Prospecting For Niobrara Gas … In South-Central North Dakota

July 28th, 2014 Nissa Darbonne | Comments Off

Strata-X is testing a gas-play concept on the edge of the Williston Basin.

The shallow, Cretaceous-age Niobrara is the target of a seemingly extra-wild wildcat program by prospectors at Strata-X Energy Ltd. in dry-hole Emmons County in south-central North Dakota.

Reflecting the operator’s hopes for making a play, Strata-X has dubbed its 120,000-acre prospect the “Sleeping Giant Gas Project,” borrowing part of the moniker from geologist Dick Findley’s name for his “Sleeping Giant” Bakken-oil play in 1996 in eastern Montana. Findley’s prospect, which became Elm Coulee Field, has made more than 125 million barrels, beginning in 2000, and inspired the modern North Dakota play that currently makes nearly 1 million barrels a day. A nascent, northeastern extension of Elm Coulee Field has made more than 5.4 million barrels.

North Dakota’s Department of Mineral Resources director Lynn Helms told the Associated Press in Bismarck that Denver-based Strata-X’s (Australia: SXA) request for permits to drill in Emmons County were “rare.”

Of 34 wells drilled for oil or gas in the county, beginning in 1943 and ending in 2007, all have been dry holes, according to state records. Six additional wells were stratigraphic tests.

Until Strata-X’s Rohweder #1-11 was spud in June in Township 132 North, Range 75 West, Section 11, the last well attempted in the county was by Staghorn Energy LLC in January 2007 four townships north. Staghorn had received a permit for a “Rohweder 1-11” but let that and another permit, Wohl 1-5 one section north, expire.

A nearby attempt

For a look at the stratigraphic column in the area, which approaches the edge of the Williston Basin, the deepest well drilled near Strata-X’s Rohweder #1-11 is Franklin investment Co. #1 to 5,359 feet in 1943 by Noble Drilling Co. for Tulsa-based Northern Ordnance Inc. The objective was Deadwood sandstone at 6,000 feet and drilling was quit shortly after encountering water and granite at 5,353 feet. It was spud June 10, 1943, and plugged on July 22.

Carter Oil Co., which began wildcatting in the Williston Basin in the 1930s and continued on into the 1950s, loaned its geologist, Loy E. Harris, to Northern Ordnance to study the rock cuttings, according to the state well file. Harris borrowed a microscope from Wilson Laird, state geologist, North Dakota Geological Survey.

Eight cores were taken along the stratigraphic column.

From the cuttings, Harris reported that “except for the Dakota, Fuson and Lakota sections, there were no sands or suitable reservoirs present above the Amsden of Mississippian age. The three above-mentioned formations contained sands, but they were rather tight and had no shows as confirmed by (a) Schlumberger electrical survey. In the Amsden formation, some rather porous dolomites and dolomitic limestones were encountered without any shows of oil.

“The Big Snowy and Madison groups of the Mississippian had very little porosity that could be noted in the cuttings. The Devonian rocks were represented principally by shales. The few limestones present contained no shows and were tight and hard.

“The Ordovician above 4,881 feet…had very little porosity and no shows of oil. From 4,881 feet to 4,910 feet, a fine dolomitic and shaly sandstone was encountered that was finely porous but with no show of oil. Between this sandy zone and 5,090 feet were rich-green to dull-brown shales which, from appearances, should make very good source beds.

“At 5,080 feet, a sandstone was topped. This sandstone graded from fine near the top to coarse and loose near the middle and back to fine near the base. This entire section, except for a few, thin, shale stringers, had fair to good porosity and would be an excellent reservoir when found under the proper structural conditions.”

The well traveled through Pierre, Niobrara (at 1,260 feet), Carlile, Graneros, Muddy, Dakota sandstone, Fuson, Lakota, formations labeled only Jurassic and Triassic, Amsden, Big Snowy, Madison (Mission Canyon and Lodgepole), formations labeled only Devonian and Ordovician, Granite Wash and granite.

A Niobrara structure

Strata-X’s program is to target a Niobrara structure in the area that contains biogenic gas generated from ancient algae at about 1,300 feet. As the Niobrara is fractured there, it reported, it estimates porosity of up to 40%. Secondary targets are the shallower Pierre and the deeper Greenhorn/Belle Fourche—which were named since Northern Ordnance’s 1943 well—the Mowry shale and the Muddy.

Spud June 22, Strata-X’s vertical Rohweder #1-11 was drilled to 1,450 feet by June 26. The company reported, “In total, gas shows were encountered over an 80-foot interval of the targeted Niobrara formation, with gas shows peaking at approximately 300 units over a background of 25 units. In drilling portions of the targeted Niobrara formation, oil fluorescence and oil cut were also observed.”

If the well produces meaningfully upon completion, the company plans to drill three more holes this year: Hoff #1-32 due north and Just #1-24 and Aberle #1-31 east of there in McIntosh County.

Fourteen of 14 attempts in McIntosh County, beginning in 1952 and ending in 1975, were dry holes.

Tim Hoops, Strata-X chief executive, president and managing director, was president of wildcatter Kestrel Energy Inc. until its going-private transaction in 2005; his early career as a geologist was with Amoco Production, Cities Service and Santa Fe Energy.

Strata-X’s chairman is Ron Prefontaine, who was a director of Australia-listed gas producer Arrow Energy Pty Ltd., which was acquired in 2010 by Royal Dutch Shell and PetroChina for $3.5 billion. Prefontaine was also a director of Bow Energy Ltd., which was acquired by Arrow for $550 million in 2011.

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas, Oil and Gas Investor This Week, A&D Watch, Contact Nissa at

Scoop, Stack And SoHot—A Guide To Oklahoma’s Oil-Play Acronyms

July 25th, 2014 Nissa Darbonne | Comments Off

The plays stretch from northwest of Oklahoma City to near the Texas border.

