OGJ Newsletter

Feb. 11, 2013
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Oxy reports impairment charge on gas assets

Occidental Petroleum Corp. reported a $1.1 billion aftertax charge in the fourth quarter 2012, largely for impairments in its Midcontinent natural gas assets, executives announced during an earnings call on Jan. 31.

Cynthia Walker, Oxy chief financial officer, said more than 90% of the impairments were related to gas properties acquired more than 4 years ago on average.

"While the performance of the properties was generally as expected, natural gas prices have declined by approximately 50% since the acquisitions," Walker said. "Also in 2012, natural gas prices and NGL prices used for reserve calculations were significantly lower than prices used in 2011, resulting in declines in economically feasible reserves in these properties."

Oxy, based in Los Angeles, plans a $9.6 billion budget for 2013, down nearly 6% from 2012. But Chief Executive Officer Stephen Chazen said the company expects to boost US oil production by 8-10% for 2013 compared with 2012.

Executives said the company's goal for 2013 is to reduce US drilling costs by 15% compared with 2012. Oxy expects its US rig count will average 55 rigs during 2013 compared with 64 rigs during 2012.

Bill Albrecht, Oxy president of US oil and gas operations, said the company expects to average 25-27 rigs in the Permian basin with one third of that program devoted to the Wolfberry play.

"Only about 15-20% or so of our wells in the Permian are going to be true horizontals," Albrecht said. "Now, having said that, we do drill a number of highly deviated wells, but those are still not horizontals. It is only in certain specific limited plays where we are drilling horizontal wells."

Chazen said Oxy continues to drill at a moderate rate in the Bakken formation as part of the company's overall plan to be conservative on spending.

Chesapeake outlines plan for McClendon's exit

Chesapeake Energy Corp. reported a succession plan for outgoing Chief Executive Officer and Pres. Aubrey McClendon, who will leave the Oklahoma City independent effective Apr. 1.

Mclendon has been CEO since the company's inception in 1989 and drove Chesapeake to become one of the largest E&P firms in North America. His career has been tarnished though with allegations of inappropriate behavior including running an energy-focused hedge fund from Chesapeake's offices and personally borrowing $1.3 billion from the company's business partners.

"Over the past 24 years, [McClendon] has created one of the most valuable and innovative companies in the energy industry," said Chesapeake Chairman Archie W. Dunham. "Under Aubrey's strong leadership," Dunham said, "Chesapeake has built an unmatched portfolio of natural gas and oil assets in creating one of the world's leading energy companies."

Dunham continued, "However, as the company moves towards more fully developing the value of its outstanding assets, Chesapeake is at an important transition in its history and Aubrey and the board of directors have agreed that the time has come for the company to select a new leader. The board will be working collaboratively with Aubrey to make a smooth transition to Chesapeake's next chief executive officer."

During this interim period, McClendon will work closely with Steven C. Dixon, chief operating officer, and Domenic J. Dell'Osso, Jr., chief financial officer, to transition certain day-to-day management responsibilities in advance of the completion of the search process for the new chief executive officer. The company and the board are committed to its current drilling program with respect to its existing $6 billion drilling and completion budget for 2013, its ongoing asset sales program and intention to reduce the company's long-term debt.

Last year, Chesapeake announced multiple agreements to sell most of its Permian properties, substantially all of its midstream assets, and certain noncore leasehold for total net proceeds of $6.9 billion (OGJ Online, Sept. 17, 2012).

McClendon will resign from the board at the time his successor is appointed and will receive his full compensation and other benefits to which he is entitled in accordance with the terms of his employment agreement. McClendon will continue to be an important partner with the company given his stock ownership as well as his interests in certain of the company's wells in connection with the Founder Well Participation Program, which will terminate on June 30, 2014.

Caerus to buy PDC Energy's noncore gas assets

Caerus Oil & Gas LLC plans to buy what PDC Energy Inc. considers its noncore Colorado natural gas assets for $200 million.

The assets being sold are in northwest Colorado's Piceance basin and northeastern Colorado. The transaction is expected to close during the second quarter, with a Jan. 1 effective date.

Assets being sold are 99% natural gas and include an estimated 85 bcf equivalent of net proved developed producing reserves as of Dec. 31, 2012. Production is 42 MMcfd net to PDC Energy.

