Solving For Markets For New Oil Supply

April 14th, 2014 Nissa Darbonne | Comments Off

A Bakken and heavy Canadian blend may push out 2 million barrels of daily medium-gravity imports.

At the turn of the century, getting new, onshore-U.S., oil and gas production to market went without concern. Spare capacity in existing infrastructure across the Lower 48 was increasingly available as net, new production was flat to declining.

Soon, getting new natural gas supply to market became an issue for producers beginning with thousands of wells from the Barnett shale. Additional, new gas from the Fayetteville, Marcellus, Haynesville and Eagle Ford resulted in needing to create a supplemental market for it—in transportation and via export.

U.S. oil producers are grappling with these issues as well.

In lieu of exporting it, which is banned but for a few exceptions, Jim Volker believes U.S. refining capacity can be created for an additional 2 million barrels a day of light, sweet from the Williston Basin.

“Based upon the thinking of our friends at Enbridge (Inc.) and others who are planning (to combine) Bakken with (heavy) Western Canadian Select, we think we can displace another 2 million (daily) barrels of medium-grade, Gulf Coast imports,” Volker, chairman and chief executive officer of Whiting Petroleum Corp., said in a keynote address to the IPAA’s OGIS New York attendees.

The API gravity of Bakken crude averages about 40 degrees; Western Canadian Select, approximately 20 degrees. Medium-gravity crude is between 28 and 34 degrees.

In addition, Enbridge’s new Sandpiper pipeline will take 225,000 Bakken barrels a day to East Coast refineries, which are weighted to light, sweet while Gulf Coast refiners are weighted to heavy crude. “We will begin to see Bakken netbacks of more than $90 a barrel…,” Volker said. “(Eastern refiners are) all looking for more light, sweet Bakken crude—from Ohio to Montreal.”

Exporting U.S. oil to destinations outside North America should be an option as well, said Scott Sheffield, chairman and chief executive of Pioneer Natural Resources Co., which is bringing online new, light, sweet West Texas Intermediate from the Permian Basin’s Wolfcamp play.

“(The U.S. is) exporting every hydrocarbon except crude oil, including coal—and LNG (too), beginning late 2015, early 2016,” he noted in a keynote address. Refined-product exports were 4.3 million barrels a day in 2013. Sheffield supports exporting at least a half-million barrels of U.S. light, sweet a day.

Why export an indigenous energy asset? Sheffield said, “We’re trying to be fair on free market. (The U.S. isn’t) banning products (export). I have no idea why, in 1975, they banned (exporting) oil. You would have thought, from a security standpoint, they should have banned products; products are what the military uses.

“…We’ve told the administration and Congress that, if we get in a military issue in the future, ‘all you have to do is shut it down for a period of time.’

“But you don’t want to shut the growth (in U.S. oil production),” which would result in laying down rigs and diminished supply, “and, all of a sudden, start sending troops to the Middle East again and have a huge trade deficit with an oil imbalance. It’s better to allow some exports.”

After all, “we’ve approved 8.5 (billion cubic feet of gas a day) of LNG (export) projects.”

He concluded, “We have to educate…the next president.”

Volker said, “While North America has been doing well in finding new supplies, outside North America, other producers have fallen short. Africa, North Africa, Brazil, the U.K. North Sea, Mexico, Venezuela. Production has actually declined by 2.7 million (of daily) barrels in the last five years from those areas.”

Meanwhile, U.S. oil producers have brought an additional 3 million daily barrels online in the past three years. About a third of that is from North Dakota, which is making nearly 1 million barrels a day now, just as Volker forecasted when presenting in OGIS New York in April 2011.

Daily imports have decreased by more than 2 million barrels, “such that the U.S. trade balance from 2005 to 2013 has dropped by $233 billion,” he said.

-Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.comUGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Heard At OGIS NY: The Tuscaloosa Code Has Been Cracked

April 9th, 2014 Nissa Darbonne | Comments Off

The price to join in the play is only going to go up.

“If someone is waiting for it to be a ‘sure thing,’ then it’s not going to be $5,000 an acre anymore.”

Rob Turnham told analysts, fund managers and media this in a break-out room Q&A at the IPAA’s OGIS New York investment symposium this week. Turnham, president and chief operating officer of Goodrich Petroleum Corp., was referring to an interest in the small-cap’s promising Tuscaloosa Marine Shale play in eastern Louisiana and western Mississippi.