Unit Petroleum Corp., the E&P unit of Unit Corp., stepped up in May with an acronym of its own for an Oklahoma oil play—SoHot, representing “southern Oklahoma Hoxbar oil trend.” The company plans 13 wells this year in the play, in Grady County southwest of Oklahoma City.

“The SoHot has six stacked sands,” reports securities analyst Marc Bianchi with Cowen & Co. “Thus far, Unit has drilled and completed horizontals in two of the zones, identifying an oily zone—Marchand—and a gassy zone—Medrano.”

The Hoxbar is a roughly 2,000-foot-thick, Pennsylvanian-age sequence of sand and shale intervals, according to Unit, which estimates it to contain four to six sand intervals that may be commercial. The oily Marchand sandstone is at about 11,000 feet; the gassy Medrano sandstone, 9,800 feet.

With a 4,300-foot lateral, the Marchand wells cost some $7 million and may produce 300,000 to 500,000 barrels of oil equivalent (BOE)—85% to 90% oil—Unit reports. With a similar lateral, the Medrano wells cost some $4.2 million and may produce 3.0- to 4.5 billion cubic feet of gas equivalent, 30% liquids.

In the southwestern Grady County area, Unit has 12,810 net acres across 50,560 gross. With an $82-million budget for it this year—increased some 50% in May—it expects to have three rigs drilling it in the second half.

Bianchi reports that the position may offer 175 to 200 SoHot well locations with most of these targeting the gassy Medrano. Unit’s funding of the SoHot program and an uptick in Granite Wash drilling in western Oklahoma will be from a reduction in Mississippian Lime drilling “where results have been inconsistent,” he reports.


Also targeting Grady County, Continental Resources Inc. revealed its Scoop play in 2012, creating the acronym for it from “south-central Oklahoma oil province.” The play, south of Oklahoma City and reaching toward the Texas border, is concentrated in the oil window of the Devonian-age Woodford shale, where the formation is up to 400 feet thick at about 15,000 feet. It is focused largely in Grady, McClain, Garvin, Stephens and Carter counties, and Continental counts some 450 wells now by it and other operators, delineating the play. Continental has some 425,000 net acres.


Following on Continental’s Scoop, Newfield Exploration Co. announced its Stack play last fall, naming it for “Sooner Trend, Anadarko (Basin), Canadian (and) Kingfisher (counties).” The play, which is northwest of Oklahoma City, targets the Woodford as well as Mississippian-age shales.

The Sooner Trend Field has produced nearly 500 million barrels of oil since its discovery in 1945. Newfield pioneered the dry-gas Woodford-shale play in 2003 in the western Arkoma Basin, east of its current, liquids-rich Woodford play in the Anadarko Basin. It has more than 170,000 net acres prospective for Woodford in its Stack play and more than 150,000 net prospective for the overlying Meramec. It also has some 75,000 net acres in the Scoop play.


Midstream operator Oneok Partners LP reported this week that it is building a 200-million-cubic-foot-per-day gas-processing plant in the midst of the Scoop play to monetize associated gas from the oil production.

Oklahoma’s monthly oil output has grown from 5.7 million barrels in April 2010 to 10.5 million this past April, according to Energy Information Administration data. The rate was last exceeded in January 1989. The state’s production reached 14.5 million barrels in January 1986, according to EIA data beginning in January 1981.

Unit Corp. has employed another acronym in its operations: Rig-operator subsidiary Unit Drilling Co.’s new-build rig has been dubbed Boss for “box on (box) self stacking.” Its first Boss is at work and three more, which are each also contracted, are being constructed.

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas, Oil and Gas Investor This Week, A&D Watch, Contact Nissa at

McClendon To Manage Energy 11 Partnership, Offering Up To 100.3 Million Units

July 18th, 2014 Nissa Darbonne | Comments Off

E11 founders are REIT managers, private oil and gas investors, and ex-Chesapeake officers.

Fort Worth-based Energy 11 LP has filed an S-1 to privately offer at least 5.3 million units at $19 each and up to 95 million additional units at $20 each, raising up to $2 billion to acquire working and other interests in onshore-U.S. oil and gas properties recommended by Aubrey McClendon’s American Energy Partners LP.

The minimum purchase is $5,000. At least 5.3 million units must be sold by Sept. 30, 2016, or the offering will be withdrawn, according to the S-1. Commission and marketing fees for the first 5.3 million units will be $1.14 per; for additional units, $1.20 per. The broker-dealer is New York-based David Lerner Associates Inc. Partnership organizers’ fees will be $1.5 million for the minimum offering and $8 million for the balance. (Editor’s note: Revised on 7-20-14 to state “Sept. 30, 2016″ rather than “Sept. 30.”)

The general partner will be managed by

–Glade Knight, chairman and founder of Apple Hospitality REIT Inc.;

–David McKenney, chief financial officer and senior advisor to Apple;

–Anthony Francis (Chip) Keating III, a principal in oil, gas and real-estate investor Rock Creek Capital, co-chief operating officer;

–Michael Mallick, founder of Fort Worth-based real-estate and energy investor Mallick Group Inc., co-chief operating officer; and

–landman Clifford Merritt, a former Chesapeake vice president, who will be president.

Keating, 34, is the son of former Oklahoma Gov. Francis Anthony (Frank) Keating II. He was Chesapeake’s in-house realtor until 2010 in more than $850 million of deals for land for corporate headquarters, field offices and drillsites in urban areas as well as for investment properties.

Merritt, Keating and Mallick have interests in McClendon’s American Energy Ohio Holdings LLC and American Energy Woodford Holdings LLC. In addition, Keating and Mallick have interests in American Energy-Permian Basin LLC and American Energy-Marcellus LLC.