James Trimble, PDC Energy president and chief executive officer, said proceeds from the divestiture will enable the Denver independent to accelerate its Wattenberg field and Utica shale horizontal drilling

PDC Energy's holdings in Wattenberg field include the horizontal Niobrara and Codell plays. It also has assets in the Utica Shale in Ohio and the Marcellus shale in West Virginia.

PDC Energy formerly was known as Petroleum Development Corp.

BP appoints Townshend as senior vice-president

BP PLC has appointed Michael Townshend as senior vice-president, BP Russia, effective Mar. 1. Currently Townshend serves as BP regional president, Iraq.

Townshend has 32 years of experience with BP working across a wide range of upstream locations and projects including Azerbaijan, Indonesia, Australia, the US, and the Middle East.

The appointment follows the decision of the current head of BP Russia, David Peattie, to leave BP at the end of February.

Exploration & DevelopmentQuick Takes

Barrett writes down Rockies gas values

Bill Barrett Corp., Denver, has built its production mix the past 2 years to 24% oil at the end of 2012, a year during which it wrote down natural gas reserves values and ceased gas drilling in two Rocky Mountain basins.

Bill Barrett said it stopped gas drilling at West Tavaputs in the Uinta basin and Gibson Gulch in the Piceance basin in Colorado in the 2012 second and third quarters, respectively, as a result of low natural gas and natural gas liquids prices and expects not to drill in either area in 2013.

A capital program of $475-525 million in 2013, 90% of which is oil-directed, includes running six rigs in the Uinta and Denver basins and includes 180 gross-100 net wells. The $963 million in 2012 capital spending included drilling 288 gross-185 net wells.

Yearend estimated proved reserves were 1.04 tcf equivalent, 29% oil and 59% developed. The reserves reflect 74% growth in proved reserves at the company's active oil programs in the Uinta, Denver, and Powder River basins and gas drilling additions at West Tavaputs and Gibson Gulch.

Negative engineering revisions at West Tavaputs resulted from performance of 20-acre spacing on part of the company's acreage.

January 2013 production is an estimated 220 MMcfd of gas equivalent, 22% oil, 70% gas, and 8% NGL. Total 2012 production was up 10% on the year as oil production rose 80%, and the number of drilling locations targeting oil increased to nearly 2,900 from 400.

Oil rate rising at Tuscaloosa marine shale well

A group led by Encana Corp. has observed an improvement in the oil production rate from a horizontal Tuscaloosa marine shale well in Wilkinson County, Miss.

The Crosby 12-H1 well continues to improve with a current production rate of 1,250 b/d of oil equivalent and a 24-hr average of 1,130 boe/d, comprised of 1,050 b/d of oil and 469 Mcfd of gas with 2,700 psi pressure on a 15/64-in. choke, said Goodrich Petroleum Corp., Houston.

The well, which has recovered about 1% of its frac fluid, has 6,700 ft of usable lateral with 25 frac stages.

Encana and Contango Oil & Gas Co. each has a 25% working interest in the well, and Goodrich has 50%.

Goodrich is also participating in the Anderson 17H-2 drilling well with a 7% non-operated working interest. Goodrich plans to spud its next operated TMS well, the Smith 5-29H-1, in the second quarter. The Ash 31H-1 and Ash 31H-2 wells, in which the company has a 12% nonoperated working interest, are expected to be completed in February.

Goodrich has 135,000 net acres in the play and now expects to spend the higher end of its previously announced 2013 capital budget in the TMS of $50 million.

Second Mafumeira development phase okayed

Cabinda Gulf Oil Co. Ltd., a subsidiary of Chevron Corp., will develop the Mafumeira Sul project offshore Angola targeting peak production of 110,000 b/d of crude oil and 10,000 b/d of LPG.

The project, 15 miles offshore in 200 ft of water, is the second stage of development of Mafumeira field on Block 0. The Mafumeira Norte project went online in 2009 and now produces 40,000 b/d of oil (OGJ Online, July 2, 2009).

The $5.6 billion Mafumeira Sul project comprises 50 wells, two wellhead platforms, and a central processing and compression facility. It will require the laying of 75 miles of subsea pipeline.