Goodrich has a one-third partner, China’s Sinopec, in some of its acreage. It has suggested that it might take a one-third-interest partner in the rest of its position. Turnham’s comment meant that, each time it, Encana Corp. and Halcon Resources Corp. drill a successful TMS well, the price for others of buying into it will go up.

“$15,000, $20,000…,” Turnham said. “Feel free to do the math….”

Halcon is moving a rig and crew from its Eagle Ford play in southeastern Texas to the TMS to spud the first of nine or 10 wells this year for it. Floyd Wilson, chairman and chief executive, told OGIS attendees that findings suggest 600,000- to 700,000-barrel wells can be made in the 90%-plus-oil-rich rock. “I think (the code’s) already been cracked (by Goodrich and Encana),” Wilson said, “but you need another 50 wells to prove it. And I think it’s well on its way.”

In a break-out session, he said Halcon isn’t actively seeking a partner in its position in the TMS. Financially, “a JV is not necessary but we would look at it to accelerate drilling,” he said.

Also, he said, “there’s plenty of interest (that has been expressed to Halcon), by the way.”

Drill days are as many as 30 to reach the deep TMS and make a 4,000- to 8,000-foot lateral. Wilson was asked about the odds of getting those down to 12. He said that using a drilling crew that has been working the Eagle Ford for it in Texas will help pare the drill time. Overall, the challenge—as measured in feet—is similar to that of the Eagle Ford and Bakken, which Halcon is drilling in about 12 days.

While presiding over Petrohawk Energy Corp., Wilson led the horizontal discovery of the Eagle Ford in 2008. The play was made in 10 months from conception to commercial well with very little data, he noted. Meanwhile, in the TMS and because of Goodrich’s and Encana’s work already, there is “infinitely more data than when we went into the Eagle Ford,” thus a source of his confidence in that the play has ongoing potential.

-Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas Investor, OilandGasInvestor.com, Oil and Gas Investor This Week, A&D Watch, A-Dcenter.comUGcenter.com. Contact Nissa at ndarbonne@hartenergy.com.

Scott Sheffield: Refiners’ Profit Margin Is Impediment To Lifting U.S. Oil-Export Ban

April 4th, 2014 Nissa Darbonne | Comments Off

“They should make some money but not $30 a barrel, in my opinion.”

The U.S. isn’t just on the verge of a “stranded oil” situation,  it’s already in the midst of it, says Scott Sheffield, chairman and chief executive officer of Permian-Basin producer Pioneer Natural Resources Co. “If not for some dynamics in the Midwest refining market, yes,” he says.

Sheffield recently addressed members of the energy M&A group ADAM-Houston, which named him its “Dealmaker of the Year” for Pioneer’s 2013, $1.7-billion, Permian joint venture with Sinochem Group and its roll-up of Pioneer Southwest Energy Partners LP. The company incurred a one-year stock-price gain of 66% in the midst of WTI-price growth of just 5% and while issuing 10.4 million additional shares in a $1.3-billion raise.

A political impediment to exporting U.S.-produced oil beyond a few exceptions, such as sending it to Canada, is refiners who are enjoying margins of as much as $30 a barrel, Sheffield says. Acknowledging that U.S. refiners suffered from marginal profit for decades until the past few years, “they should make some money but not $30 a barrel, in my opinion,” he added.

While the Nymex price for WTI, for example, is up to $100 a barrel and breakeven in many plays is at least $60 oil, what producers net is affected by transportation-to-market costs and by the onshore-versus-Gulf Coast price differential, which was $18 in mid-March for Permian Basin crude, for example.

So, while the Nymex price for WTI may be $100, a Permian producer may net between $70 and $80; with a cost of $60 a barrel, its profit may be $20 a barrel or less.

“Once all North American, light, sweet imports are displaced, the Gulf Coast will become saturated with domestic production,” he says. As a result, producers will experience a more than $30-a-barrel differential to Brent, rigs will be let go, “starting with the marginal plays and eventually every play will shut down,” he says.

Meanwhile, he adds, lifting the ban would create up to 1.7 million new jobs by 2020, as per a McKinsey & Co. study; reduce U.S. gasoline prices, as per a Resources for the Future analysis; and improve the U.S. trade balance as per a Citigroup forecast that a $354-billion U.S. trade deficit in 2010 could become a $5-billion surplus in 2020.