McClendon’s E11 Management LLC, a unit of his American Energy Partners LP, will recommend and operate the properties Energy 11 LP buys.*

According to the S-1, McClendon’s AEP has grown in about 15 months to some 400 employees, including 125 in engineering, drilling and operations; 38 in geoscience and petrophysics; and 78 in land. Senior officers, in addition to McClendon, are

–Jeff Fisher, chief operating officer and formerly Chesapeake’s executive vice president, production;

–Scott Mueller, chief financial officer and formerly a partner in private-equity firm Hall Capital Partners;

–Jeff Mobley, senior vice president, major acquisitions, and a CFA who was Chesapeake’s senior vice president, investor relations and research;

–Curt Launer, senior vice president, capital formation, and formerly an equity analyst for Deutsche Bank Securities; and

–Jim Linville, director, acquisitions engineering, and formerly the Rockies business-unit manager, operations engineering, for Devon Energy Corp.

Energy 11 LP is the second McClendon has been enlisted to manage. In December, REIT organizers unaffiliated with oil and gas investments, formed American Energy Capital Partners GP LLC to raise up to $2 billion to invest in properties recommended by AEP. (See McClendon Partners With REIT Managers To Form New E&P Operator.)

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas, Oil and Gas Investor This Week, A&D Watch, Contact Nissa at

* From the S-1: We will pay the Manager a monthly general and administrative expense compensation amount (“Monthly G&A Expense Amount”) at an annual rate that will be 1.75% of the net proceeds from the sale of common units, less commissions, marketing fee and offering and organization expense, plus the amount of outstanding indebtedness, which we refer to as the reimbursement base, for the first six months following the initial closing. Thereafter, the Monthly G&A Expense Amount will be at an annual rate of 3.5% of the reimbursement base and will reduce to an annual rate of 2% of the reimbursement base over time. In addition, pursuant to the Partnership Agreement, concurrently with the initial closing of the sale of common units pursuant to this offering, we will issue to an affiliate of the Manager (“Incentive Holdings”), 100,000 class B units that will entitle Incentive Holdings to participate in Partnership distributions after investors in the common units have received cash distributions equal to the preferred distribution, any arrearages in the preferred distribution and $20.00 per unit.

Deals For Oil, Gas Assets To Reach $100B This Year

July 4th, 2014 Nissa Darbonne | Comments Off

‘People fill their plate with more than they can eat.’

Nearly 30,000 wells have been drilled now in the Eagle Ford, Bakken, Fayetteville, Marcellus, Haynesville, Niobrara and Utica, just since year-end 2007, and three of these—the Bakken, Fayetteville and Marcellus—were already under way.

And the count doesn’t include potential wells in the Permian Basin.

“The Permian is still a story to be written,” Bill Marko, managing for investment-banking firm Jefferies LLC, told Oil and Gas Investor’s Energy Capital Conference attendees in an entrepreneur’s forum in June.

Just counting the inventory of 12, sample, onshore-U.S. operators’ well-location inventory ranges from 66,000 to 7,900 each, he said. And the list excludes, for example, that of Pioneer Natural Resources Co., which has an estimated 20,000 well locations in its legacy Permian position alone.

Overall, resource-play operators have between eight and 68 years of inventory to drill, “some of which they’ll never get to,” Marko said.

Among those buying into plays, “people fill their plate with more than they can eat.” Hence, conditions are ripe for M&A transactions. Through early June, just as American Energy Partners LP announced deals totaling more than $4 billion for Permian and in the Utica-play properties, 2014 deal volume totaled $37 billion. Marko estimates transactions by year-end will reach $100 billion.

“One of the things that chilled 2013 deal flow was activist investors,” he said. Deal volume for 2013 was some $48.2 billion, compared with $93.7 billion in 2010, $90.1 billion in 2011 and $122.3 billion in 2012.

New managements are divesting gas properties for oil-weighted assets and selling non-core positions to invest in improving overall performance metrics, debt and equity markets are open, and private-equity managers alone have $35 billion to invest, which Marko noted “equals some $100 billion of purchasing power” when leveraging the equity with debt.

Buyers have notably included foreign-based companies, whose investments in U.S. resource plays have totaled $123.3 billion since year-end 2008. “Some of them have done good deals and some of them have done bad deals,” he said. He estimates that two thirds of the $350 billion of all resource-play deals since 2008 are not economic.

New buyers include MLPs, such as Memorial Production Partners LP, which has bought into the Eagle Ford play. Another potential buyer may be LNG-export operators, which see ownership of physical gas-producing assets as a possible arbitrage in price fluctuations, he said. However, LNG operators are concerned with whether they have or can acquire the expertise to operate oil- and gas-drilling operations.

As for natural gas prices, will these grow? On the demand side, the impact of exporting it is unknown, he said. “How big? I don’t know.” The potential growth of natural gas in transportation is an additional factor. More exciting is the growth in demand for natural gas in manufacturing operations, however. He estimates some 5 billion cubic feet of new, daily demand from this.

But, for example, Appalachian Basin operator Rice Energy Inc. reported on June 2 that it brought on a new Utica well, Bigfoot 9H, with an IP of 42 million cubic feet equivalent a day, he noted.

“It’s going to be tough to ever say we’re going to be short of gas,” he concluded. “…We’re in this price environment for a very, very, very long time.”

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas, Oil and Gas Investor This Week, A&D Watch, Contact Nissa at

Look Who’s Doing It Again: Frank Lodzinski

June 23rd, 2014 Nissa Darbonne | Comments Off

The four-time E&P build-and-divest success aims to take his newest public via a merger with Earthstone Energy.

Earthstone Energy Inc. shares (NYSE MKT: ESTE) shares are up 59% in five weeks in anticipation of Frank Lodzinski’s take-over of the company in a reverse merger with Lodzinski’s Oak Valley Resources LLC.

The deal is expected to close in September or October. Lodzinski said earlier this month, in Oil and Gas Investor’s annual Energy Capital Conference, that he looks forward to being in the public arena again. “We’re about 35% gas (reserves) right now,” he said of Oak Valley’s portfolio.

