Devon to sell all GoM, international assets; claims highest rate Haynesville Shale well
Devon Energy Corp. has a plan to position itself as a high-growth North American onshore company. The company intends to sell all of its Gulf of Mexico and international assets and use the proceeds to further its US and Canadian onshore portfolio and to retire debt.
J. Larry Nichols, chairman and CEO of Devon noted, "We do not believe that the value of our high-quality Gulf and international assets is being adequately reflected in our stock price. By monetizing these assets, we will realize their full value, allowing us to unleash the growth potential that resides within our world-class onshore assets."
While the company believes the value of its Gulf and international assets may not be adequately reflected, it is betting that the value of its onshore assets will be. A recent drilling effort in the Hayneville Shale offers support. The well in San Augustine County, Tex, The Kardell Gas Unit 1H, was drilled to roughly 18,350 feet, including a horizontal lateral section of roughly 4,500 feet.
"With a flow rate of more than 30 million cubic feet per day, we believe the Kardell well is the highest rate well ever drilled in the Haynesville Shale. said David A. Hager, executive vice president of exploration and production. "We plan to go to a five-rig program in 2010 in this southern play area," he continued.
Devon operates the well with a 48% working interest. Crimson Exploration Inc. owns the remaining 52% working interest.
Devon's southern Haynesville Shale acreage comprises 47,000 net acres principally located in the Texas counties of San Augustine and Sabine and in Sabine Parish, Louisiana. Devon holds a 100% interest in its primary term leases in the southern area.
Devon holds approximately 570,000 net acres in the greater Haynesville trend of east Texas and north Louisiana.
Redeploying sale proceeds
According to Pritchard Capital Partners, approximately 30% of the company's CAPEX is currently allocated to Gulf of Mexico (largely fixed capital commitments) and other international assets, while the estimated growth rate in those regions for 2009 is negative 3%. By selling these negative growth assets and redeploying the proceeds into onshore North America, which has a 2009 estimated growth rate of 9%, the company reduces fixed costs and accelerates working growth assets.
The company expects the divestiture process to begin in the first quarter of 2010, be completed by year-end, and believes the sale could generate after-tax proceeds of $4.5 billion to $7.5 billion.
Devon drills for natural gas in the Big George coal formation in northeastern Wyoming. The Big George is one of several coalbed natural gas fields in the Powder River Basin. Photo courtesy of Devon Energy Corp.
Devon expects to spend roughly $2.1 billion of the proceeds over the course of 2010 and 2011 on North American development in order to achieve a CAGR of 10% in 2010 and 2011. By 2012, the company expects to generate a 10% CAGR funded entirely through internal cash flows. On a per share debt-adjusted growth metric, the company believes it will achieve a 12% compound annual growth rate. Previous estimates by Pritchard Capital put Devon's 2009-2010 debt-adjusted compound growth rate at 2.3% (using closing prices from Oct 26, 2009).
The company has said it plans to double its 2009 drilling in 2010 with 80 wells, ramp the rig count from 10 to 18 by 2014, and exit 2014 at 400 MMcfe/d.
Asset balance, outlook
Based on estimated year-end 2009 proved reserves, Devon's Gulf of Mexico and international properties account for roughly 7% of the company's proved reserves of 2.8 billion barrels of oil equivalent.
Oil and natural gas liquids account for nearly 43% of company-wide estimated proved reserves at year-end 2009. Pro forma for the divestiture of the Gulf of Mexico and international assets, oil and natural gas liquids account for 41% of the total. The company's overall balance between liquids and natural gas will change only slightly following the divestiture.
Standard & Poor's Ratings Services said the sale will not affect the company's ratings or outlook (BBB+/Stable/--). While the company's plans to accelerate capital spending in North America, likely outstripping internationally generated cash flow and increasing debt in 2010, S&P believes there is "additional room for higher debt levels at the current rating," and "assuming the asset sales are consummated, debt should fall below current levels."
— Mikaila Adams
Apache's Hostetter #1-23H well producing 17 MMcf, 800 b/d; 3Q production exceeds 600,000 boe/d
Houston-based Apache Corp. has today announced that the Hostetter #1-23H well located in Washita County, Okla., is producing 17 million cubic feet (MMcf) of gas and 800 barrels of liquid hydrocarbons per day.
The Hostetter #1-23H is Apache's first operated horizontal well in the Granite Wash play. The well was drilled to a depth of 12,500 feet with a 4,000-foot horizontal section and eight separate fracture-stimulation stages. Apache owns a 72% working interest in the well.
"Apache controls more than 200,000 acres across the play, primarily held by production," said Rob Johnston, Apache's Central Region vice president.
"Apache has drilled hundreds of vertical wells across the play, and horizontal drilling technology has unlocked hundreds of additional opportunities on Apache's acreage," he said.
By year-end, the company will operate four horizontal drilling rigs in the immediate area and plans to drill more than 20 horizontal Granite Wash wells in 2010.
Recently, the company reported that for the first time average worldwide production surpassed 600,000 boe/d during the third quarter, increasing 3.4% from the second quarter and 19% from the prior-year period.
"Apache's regional growth drivers put the company on track for record production and solid financial results in 2009, and we will enter 2010 with strong momentum, including two development projects in Australia that should add 40,000 barrels of oil per day to worldwide output when they commence operations in the first half," said G. Steven Farris, chairman and CEO.
In Australia, the Ningaloo Vision floating production, storage and offloading vessel is expected to arrive at the Van Gogh field in the Exmouth Basin in November, with first production expected in early 2010. Van Gogh is projected to add 20,000 barrels per day to Apache's annual net oil production.
Pyrenees, a second oil project in the Exmouth Basin, is projected to begin ramping up to 20,000 barrels per day (net) during the first half.