Securities analyst David Tameron writes that producers who presented in a mid-March, Wells Fargo Securities LLC-hosted symposium “agree that an oversupply of light, sweet crude and condensate is forthcoming and represents a mismatch with the Gulf Coast refinery feed-slate, which is more configured for medium to heavy barrels.

“The industry is attempting to deal with this dislocation in a number of ways, including the construction of condensate splitters, some minor investments by refiners (such as Valero Energy Corp.) to process more light, sweet crude and increased blending with heavy crudes.”

They weren’t expecting the oil-export ban to be lifted anytime soon, however, he adds, “given the political dynamics—no politician wants to take actions that could result in higher motor gasoline prices—and the near-term election cycle.”

He concludes, “Any potential change in policy would likely be on a case-by-case basis and in response to severe market dislocations that cause public sentiment to shift.”

FBR Capital Markets & Co. securities analyst Benjamin Salisbury notes in a report this week that producers are asking the Department of Commerce to allow export of natural condensate, which is a gas while still in the ground and arrives at the wellhead as a liquid.

Sheffield says U.S. wells are currently producing some 800,000 barrels of condensate a day, particularly from the liquids-rich Eagle Ford play. The figure represents some 10% of total, daily, U.S. oil production. If producers are able to export the condensate, he says, daily, U.S., refining capacity for new, light, sweet production would grow by some 800,000 barrels.

Salisbury writes, “It is possible to seek (a condensate exception) and it appears that producers have a relatively strong technical argument. Moreover, lease condensate is relatively obscure and does not carry the political sensitivity that crude-oil exports would.”

An option, however, is to send it to Canada, he adds. “As we understand it, the law allowing crude exports to Canada could be similarly applied to exports to Mexico with a presidential determination of national interest.

Oil-price speculators are discounting forward-month contracts for WTI, primarily due to concern about future markets for it. While WTI was trading at $101 a barrel today, the May 2015 contract was $91; May 2016, $85; and May 2017, $83.

Judith Dwarkin, director and chief energy economist for research group ITG Investment Research Inc., says, “We believe fears are overblown that U.S. crude prices are about to collapse because domestic, light-oil, production growth will soon hit a ‘wall’ with respect to crude-import-displacement opportunities.”

The firm analyzed the price discount required on light, sweet domestic crude—relative to other crude types—to displace sour and heavy grades in cracking and coking-type refinery configurations in the U.S. Gulf Coast market, she says. Taking January 2014 price spreads for LLS/Mars ($4/barrel) and LLS/Maya ($14) and Gulf Coast product prices as the starting point, the firm found that “light, sweet crude largely displaces sour in the example USGC cracking refinery at a $1/barrel narrowing in the light sweet/sour price differential.” She adds that, “for the coking refinery, light, sweet largely displaces heavy at a $3/barrel narrowing in the light sweet/heavy spread.

“A bigger price discount is required for the coking compared to the cracking configuration because the coker sees a smaller uplift in product value by shifting to a lighter crude slate.”

As for geography-based—rather than oil-type-based—differentials, she notes, “they’ve ticked up this year in part because WTI Cushing prices are being supported by a very robust stock draw from this hub, due to the start up of (the Keystone) XL (Gulf Coast leg), and because production growth in the Permian is out-pacing take-away capacity again.

“The latter problem should diminish as additional pipeline projects come to fruition in the basin.”

-–Nissa Darbonne, Author, The American Shales; 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.

Still-Tumbling Gas In Storage Causing Doubt As To If Full Reload Is Possible

March 13th, 2014 Nissa Darbonne | Comments Off

Meanwhile, gas futures refuse to exceed $5.

U.S. working gas in storage has declined to 1.001 trillion cubic feet as of March 7—the lowest level since just under 1 Tcf in May 2003—according to the Energy Information Administration’s weekly update. Yet gas futures will continue to refuse to budge, the EIA expects, despite that winter continues across the U.S., while flex-fuel power-generation plants can merely switch to coal should natural gas prices push higher.

The April contract was trading at $4.41 per million Btu—the energy equivalent of roughly 1,000 cubic feet of gas—this morning; forward months were in the $4s through 2023. The EIA estimates fuel switching would occur above low-$4 gas, keeping demand flat.

What will surprise is if reloading the storage this spring and summer to the traditional 3.5-Tcf-plus level entering this coming fall can be achieved. “(It) is physically possible,” report securities analysts with Tudor, Pickering, Holt & Co. “But injections have to be at or near record levels each week through the entire (reloading) season,” which is April through October.