Earthstone primarily operates in the Williston Basin and South Texas and has net proved reserves of 3.2 million barrels of oil equivalent (BOE), 82% liquids, and production of 600 BOE a day. Oak Valley has 11.4 million BOE of proved reserves, 65% liquids, leasehold of 67,000 net acres and production of 2,150 BOE a day, primarily from the Eagle Ford in South Texas.

The combined company’s liquids reserves will be 68.5%. Oak Valley shareholders—including management, EnCap Investments LP, The Vlasic Group, Wells Fargo Energy Capital Inc. and BlackGold Capital Management LP—will own 84% of Earthstone.

As for the combined company’s name, Lodzinski, 64, said he may shed the “Oak Valley” moniker he gave his current start-up, as peers have teased that it sounds like the name of a retirement home.

Lodzinski’s career began in the early 1970s as an auditor of utility companies. In 1984, he began rolling up failing drilling partnerships into Energy Resource Associates Inc., particularly with financial backing of the Vlasic family, which sold its interest in the pickling company in 1978. Some of the assets were sold for stock in Hampton Resources Corp., which was sold in 1995 to Bellwether Exploration Co. Lodzinksi then formed Cliffwood Oil & Gas Corp., acquiring a controlling interest in Texoil Inc. He sold Texoil in 2001 to Ocean Energy Inc., which later merged into Devon Energy Corp.

Lodzinski then took on the restructuring and liquidation of Aroc Inc. and, in 2004, his Southern Bay Energy LLC took on Aroc’s remaining assets. Merging Southern Bay into GeoResources Inc., Lodzinski sold that in 2012 to Halcon Resources Corp.

According to an Earthstone and Oak Valley report,

–Hampton Resources produced a 30% return to preferred investors and 700% return to initial investors,

–Texoil, 250% to preferred investors, 300% to follow-on investors and 1,000% to initial investors,

–Aroc, 17% to preferred investors and 400% to initial investors, and

–Southern Bay, 40% to initial investors.

Lodzinski noted in the conference in June that the Vlasic family has backed his start-ups all along, beginning in 1984. Capital partners with experience are the best, he told industry members who are considering starting their own companies. “The worst thing you can do is take in people who don’t understand the risks,” he said.

His team at Oak Valley has worked with him for between 12 and 25 years, he added. And, he noted, the job of running an oil and gas company isn’t a job. “It’s a commitment…You have to think of everything. Tonight it might be frac sand or logistics or oil prices….” His team stays on top of the day-to-day “so I can stay ahead of the ball and anticipate where we’re going because these plays are so logistically complex.”

Shares of Earthstone, which was formed in 1969 as Basic Energy Science Systems Inc., traded below $2 into 2003 and pushed to $27.50 in 2006 as EOG Resources Inc. and others began to prove Bakken leasehold commercial in North Dakota. (Note: Share prices are adjusted for a 1-for-10 split in January 2011.) The price rose and tumbled during the next several years to about $13 in July 2013.

Prior to Lodzinski’s news on May 15, shares were $21.74; they closed at $34.61 Monday.

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas, Oil and Gas Investor This Week, A&D Watch, Contact Nissa at

Range Resources Responds To Magnum Hunter’s Marcellus Claim

June 13th, 2014 Nissa Darbonne | Comments Off

Range is proud to have pioneered the Marcellus shale (play) a decade ago.”

Several individuals who attended Hart Energy’s recent DUG East 2014 conference in Pittsburgh have asked about remarks Magnum Hunter Resources Corp. chairman and chief executive officer Gary Evans made that a Magnum subsidiary made the first Marcellus well—in 2004—rather than Range Resources Corp.

“A company I’m not going to name, but their name rhymes with mange, claims that their Renz 1 (in 2004) in…Pennsylvania, was the first slickwater frac in the entire Marcellus that kicked off this boom that we’re all here talking about. Well, that’s simply not true,” Evans said.

“In 2003, Triad Hunter (LLC), a wholly owned subsidiary of Magnum Hunter, plugged back a non-economic Clinton-Medina sandstone well over the Marcellus shale. This well was located in…Noble County, Ohio. The name of that well is the Addis 2A. The well was perforated from 4,006 feet to 4,080 feet on Nov. 14, 2003, and, on April 30, 2004, BJ Services (Co., now a part of Baker Hughes Inc.) performed a slickwater frac, using 3,290 barrels (i.e., roughly 138,000 gallons) of treated freshwater and 73,000 pounds of 20/40 sand. Initial shut-in pressure was 1,550 psi.

“The well IPed a whopping 100,000 cubic feet a day,” he quipped, “but this was the very first Marcellus well in the whole Marcellus play. We found this out after digging through our records (after) we bought Triad, a 23-year-old company, that its well in Noble County was the first Marcellus well and not (Range’s well) in Pennsylvania.”

Rocky Roberts, senior vice president, Appalachian operations, for Triad Hunter LLC, says Triad’s Addis 2A was commercial. Triad went on to make another vertical, Marcellus well in Pleasants County, West Virginia, in the summer of 2004. Roberts was with the company at the time.

He adds, however, “I think it is fair to (give) credit to Range for the first horizontal completions.”

Range Resources completed its vertical Renz 1 well in the Marcellus in western Pennsylvania in October 2004, using the sand-light, gel-light, frac recipe that had been shown, beginning in the late 1990s, to be successful in completing Barnett-shale wells. In this, which is known as the “light-sand frac,” mostly water and a small amount of sand and gel—rather than large amounts that are used in “massive hydraulic fracs”—are used to improve permeability.

(Editor’s note: What is italicized was added to this blogpost on July 20, 2014.)

Range responds, “The Ohio regulatory agency does not recognize the well as being in the Marcellus.”