The company produced 607,118 boe per day 3Q09. Liquid hydrocarbons production averaged 297,997 b/d, up 2% from 2Q. Gas production averaged 1.85 billion cubic feet per day, up 5% from the second quarter.
Apache reported net income of $441 million, or $1.30 per diluted common share, compared with $1.2 billion, or $3.52 per share, in the prior-year period.
Apache's 3Q adjusted earnings, which exclude certain items that impact the comparability of operating results, totaled $534 million, or $1.58 per share, compared to adjusted earnings of $1.1 billion, or $3.19 per share, in the prior-year period. Apache had roughly $1.4 billion in cash at the end of 3Q09. Debt was 24.7% of total capitalization.
W&T begins Daniel Boone production
W&T Offshore Inc. has begun production from its Daniel Boone discovery well, a deepwater development in the Gulf of Mexico within Green Canyon Block 646.
Daniel Boone lies in water depths of roughly 4,230 feet about 120 miles from the Louisiana coast. The discovery well has current gross daily production of nearly 6,000 barrels of oil and 5,700 thousand cubic feet of natural gas per day, or 6,950 barrels of oil equivalent per day. The well is connected via a 22-mile subsea tieback to a third-party operated platform in Green Canyon Block 338. Sales commenced September 28, 2009.
W&T holds a 60% working interest and operates the Daniel Boone field. Mariner Energy Inc. holds the remaining 40% working interest.
For C$250, ExxonMobil, Imperial buy oil sands assets from UTS
Calgary-based UTS Energy Corp. (UTS) has sold its 50% working interest in Alberta Oil Sands Lease Nos. 421, 022 and 023 located east of the Firebag River in north-eastern Alberta to Imperial Oil and ExxonMobil for C$250 million.
Lease 421 was acquired in a land sale in late 2006. Based on five holes drilled in early 2008, the two adjacent leases (Leases 022 and 023) were purchased. By the end of the 2008/2009 winter season, the total number of core holes drilled in the combined area was 59. An area equivalent to 24 sections was found to be prospective; however, insufficient drilling has been completed to fully determine the resource potential in the area.
UTS anticipates that the estimated after-tax proceeds will be C$200 million. The company holds an estimated C$440 million in cash and cash equivalents. The company is also owed C$695 million remaining earn-in by Teck and Suncor on the Fort Hills Project.
The Lease 421 divestiture marks the end of the formal value maximization process started in January of 2009 in response to the hostile takeover bid launched by Total E&P Canada Ltd.
RBC Capital Markets and TD Securities Inc. acted as financial advisors to UTS on the transaction. Blake, Cassels & Graydon LLP acted as legal counsel to UTS.
Triple Diamond Energy confirms Wilcox Sand discovery in Oklahoma
Triple Diamond Energy Corp. made a Wilcox Sand discovery in its prospect acreage located just north of the Central Oklahoma Oil Platform in Seminole County, Okla. The Overlook #14-1 was drilled to approximately 4,563 feet.
Electric wireline logging and mud logging sample shows indicate the Overlook #14-1 well encountered significant hydrocarbon pay in the Wilcox Sand formation.
Triple Diamond Energy holds acreage to the west of the discovery well location and has options to acquire additional acreage to the north and south, resulting in the possibility for a contiguous acreage block, noted Chris Jent, president of Triple Diamond Energy.
The company's geological consultant, American Natural Resources, estimates 2.6 million barrels of recoverable reserves within the 560 acre closure. Triple Diamond Energy's operating company, O&G Well Service LLC has plans to initiate development of the newly discovered field and plans to drill the Overlook #14-2 and Overlook #14-3 before the end of the year.
Microsoft joins Energistics to drive oil, gas industry standardization
Microsoft Corp. has teamed up with Energistics. Microsoft, along with its ecosystem of partners, has experience in bringing technologies and solutions to the mainstream oil and gas industry. This expertise will be used to deliver the reference implementation of Energistics' standards such as the Wellsite Information Transfer Standard Markup Language (WITSML) and Production Markup Language (PRODML), enabling oil and gas companies to increase the implementation of standards while lowering adoption hurdles.
Energistics' founding objective was to unite the oil and gas industry and foster an environment of collaboration.
"[E&P]Companies that can help facilitate the development and deployment of open data exchange standards such as PRODML will play a vital role in ensuring the industry can maximize potential cost savings," said Catherine Madden, senior research analyst at IDC Energy Insights.
Albrecht "Ali" Ferling, Ph.D., managing director, Worldwide Oil and Gas Industries at Microsoft. "By helping the industry adopt standards, Microsoft believes the industry can drive down cost by improving interoperability and building a platform for collaboration and communication."
Questar begins drilling at Johnson Bottoms unit, reports slight increase in overall production in 3Q09
Pacific Energy & Mining Co., along with Questar Corp. subsidiary Questar Exploration and Production, commenced horizontal drilling of the initial well at the newly-unitized Johnson Bottoms Unit in early November. The well is located in Section 22, 7 South 21 East, Uintah County, Utah.
Questar E&P serves as operator of the unit. The target zone is the H4 member of the Greenriver formation at an approximate depth of 7,000 ft. There are six permitted wells on the unit at an approximate cost of $2.5 million each.
Questar E&P EBITDA in 3Q09 declined 23% compared to the 2008 quarter due primarily to a 15% decrease in realized natural gas prices and a 40% decrease in realized oil and natural gas liquids prices.
Reflecting continued voluntary curtailments, Questar E&P 3Q production was 43.8 bcfe, compared to 45.3 bcfe in 3Q08 and 43.4 bcfe in 2Q09.
An independent review dated June 2008 shows Questar holds probable reserves of 919 bcfe, 1,843 bcfe of probable reserves, and a resource potential of 7,968 bcfe in the Uinta Basin.
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