“If late April/early-May injections are normal…then hitting a 3.8-Tcf storage target is unlikely, putting upward pressure on gas prices.”

Record, sustained low temperatures this winter has resulted in an average of 91.2 billion cubic feet of daily gas consumption beginning Nov. 1—10% more than last winter and 13% more than during the past five winters—the EIA reports. “Residential/commercial consumption increased by 17% over…the 2012-13 winter season, while population-weighted heating degree days—indicating cold weather—increased by 16%,” it adds, citing data from Bentek Energy LLC.

Adding 2.5 Tcf to storage in the coming months “would surpass the previous record, injection-season, net-inventory build, (which was during) 2001, by more than 90 Bcf, to end the injection season at 3.459 Tcf.

“While the projected storage build for the upcoming injection season would be a record, total Lower 48 (end-of-October) inventories in 2014 would still be at their lowest level since 2008. High injections would not fully erase the deficit in storage volumes caused by this winter’s heavy withdrawals,” the EIA concludes.

Richard Hastings, macro-strategist for Global Hunter Securities LLC, notes that 195 Bcf was drawn from storage during the week ending March 7, “vastly outpacing any comparable week of historical comparisons.”

The total draw this winter “already surpasses what occurred in 2003,” he adds.

“However, there is yet a bit of time left for the season to surpass 2003, not only in a statistically normalized way but also in an actual way: If a few more cold snaps take place, then not only would end-of-season working gas decline to our new forecast of 706 Bcf but there are chances for comparisons to the 642-Bcf level hit in April 2003.”

–Nissa Darbonne, Author, The American Shales; 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.

Robert Gates: U.S. Has ‘Badly Misjudged’ The Arab Spring

February 10th, 2014 Nissa Darbonne | Comments Off

But the greatest threat to national security is within the White House and Congress, he says.

The U.S. has “badly misjudged what we have called ‘the Arab Spring.’” Citing those and other revolutions, such as Cuba’s, “only one turned out reasonably well in the first decades and that was our own,” former U.S. secretary of defense Robert Gates told oil and gas executives Thursday in Houston.

Gates, whose Duty: Memoirs of a Secretary at War was released in January, spoke at NAPE Expo’s annual fund-raiser for veteran programs. Charities each receiving $100,000 donations this year are The Mission Continues, Lone Survivor Foundation, Support-A-Soldier and Canine Companions for Independence.

What complicates reaching peaceful discourse within Islamist countries that have undergone revolution in the past few years is the multitude of factions in conflict, he said: Shia versus Sunni, reformers versus authoritarians, secularists versus Islamists and, ultimately, whether resolution can be found in the absence of oppression.

As for Iran, it “is determined to develop nuclear-weapon capability.” The goal pre-dates the Iranian revolution, meaning it transcends the government, which makes it difficult to believe the thinking would change with any shift in governance.

What is possible is “a nuclear-armed Iran instigating a nuclear-arms race in the most volatile region of the world…That’s why we have to do everything we can to prevent that eventuality.” The U.S. should not revise what it expects from Iran and the country should be held to a six-month deadline as the Iranians are great at slow-playing, which could compromise U.S. conviction in its requirements.

Other threats are North Korea, of course, which has a handful of crude, nuclear weapons. Also, the discovery of oil in the South China Sea pits China against neighbors in ownership claims.

But “the biggest threat to American national security today is found within the two square miles of the White House and Capitol Hill,” he said.

In his last years as secretary of defense, he encountered “internal conflicts within the executive branch” coupled with “parochial interests of so many members of Congress” as well as war within the Pentagon itself. “Over time, the broad dysfunction in Washington wore me down.” Members of Congress, with a few exceptions, have become “uncivil, incompetent in fulfilling constitutional duties…, thin-skinned, often putting (re-election) before country.”

His service under President George W. Bush and President Obama brought light to “two far different men.” Bush questioned advisors and took them to task; their loyalty to country first was not doubted. Of Obama’s advisors, Obama “was deeply suspicious of their actions” and intentions.

Also, Bush “supported the troops…and the mission….” Meanwhile, Obama “opposed the mission…He rarely told the troops…why their sacrifice was necessary…

“It all took a growing emotional toll on me…No one who had been in combat could walk away without scars.”

He read hometown newspaper articles about fallen American servicemen and -women before writing letters to their families, wanting to get to know each of them.

“My wars are over. For those who fought…their war will continue for the rest of their lives.”

–Nissa Darbonne, Author, The American Shales; 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.