Range’s Renz 1 IPed some 800,000 cubic feet per day. It proceeded to drill several, additional, vertical Marcellus wells. Its first three horizontal attempts—in the spring of 2007—had IPs ranging from 20,000 to 600,000 cubic feet a day. Each was uneconomic due to the higher cost of horizontal—versus vertical—wells.

Upon importing a rig and frac equipment and crews from outside Appalachia, Range landed a fourth horizontal, Gulla 9, in the uppermost section of the Marcellus in August 2007. The well IPed 3.2 million cubic feet a day. The next three wells IPed 3.7-, 4.3- and 4.7 million a day.

Range reports, “Magnum Hunter’s Addis #2A has produced a cumulative 14 million cubic feet of gas and was producing only a few thousand cubic feet a day in 2012. It’s projected, cumulative, gross recovery will be less than 20 million cubic feet of gas equivalent. This is not enough to justify additional drilling—i.e., it was not commercial—and it was not offset. Magnum’s West Virginia well had similar rates and a similar projected recovery to their Ohio well. Neither well was commercial, in that they could not justify drilling and completion dollars for a new well.”

Range’s Renz 1 has produced 213 million cubic feet of gas and some 400 barrels of oil with an estimated, cumulative, gross recovery of 600 million cubic feet of gas equivalent. “This was commercial and the well was offset with numerous, vertical, Marcellus-shale wells,” Range reports.

It adds, “Range is proud to have pioneered the Marcellus shale (play) a decade ago. Attempts to complete the Marcellus by us and many operators date back several decades, but it was through the hard work and vision of Range’s technical team—led by Bill Zagorski, a geologist recognized by the Pittsburgh Association of Petroleum Geologists as the ‘Father of the Marcellus’ and the 2013 recipient of the American Association of Petroleum Geologists’ Outstanding Explorer Award—that unlocked the play by successfully applying a Barnett-style, hydraulic, fracture-stimulation, which exceeded 1 million gallons, on the Renz #1 in October 2004.

“The Renz is without question the well that pioneered the Marcellus. At the time, it was the largest hydraulic-fracture treatment east of the Mississippi and it was the first commercial well that encouraged Range—and, eventually, other companies—to further develop the Marcellus. Additionally, Range’s development drilling that occurred as a result of the Renz’s success helped to encourage Range to help pioneer and drill the first horizontal Upper Devonian shale and Utica/Point Pleasant shale wells in 2009.

“Today, the Marcellus is the largest, producing, natural-gas field in the United States and—when combined with the Upper Devonian, which sits above the Marcellus, and the Utica/Point Pleasant, which sits beneath the Marcellus—could one day be recognized as the largest known field in the world. At the same time, this discovery now supports more than 240,000 jobs in Pennsylvania, while reducing energy costs for consumers and generating billions of dollars in royalties as well as taxes and fees for state and local governments.”

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas, Oil and Gas Investor This Week, A&D Watch, Contact Nissa at

All The Pretty, New, Permian Wells…But Where Will The Oil Go?

June 4th, 2014 Nissa Darbonne | Comments Off

Chris Keene: “(And) you have the Delaware Basin sitting out there, saying, ‘Wait a minute. What about me?’”

As oil flowing from Texas and New Mexico has grown to more than 3 million barrels a day, railers, truckers, pipeliners and producers are quickly adding infrastructure to get it to market. But new production from both the Permian is increasingly competing for refining capacity.

“We’re going to need to look at how we get more (Permian) barrels to Cushing or we’re going to look at the West Coast,” Jarrett Vick, president of oil-trucking operator Permian Transport & Trading, said in DUG Permian 2014 post-presentation Q&A session in Fort Worth in May. “I think the markets will determine that for us in the near future.”

Chris Keene, president and chief executive officer of Bakken rail operator Rangeland Energy LLC, said unit-train take-away is crucial in the western, Delaware Basin portion of the Permian Basin, which is more pipeline constrained than the eastern, Midland Basin portion.

“When did we realize it? Probably about a year ago, just in looking at the trends in production as well as in pipe capacity,” he said. Rangeland is building a unit-train loading facility near Loving, New Mexico, in the Delaware Basin, hauling oil out to Cushing and the Gulf Coast, while hauling proppant in.

“Rail has made crude oil a nationally traded commodity,” he said. “You seek out your highest-value market. Our markets are the East Coast, where you’re competing with Brent, and the West Coast, where you’re competing with ANS (Alaska North Slope oil) or foreign cargos.”

Texas’ production just four years ago was 1.13 million barrels a day; the U.S. Energy Information Administration estimates that, in March, it was 2.97 million a day. Meanwhile, New Mexico’s production has grown in the past four years from 179,000 barrels a day to 313,000.

New production from the Delaware Basin, which straddles the New Mexico/Texas border, may struggle for a market in the shadow of new Midland Basin, Eagle Ford and East Texas supply, Keene said. “If I were to have a crystal ball and look at it, I would say, ‘Okay, as you see more of this light, sweet production coming off the Eagle Ford and…in East Texas and in the Bakken, initially there is this bubble that is built. And as this new pipeline capacity gets built out of the Permian around Midland and Colorado City…you have the Delaware Basin sitting out there, saying, ‘Wait a minute. What about me?’

“So price-impact (risk) there is No. 1. And now you have the rail option. We’ve provided that.”

Darrel Koo, senior associate, energy research, for ITG Inc., said in an economics-panel Q&A session that he expects price pressure in the Gulf Coast and other U.S. oil markets, resulting in a widening differential among them, thus producers laying down rigs in the future. “There is probably a bit more room to go before we see very severe discounts.”

Raphael Hudson, director, upstream research, for Hart Energy, said, “There is a little bit of spare capacity in terms of the refining capability, even though there is a mix-match in terms of the crude quality.” New U.S. oil production is light-gravity while most U.S. refining capacity is weighted to processing heavy oil of less than 38 degrees. From the Eagle Ford, in particular, a great deal of production is super-light, 60-plus-degree-gravity condensate.