U.S. Senate Committee To Launch U.S. Oil-Export Debate Jan. 30

January 22nd, 2014 Nissa Darbonne | Comments Off

The intersection of too much U.S. light-oil production and too little refining capacity for it is near.

The debate is on.

The U.S. Senate’s energy and natural-resources committee has booked a hearing for 10 a.m. EST, Jan. 30, on lifting the ban on exporting U.S.-produced oil as the clock is quickly ticking toward more U.S. light-oil production and too little U.S. refining capacity for it.

Michael Webber, deputy director of the University of Texas’ Energy Institute, told the Wall Street Journal earlier this month about what already appeared to be an imminent, national debate, “I think it will be a huge, knockdown fight because it pits environmentalists against national-security hawks against producers against consumers.

“It’s a cage match for a multi-hundred-billion-dollar market.”

The EIA reported today that its 2014 Annual Energy Outlook “projects declines in U.S. oil and natural gas imports as a result of increasing domestic production from tight-oil and shale plays. U.S. liquid-fuels net imports as a share of consumption (are) projected to decline from a high of 60% in 2005 and about 40% in 2012 to about 25% by 2016.”

U.S. gas exports as LNG are already set to commence in 2018 as newly constructed, liquefaction facilities come online, the EIA notes.

“Conversely, other major economies are likely to become increasingly reliant on imported, liquid fuels and natural gas. China, India and OECD Europe will each import at least 65% of their oil and 35% of their natural gas by 2020—becoming more like Japan, which relies on imports for more than 95% of its oil and gas consumption.” (Note: Click for the webcast of a U.K. House of Lords economic-affairs-committee hearing last week on development of the U.K.’s shale-gas potential. Testimony includes that of Chris Wright, founder of frac-mapping and -diagnostics firm Pinnacle Technologies Inc.)

The U.S. currently allows some export of U.S.-produced oil to Canada; there are a few, additional exceptions.

In short, forecasts are for yet more growth in U.S. production of light crude. Where is the intersection of too much light oil for indigenous refining capacity, will that make U.S. oil “stranded” and what effect would that have on WTI?

Garry Tanner, managing director for energy private-equity investor Quantum Energy Partners LP, was presented this question Friday during energy M&A group ADAM-Houston’s membership meeting.

“I think you’re already seeing that to a certain degree,” he said. “In any area, basin or country where you have dramatic growth, generally you see a bit of a disconnect from the market.

“It takes time to build that infrastructure and solve those issues.

“We definitely saw North American gas (prices) disconnect with the rest of the world; we have a discount on gas in the U.S. (now) versus everywhere else. You’ve started to see the differential between Brent and WTI and we’ve come to the point where we have, basically, pushed all of the light, sweet crude coming into the country away.

“There is a little bit still coming in on the (Gulf) coast and some long-term (contract) oil coming in from Saudi Arabia.

“But we are concerned about what that’s going to do.

“That is one of the risks you have (in investing in U.S. oil right now). There is a global risk of oil demand and then we have a localized risk, which is ‘What’s going to happen as we continue to grow light-oil supply when the refineries are built for heavy?’”

(Note: Also see the Jan. 9 blogpost: “U.S. Oil Exports Seem Premature But The Issue Is With The Type Of Oil Refineries Can Process.”)

–Nissa Darbonne, Author, The American Shales; 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.

U.S. Oil Exports Seem Premature But The Issue Is With The Type Of Oil Refineries Can Process

January 9th, 2014 Nissa Darbonne | Comments Off

Gulf Coast refineries need heavy oil while growing, new U.S. production is light oil.

Exporting U.S. oil while the U.S. still imports 8 million barrels of crude a day to meet indigenous demand for gasoline and other products seems premature. But the issue is with the type of oil U.S. refineries can process.

Most new U.S. oil production is light and sweet, notes Andy Lipow, president of advisory firm Lipow Oil Associates LLC. “The majority of U.S. refining capacity, particularly on the Gulf Coast, is set up to handle heavy sour. There are equipment limitations in switching from heavy sour to light sweet, although some refiners are updating their equipment to handle more light sweet.”

If more than half of U.S. refining capacity is for processing heavy sour, then is the intersection near of too much U.S. light sweet production and too little refining capacity for it? “I wouldn’t say that,” he says. “Some switching can go on. There are a variety of things that can be done.”

Sen. Lisa Murkowski (R-Alaska), who is the ranking member of the Senate’s energy and natural resources committee, issued a white paper Tuesday, calling for an end to the ban on exporting U.S.-produced crude oil. Currently, oil may be traded with Canada as it ships more to the U.S. than U.S. producers ship to it. Oil that has been imported to the U.S. can be sent to other countries, such as China. And there are a few other exceptions.

What Murkowski’s and others’ reports have not yet explained is how near the U.S. is to that flashpoint of too much light sweet. Murkowski, who provides several citations to other, credible work, writes only that “many producers, however, fear that rising light crude production will soon exceed not only the nation’s light refining capacity, but also the ability of refiners to adapt to the new production slate. When this point is reached, the U.S. oil resurgence will collide with the de facto ban on crude oil exports.”

East Coast refineries, such as one in Philadelphia that was to be shuttered before The Carlyle Group bought it in 2012, are benefitting from new light sweet supply. Refineries in the area had not switched to refining heavy sour crude in the 1990s while Gulf Coast refineries did.

U.S. oil production has grown from 4.21 million barrels a day in September 2005*—while many Gulf of Mexico and Gulf Coast oil wells were shut in as a result of Hurricane Katrina—to 7.04 million barrels in January 2013. In that month, the U.S. imported nearly 8 million barrels per day, while producing 7 million a day.

By October 2013, U.S. production had grown further to 7.75 million a day, the last month for which data is available from the Energy Information Administration.**

Meanwhile, U.S. imports of crude oil by gravity declined to some 1% for light, 40.1- to 45-degree oil in 2013 and had been 7.7% in 2010 and 12% in 1984, according to the EIA. Imports of yet-lighter, 45-plus declined to about 0.2% in 2013 and had been about 2% during much of the 2000s.

Imports of 35.1- to 40-degree oil have fallen to 8.8%, down from up to 20% in the 2000s. As for 30.1- to 35-degree oil, imports have fallen to about 26%, down from as much as 42% in the 2000s.

Heavier crudes of 30 degrees or less now represent the majority of imports: 7.7% is 25.1 to 30 degrees; 35.5% is 20.1 to 25 degrees; and 19.7% is 20 degrees or less. The lattermost had represented just some 6% of imports entering the 2000s.

“Over the past 15 years, the API gravity of crude oil processed in U.S. refineries has averaged between 30 and 31 degrees,” the EIA reported in its annual energy outlook this last spring. “As U.S. refiners run more domestic, light crude produced from tight formations, they need less imported light…crude to maintain an optimal API gravity. With increasing U.S. production of light crude…, the average API gravity of crude-oil imports declines.”

Platts reported that Department of Energy Secretary Ernest Moniz said of the oil-exports ban in December, “Those restrictions on exports were born, as was the Department of Energy and the Strategic Petroleum Reserve, on oil disruptions. There are lots of issues in the energy space that deserve some new analysis and examination in the context of what is now an energy world that is no longer like the 1970s.”

–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 September 2005 production was the least U.S. oil production in a month since July 1943. **The highest level of U.S. daily oil production was 10.04 million a day in November 1970.

Dan Rice, Sons Plan To IPO Their Marcellus- And Utica-Focused Rice Energy

January 8th, 2014 Nissa Darbonne | Comments Off

Private-equity sponsor Natural Gas Partners plans to sell some of its interest.

Former BlackRock Inc. managing director Dan Rice III and sons plan to IPO their 5-year-old, Marcellus- and Utica-focused Rice Energy Inc., listing it on the NYSE as RICE.

Dan Rice IV, 33, is chief executive officer and previously was an investment banker for Tudor, Pickering, Holt & Co. Securities Inc. and an analyst for offshore driller Transocean Inc.

Toby Rice, 31, president and chief operating officer, was founder and president of frac-technology firm ZFT LLC. Derek Rice, 28, is vice president, exploration and geology; previously, he worked as a wellbore geologist for an oilfield-service company.

Prior to joining BlackRock, Rice III, 62, was a portfolio manager for State Street Research & Management. Currently, he is lead portfolio manager for GRT Capital Partners LLC’s energy division.

The Rice family formed the E&P in 2008 and gained private-equity backing from Natural Gas Partners in 2012, currently totaling $300 million.