Scott Sheffield, chairman and chief executive officer of Pioneer Natural Resources Co. and who presented in the conference as well, estimates some 800,000 barrels—or roughly 10%—of current, daily, U.S. oil production is condensate.

Hudson said, “One possible relief valve would be condensate splitters. When you split the condensate—and a lot of this light oil would qualify as condensate—you are no longer dealing with an unrefined product so, therefore, it is exportable. That could relieve some pressure in the short term.”

Benjamin Shattuck, upstream analyst, Lower 48, for Wood Mackenzie, said some Permian operators will be well positioned to deal with a lower oil price. “Midland has been through boom/bust periods. Operators have not forgotten that…Operators now…are dialing down lease-operating expenses for that reason and trying to buy mineral rights to position themselves in a lower oil-price environment.”

Permian oil is mostly 40 degrees in gravity, Koo noted, “with exception, such as the western Delaware Basin, where the liquids are lighter. As Cimarex (Energy Co.) has indicated, they are probably 50- to 55-degree API, but that is a specific part of the basin. The rest is roughly 40 to 45 degrees.”

Koo said he and his ITG colleagues are “kind of in a $90 oil camp with the preface that there will be volatility, certainly in local hubs in the Lower 48. There is going to be some downside pressure in the Gulf Coast in the next year or so.”

Joel Castello, reserves and acquisitions manager, for Endeavor Energy Resources LP, which operates in both the Midland and Delaware basins, said, in a private-operator Q&A session, “I read the same things you all read…The world is what it is. You could have a global recession or wars that change the price…There are all kinds of risks out there.”

Kirk Blackim, director, business development, gathering and processing, for Crestwood Midstream Partners LP, said, “One of the things we’ve seen in the Marcellus area is, through the use of condensate stabilizers, we are driving off a lot of the light end so it ends up in the NGL products.

“But, given the current state of the refining industry and the ability to handle the heavier crudes and less light crude, there is only so much of that that the industry can tolerate.”

John Harpole, president of advisory firm Mercator Energy LLC, said a fellow markets analyst looked at the slate for the 138 oil refineries in North America to see if merely blending light oil with heavy oil will resolve the gridlock. “The entity that comes up on the short stick on that one is light, sweet crude,” he said. “We simply can’t blend enough.”

Rail operator Keene noted that condensate is “darn near an NGL (natural gas liquid) anyway.” The U.S. Commerce Department is considering an industry proposal that condensate no longer be defined as crude oil, of which the U.S. forbids meaningful export.

People are looking at potentially exporting condensate,” Keene noted. “And, people are looking at ‘Do you just have to split it and export the products?’ Do you split it (where it is being produced) and rail it out? Or do you rail the condensate down to a port at the Gulf Coast, split it there and export the products?”

Meanwhile, oil-quality concerns have developed among refiners who receive shipments via rail, Harpole said.

Keene concurred: “Crude quality is becoming the issue.” He worked, previously, for a refiner in its midstream business unit. “Refiners do not like condensate. You refine crudes for refining value. Eventually these crude streams get saturated.

“As a producer, you can no longer blend this condensate into the stream. In some cases, you try to dump it in. It finds its way into a truck or into a rail car and, ultimately, a ‘it hits the fan’ kind of thing…A lot of this condensate is going to be looking for a home…and purity of product continues to be important.”

Truck operator Vick said the company has to know exactly the gravity of what it puts into its trucks, since the product is then taken to a pipeline, which has rigid quality specifications. “We have to look at that because of the pipeline specs,” he said. “The pipelines are starting to penalize.”

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas, Oil and Gas Investor This Week, A&D Watch, Contact Nissa at

Oil-, Water-Production Data Difficult To Get For Permian Wells

June 4th, 2014 Nissa Darbonne | Comments Off

Darrel Koo: “…There isn’t a lot of transparency.”

Getting information about new Permian Basin wells has been complicated for both royalty-interest owners as well as for accomplished analysts. “The data-quality issues are certainly a concern in Texas,” Darrel Koo, senior associate, energy research, for ITG Inc., said in a DUG Permian Basin 2014 post-presentation Q&A session in Fort Worth in May.

“The biggest issue for me (is that) production in Texas is allocated to the lease level for oil wells. There may be 50 oil wells producing and Texas doesn’t tell you how much production is associated with each well. It’s difficult for an analyst to get type curves.”

One attendee said he is receiving royalty checks for wells that have been online for as many as nine months but there is no reported production. Koo said, “There are games that can be played. They don’t release those reports until after the wells have been producing for a long time…I can’t speak to when that will be resolved—if at all—but we certainly think it is an issue for people trying to analyze this (Permian) play.”

Determining water cut has been challenging as well, he added. “In Texas, unfortunately, the water-production data is not great. Operators are not obligated to report water-production data, so there isn’t a lot of transparency.” Water is indicated in completion reports, but “there is a lot of load water in that. You can’t say the formation is producing 70% water. That’s just not the case.”

The water cut is lower, however, than, for example, that which is produced from the Mississippi Lime play in Oklahoma, he added. There, he estimates water-disposal and other lease-operating expense is $10 to $11 per barrel. “In the Midland Basin, Concho (Resources Inc.) is operating at $6, $7, $8 on the average. Water is not materially affecting LOEs (there).”

For anecdotal reference, in the Delaware Basin, “we do have information from New Mexico on water-production data and some of the Wolfcamp wells there are 20% water cut, so it’s not that bad in our opinion.”

Benjamin Shattuck, upstream analyst, Lower 48, for Wood Mackenzie, said he doesn’t see a water-cut issue in the Midland Basin either but he expects water-sourcing to become a widespread problem. “Disposal has been problematic also.” Trucking it out is some $3 a barrel.