The Canonsburg, Pennsylvania-based producer holds some 43,351 net (45,562 gross) acres over Marcellus shale, mostly in Washington County, and 46,488 net (48,660 gross) over the Utica/Point Pleasant play, mostly in Belmont County, Ohio. Since its first horizontal Marcellus completion in October 2010, it now has 37 of these wells with a 100% success rate and laterals averaging some 5,700 feet. Estimated ultimate recovery is between 1.2- and 2.9 billion cubic feet of gas per 1,000 feet of lateral. It had four rigs drilling its inventory in December of an estimated 349 gross (325 net), additional Marcellus well locations.

Third-quarter 2013 production was 128 million cubic feet a day from the Marcellus wells as well as from its three horizontals in the overlying Upper Devonian. It expects most (36,932 net) of its Marcellus acreage is prospective for gas from this formation as well, resulting in 211 gross (194 net) potential, additional drilling locations.

Meanwhile, in the Utica play, it spud its first attempt, Bigfoot 7H, in October in Belmont County and has two rigs drilling for it there where it estimates it has 753 gross, 233 net, prospective well locations. Bigfoot encountered bottomhole pressure of 8,800 psi (nearly 0.7 psi per foot) and had to be plugged, however. Rice plans to drill an adjacent horizontal with a new plan to handle the reservoir pressure.

Proved reserves as of Sept. 30 were 552 Bcf, all in southwestern Pennsylvania. Plans are to invest $1.1 billion, consisting of $299 million in the Marcellus, $132 million in the Utica, $386 million in further acreage acquisitions and $263 million on take-away infrastructure.

In December, coal operator Alpha Natural Resources Inc. agreed to sell to Rice its 50% interest in a Marcellus joint venture for $100 million in cash and $200 million in stock. In October, Rice and Gulfport Energy Corp. agreed to jointly develop some 50,000 net acres over Utica in Belmont County with Rice as operator of acreage in the northern area of the deal (27,000 net acres) and Gulfport as operator in the south (23,000 net acres).

The company plans to use IPO proceeds to pay $240 million of bank debt and the $100 million to Alpha; the balance will be used for capex. NGP plans to sell some of its interest.

Other members of management include Grayson Lisenby, chief financial officer formerly with NGP and investment-banking firm Barclays Capital Inc.; Ryan Kanto, vice president, production, formerly with Encana Corp.; John LaVelle, vice president, drilling, formerly president of Geological Engineering Services Inc.; and Varun Mishra, vice president, completions, formerly with EOG Resources Inc.

Lead underwriters are Barclays Capital Inc., Citigroup Global Markets Inc. and Goldman, Sachs & Co.

Additional underwriters are BMO Capital Markets Corp.; Capital One Securities Inc.; Comerica Securities Inc.; FBR Capital Markets & Co.; Johnson Rice and Co. LLC; RBC Capital Markets LLC; Scotia Capital Markets; Sterne, Agee and Leach Inc.; SunTrust Robinson Humphrey Inc.; Tudor, Pickering, Holt; and Wells Fargo Securities LLC.

–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.

McClendon Partners With REIT Managers To Form New E&P Operator

December 15th, 2013 Nissa Darbonne | Comments Off

The raise of up to $2 billion is offering units for $20 each.

Aubrey McClendon has partnered with REIT-fund managers to offer units in a new oil- and gas-acquisition and exploitation company, American Energy Capital Partners LP. The raise of up to $2 billion is to purchase producing and non-producing properties onshore the U.S.

Units are to be priced at $20 each and won’t be publicly traded, according to the S-1 filing with the SEC on Friday.

In brief, the partnership is managed in a services contract by McClendon’s Oklahoma City-based AECP Management LLC, which he formed in July after leaving shale-play leader Chesapeake Energy Corp., which he co-founded in 1989.

The general partner, American Energy Capital Partners GP LLC, is led by Nicholas Schorsch and Bill Kahane, whose American Realty Capital Trust Inc. has led the formation of six public and five non-public REITs beginning in 2007 and merged with Realty Income Corp. this past January. The general partner also owns the new company’s limited partner.

Schorsch and Kahane also control the offering’s marketer, Realty Capital Securities LLC. Edward Weil Jr., Nicholas Radesca and Peter Budko, three former officers of the pair’s REITs, will be executive officers of the new E&P company.

American Energy aims to buy working, leasehold, royalty, overriding royalty, production-payment and other interests in oil and gas properties. “We have not identified any oil and gas properties we will acquire at this time,” it reported Friday.

The S-1 mentions McClendon’s personal oil and gas interests in Chesapeake’s Founders Well Participation Program in a glossary of definitions but does not mention how these will be relevant to the new company.