“You can do the math on that and see the value destruction pretty quickly, if you are putting in an SWD (saltwater-disposal well) per section at 25 or 50 cents per barrel. You begin to see a $1- to $1.5-million-per-well swing there.”

Raphael Hudson, director, upstream research, for Hart Energy, noted that operators are looking at recycling fracture-fluid water, using produced water and/or sourcing brackish water from San Juan Basin wells. “We believe there are ways around it, but there certainly is a problem. It is a constraint that needs to be addressed.”

Bob Manelis, general manager, Permian production unit, for BHP Billiton Ltd., said, in a separate Q&A session, that the company’s current Permian fracture-fluid recipe is 70% freshwater and 30% produced water. The company plans to eventually use 100% produced water.

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas, Oil and Gas Investor This Week, A&D Watch, Contact Nissa at

George Yates, Brigham, Endeavor On Permian Drilling, Cost, Capital

June 4th, 2014 Nissa Darbonne | Comments Off

George Yates: “…The payout is incredible…We project something like a one-year payout.”

The cost of converting a Permian Basin drilling program from vertical wells to horizontals is steep, particularly for a private operator, says George Yates, president of New Mexico-based Heyco Energy Group Inc. and a third-generation Permian driller. “It’s an oft-asked question,” he said in a DUG Permian 2014 post-presentation Q&A session in Fort Worth in May.

“Let me, first, say the industry has changed tremendously. This transition from a vertical program to a horizontal program is not an easy transition for every operator. It is technically challenging. It takes resources—the ability to execute organizationally. Operators have to make those commitments.

“And, it takes capital. In our case, we are going forward with our drilling program with internally available capital…At some point, we will consider other kinds of capital because the budget is pretty large. The good thing about that is that, today, there is a lot of capital available and a lot of choices of structure. We’re postponing that decision to help us make the right decision.”

Yates has seven horizontal wells in the company’s current drilling program—all targeting Bone Spring in the Delaware Basin. “I cannot tell you a budget number, but it is much more expensive than we are used to as a, primarily, vertical operator…

“(But) the payout is incredible. For our seven wells (to date), we project something like a one-year payout.”

Privately held Endeavor Energy Resources LP has a $550-million budget for 2014 for 107 wells among which 13 will be horizontal. “We’re still in the vertical mode, primarily,” Joel Castello, Endeavor reserves and acquisitions manager, said. “Our owner (35-year basin operator Autry Stephens) likes to use his own drilling company, Big Dog Drilling. We have only two rigs that are outfitted for horizontal drilling. We have committed to buy a walking rig and to upgrade one of our other rigs to drill horizontal wells.”

Both of its horizontal-capable rigs are drilling for it in the Delaware Basin where Endeavor has expiring leasehold, targeting Bone Spring and Wolfcamp in Reeves and Loving counties, Texas. Meanwhile, its verticals are traditional, stacked-pay Wolfberry wells.

Endeavor also has a newly minted agreement with ExxonMobil Corp. unit XTO Energy Inc. in which XTO is to gain operating equity in 34,000 gross Endeavor acres in the Midland Basin in Midland and Upton counties. In the deal, Endeavor will continue to operate its HBPed, shallow production; XTO will drill and operate horizontal wells in the Wolfcamp.

Also in the Delaware Basin, private operator Brigham Resources LP has three rigs drilling for it in Reeves and Pecos counties, Texas, with plans for roughly 25 gross wells this year. “So we have a lot on our plate,” said Gene Shepherd, chief executive officer who co-formed the company with Bud Brigham, both formerly chiefs of publicly held, Bakken-focused Brigham Exploration Co., which was sold in 2011 to Statoil ASA.

Shepherd said of access to capital these days, “Capital is out there and it is amazing, as a private company, the access to high-yield debt markets. When we (at Brigham Exploration) went into the downturn in 2008, if 100% of our debt capitalization had been banks, it would have been tough. But we had done a $125-million, high-yield offering. It’s a bullet maturity and there are no maintenance covenants, so it’s a great source of capital.

“There is a lot of availability, regardless. You don’t have to be public to have access—private-equity sponsors, mezzanine guys, the non-traditional debt markets, the term-loan markets. You have low interest rates and $100 commodity pricing.

“It’s as favorable as you can get.”

Castello noted that commercial lenders are pretty strict and redeterminations are every six months. “We found that the public, high-yield, debt market is pretty cheap money. Our last bond issue amounted to about 6% (interest). So, we’re generating a 50% internal rate of return on very low-geological-risk drilling and you can get money at 6%? That’s a cash machine.”

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas Investor,, Oil and Gas Investor This Week, A&D Watch, Contact Nissa at

As The Price Is Only Growing, Biggest Permian Buyers-To-Be Waiting For Softening

June 4th, 2014 Nissa Darbonne | Comments Off

Chris Simon: “The companies that are going to be successful (buyers) are those that are going to go beyond…the engineered valuation.”

It may seem unlikely that Permian Basin entry and bolt-on costs will decline, but the largest independents and the super-majors are holding out for this before sweeping in or consolidating, according to Chris Simon, managing director and co-head, A&D, for Raymond James & Associates Inc.

“Some of the larger companies I’ve talked to have thought the price of the play is a little steep, given the equity performance you’re seeing from some of these pure-play (stocks) and even some of the large independents,” Simon said in a DUG Permian 2014 post-presentation Q&A session in Fort Worth in May.

“Given where the forward oil curve is, perhaps they’re waiting in the wings to see if there is an equity correction—because we’re pretty fairly valued in the equity price. Our research group, which makes a lot of oil and gas calls, has been predicting some softness in oil prices for the last several years. It hasn’t happened because world events have interrupted some supply elsewhere and caused that prediction to get kicked down the road.

“They’re still predicting some softness next year. Will it happen? I tend to take the ‘over’ on it, personally. I don’t think the fundamentals are there for them to be in an immediate rush to that, but I think there is a real possibility in the medium term.”