Distributions of $1.20 a year per unit, paid monthly, are targeted. Assets accumulated are to be divested within five to seven years of the raise with net proceeds paid to unit-holders.

As manager, McClendon’s company will be responsible for procuring acquisition candidates, financing, operating properties, divesting, hedging and other traditional E&P responsibilities for a monthly fee equivalent to 3.5% of the equity raise on an annualized basis until the offering and 4% annually after in addition to fees for buying and selling properties and procuring financing. The general manager is to be paid 1% monthly, annualized.

Offering costs are expected to be 11.5% of the total raised with 7% paid in sales commissions and 3% to the dealer-manager, plus 1% to the general partner and 0.5% to McClendon for their fees and expenses related to the offering.

McClendon’s new company has 125 employees to date.

–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.

Australia, Argentina Likely To Develop Tight-Rock Resources Next

December 10th, 2013 Nissa Darbonne | Comments Off

Turkey, Russia also likely; the U.K., possibly; China, some day.

Production of tightly trapped oil and gas outside North America will still likely occur in Australia and Argentina before in other countries, according to securities analysts with Tudor, Pickering, Holt & Co. Securities Inc.

The research group’s “shale-play heat map” factors in geology, economic incentives, the availability of oilfield services, market access, regional commodity pricing, take-away infrastructure, whether investors would fund projects in the region and whether there is government and community support of tight-rock development.

“The rock is most important,” note team members Shola Labinjo and Anish Kapadia. “After that, as free-market capitalists, we tend to weigh private-sector-resource allocation very heavily.”

Australia’s Cooper Basin (tight gas) is likely to be development based on the existence of economic incentive. “But, in a nod to the power of geology, we like Argentina’s Neuquén Basin (tight oil and tight gas) too,” they add.

This is despite that Argentina does not fare as well on the measure of free markets, they note, as Argentina expropriated Repsol SA’s interest in YPF SA last year without fair compensation and also controls prices for gas produced in the country.

The pair also likes Turkey’s Anatolian (tight oil) and Thrace (tight gas) basins and Russia’s Bazhenov formation (tight oil) in West Siberia Basin. But Labinjo and Kapadia have “mixed feelings on the Bowland (tight-gas basin) in the U.K. and (tight gas from) Sichuan (Basin) in China.”

For tight-gas development in Bowland Basin, public support will be necessary. As for tight-gas development in Sichuan Basin, little profit incentive, high costs, market regulations and geology have limited development to date, they note.

As for Poland, where shale-gas exploration has been attempted in the past few years ago, resources found have paled in comparison with the cost of creating a modern oilfield-service industry in the country and building infrastructure. It “is now our least preferred,” the analysis report.

Major oil companies are leading tight-resource exploration abroad, they also note, such as Royal Dutch Shell and Chevron Corp., which are looking at South Africa’s tight-gas Karoo Basin.

“Noticeably absent are the U.S. independents, which are, understandably, pre-occupied with opportunities at home.”

Development of tight-rock resources in other countries, such as France, is possible but has failed on the measure of government support. “Geologically, the elements are in place in most regions (of the world); however, specific issues, including skepticism around hydraulic fracturing…, are impeding progress. Host governments have been divided in their response…A few appear to be in engaged in a ‘who can ban (fracing) the most’ contest.”

Scott Gruber and fellow securities analysts with Bernstein Research report on development of non-North American production of just tight gas that “we continue to maintain our view that commercial development is inevitable but will occur at a much slower pace than the U.S., with little commercial production over the next three years.”

They add that

Mexico has large tight-gas resources but is looking to more immediately import more gas instead,

–Development of tight-rock resources in Colombia will likely focus on liquids-rich rock as Colombia consumes very little natural gas,

France has banned fracing,

Germany has banned fracing,

–Interest in tight rock in Russia has been limited to those that may produce oil and not gas as the country has proven enough gas-production potential already and

–Commercial tight-gas-production potential may exist in North Africa and the Middle East as well.

“However, the U.S. provides a differentiated operating environment that is ideally suited for shale development. This includes a broad E&P industry with ample access to capital, deep geologic knowledge, a legal system that compensates land owners for development, broad oil service and midstream industries to provide the requisite development equipment and infrastructure, limited environmental backlash, especially given the benefit of reduced coal consumption and crude imports, and generally good access to water.

“Many—or at times—all of these factors do not exist in the countries abroad that are also endowed with quality shale,” the Bernstein team report.

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