Darrel Koo, senior associate, energy research, for ITG Inc., noted, in a Q&A session as part of a play-economics panel, “A lot of consolidation has already happened. There are a few elephants in the room. Endeavor (Energy Resources LP) is one of them. They own 500,000 net acres—essentially checkerboard with Pioneer (Natural Resources Co.) out there. It is one of the most attractive positions held by a private operator, but it is a large bite size, to say the least.”

There may be more room for consolidation in the Delaware Basin, rather than the Midland Basin. “It’s less known basin than the Midland.”

Striking deals with private operators—many of whom are multi-generation owners of leasehold HBPed by verticals in the basin’s conventional formations—will need to be creative, said Benjamin Shattuck, upstream analyst, Lower 48, for Wood Mackenzie. “The Endeavor/XTO (Energy Inc. deal) is a great example.”

In this, ExxonMobil Corp. unit XTO is to gain operating equity in 34,000 gross Endeavor acres in the Midland Basin in Midland and Upton counties. Endeavor will continue to operate its HBPed, shallow production; XTO will drill and operate horizontal wells in the Wolfcamp formation.

Shattuck said, “They were very savvy…to include only horizontal development of the Wolfcamp. You will find that throughout the Permian. Most of these legacy privates you are talking about have been in these families’ hands for generations now. The owners are very savvy and have been around the oil and gas block. They will want to monetize to the fullest what they can.

“Do we expect it to happen? Absolutely. Do we think it will be some sort of trend that emerges over the next year or so? Probably not. There is not an incentive for those companies for that right now.”

Raphael Hudson, director, upstream research, for Hart Energy, noted that private operators have other options as well, such as to IPO. “There have been several of these transactions. RSP Permian (Inc.), Athlon (Energy Inc.) and Diamondback (Energy Inc.’s plans to IPO a mineral-rights unit, Viper Energy Partners LP) are a few recent examples.

“Consolidation may not be the only way in which this sort of investor organization of the sector shapes up.”

Simon noted that many legacy, vertical operators lack experience with drilling horizontal wells that cost five times more and are a more challenging engineering feat. “They’re trying to make that decision as to whether they are going to develop it themselves. But they’re not that experienced and will have some learning curve. Do they JV? Or do they sell? It’s a decision as to what their corporate life is to be. I expect a number of them are going to sell.”

Amongst the largest, prospective, new-entrant buyers, such as super-majors, they will seek an operator that not only has Permian Basin bulk but also has a record of operational excellence. They may even be open to buying a non-pure-play operator, such as Pioneer or EOG Resources Inc., which have holdings and experience in other shale plays as well.

“They’re going to want to make a big entrance rather than buying a billion-dollar company, particularly if they don’t have the expertise,” Simon says. “We’ve seen that in the Bakken with the Statoil (ASA)/Brigham (Exploration Co.) deal. BHP (Billiton Ltd.) has gotten into the Eagle Ford and other places (via its purchase of Petrohawk Energy Corp.).

“We’ve seen those big steps. I think that’s more likely. Now, there could be consolidation among the small independents, private or public. But I think the equity market is a bit strong right now for them to get too aggressive on that.”

For Permian players, however, equity valuations only continue to grow. “Yes, but there comes an end. There will be a saturation. I think the IPO market is still very strong. There is one (Parsley Energy Inc.) active this week.” Parsley priced the following day at $18.50 a share in an oversubscribed 5-million-share offering. Shares were trading on June 4 at $24.92.

“Will you see some more IPOs coming out of the Permian? Probably. Will you see as many as we’ve seen already? Maybe not. Not every management team is ready for prime time, so not everyone has that option. And some management teams are ready for prime time but they don’t want to be a public company. It’s not always the path for groups of assets and management teams.”

A great deal of the equity market’s interest in owning a piece of the Permian is the basin’s stacked pay, he added.

“The companies that are going to be successful (buyers) are those that are going to go beyond the net asset valuation or the engineered valuation. I’m an engineer by background, so that kind of sends shivers up engineers’ spines in evaluating properties but (our research group says of the) stacked-pay nature of the Midland Basin, ‘Imagine the Eagle Ford with four additional Eagle Fords and that’s what you have in the Permian.’”

Pioneer chairman and chief executive officer Scott Sheffield, who presented earlier that morning, used a multiplier of 12 in estimating the hydrocarbon potential. Bob Reeves, Athlon president and CEO, who presented that morning as well, used a multiplier of eight to nine. “It’s hard to get your arms around that but we understand, on the road shows for these pure Permian players, that—when they talked about these net effective acres, where if they had 100,000 acres but they had four proven, potential benches in the Wolfcamp—the investor groups weren’t batting an eye.

“…If you’re going to look at it based on today’s reserves and performance, that’s one thing, but I think the real successful (buyers) are going to have the vision to see that this has great potential and (decide that) ‘If we’re going to compete here, we’re probably going to have to stretch a bit in an acquisition setting.’”

Gene, CEO of Brigham Resources LP, which has put together leasehold in the Delaware Basin, said in a Q&A session among fellow private-operator presenters, “There are other ways to compete.”

Among what Brigham brings to the bargaining table, in addition to its deep Bakken experience, is that it’s ready to drill, he said. “We are operating (as a start-up to date) from a relatively low level of activity so, if you want to see your acreage developed quickly, we can bring rigs in immediately…

“With one of the bigger companies, who knows when that acreage gets developed? In a lot of instances, a lease bonus of $30,000 is a lot but so is 25% of that future revenue stream.

“We can tell a lessor that we will bring the rig immediately. That is one way we attempt to level the playing field.”

–Nissa Darbonne, Author, The American Shales; Editor-at-Large, Oil and Gas Investor,, Oil and Gas Investor This Week, A&D Watch, Contact Nissa at