Production will begin in 2015. Associated natural gas will feed the Angola LNG plant in Soyo.

Cabinda Gulf, operator, holds a 39.2% interest in Mafumeira Sul. Other interests are Sonangol EP 41%, Total 10%, and Eni 9.8%.

Eni group has Western Desert oil discovery

A group led by a subsidiary of Eni SPA has made a third light oil discovery in Egypt's Western Desert on the Meleiha concession, where oil production is rising and considerable exploratory potential is said to remain.

An exploratory well on the Rosa North deep prospect encountered a combined 80 m of oil pay in multiple sandstone reservoirs at more than 2,200 m and flowed at commercial rates, said participant Lukoil Overseas.

The group will drill at least two development wells this year, and each well is expected to go on line at 2,000 b/d, Lukoil said.

Rosa North follows the group's 2010 Arcadia discovery and 2012 Emry Deep find. Meleiha produced 1.2 million tons of oil in 2012, and the group has shot and interpreted 3D seismic on the block.

Eni's International Egyptian Oil Co. has 56% interest in Meleiha, Lukoil Overseas 24%, and Mitsui & Co. 20%.

Condor finds oil, gas on Precaspian block

Condor Petroleum Inc., Calgary, said its Kiyaktysai KN-E-201 well at the Zharkamys West 1 Territory in the Precaspian basin in Kazakhstan is an oil and gas discovery, having encountered a 136-m stacked sand-shale interval while drilling to an intermediate casing depth of 1,408 m.

Based on wireline logs, the interval has 58 m of net hydrocarbon pay consisting of a continuous 41-m light oil column and a separate 17-m gas column. An oil-water contact has not been penetrated.

Intermediate casing is being set to isolate the upper 58 m of pay intervals from a higher-pressured oil zone encountered at 1,400 m prior to drilling ahead to a total depth of 2,000 m.

Condor has a 100% interest in the exploration rights to the 2,610 sq km Zharkamys Territory.

Drilling & ProductionQuick Takes

Ghana's Jubilee field sets oil production record

Jubilee field offshore Ghana was producing 110,000 b/d of oil at the end of 2012 and recently set a new record of 112,500 b/d following two acid stimulations and the start-up of two new Phase 1A wells, said Anadarko Petroleum Corp.

The field, operated by Tullow Oil PLC, averaged more than 88,000 b/d in the last quarter of 2012, Anadarko said. Jubilee came on production in November 2010.

The Tullow-operated partnership that holds the Deepwater Tano block submitted a development plan for the Tweneboa, Enyenra, and Ntomme field complex northwest of Jubilee to Ghana's government in the 2012 fourth quarter.

The Sapele exploratory well is drilling southwest of the Jubilee Unit, and results are expected in the first quarter of 2013, Anadarko said. Appraisal work on the Wawa discovery is also planned for 2013 (OGJ Online, July 18, 2012).

Meanwhile, the Okure-1 exploratory well was deemed noncommercial and has been plugged and abandoned.

Brownfield allowance helps Thistle renewal

EnQuest PLC, London, has received a brownfield tax allowance to support redevelopment of Thistle oil field in the northern UK North Sea.

The allowance, which EnQuest said is among the first offered by the UK government, is part of a package of measures implemented last year to support offshore investment after a 2011 increase in tax rates on oil and gas producers (OGJ Online, July 5, 2011).

Enquest, formed in 2010 from UK North Sea assets of Petrofac Ltd. and Lundin Petroleum, is revitalizing the 60-slot steel Thistle platform, which handles production from Thistle and Deveron oil fields (OGJ Online, Mar. 10, 2010).

It says a 2007 seismic program identified attic oil and other potential in the highly faulted, multilayer field.

The company expects to increase recovery by 35 million boe and extend field life to 2025 or beyond by increasing water injection volumes and drilling new targets.

In 2011, EnQuest began installing electric submersible pumps in four wells and new power supply on the platform.

The company has refurbished and reactivated the platform's drilling rig is upgrading topsides and the steel jacket, which was installed in 524 ft of water 275 miles northeast of Aberdeen in 1976.

Thistle produces light, low-sulfur oil with a low GOR. Production moves by pipeline to the Dunlin and Cormorant platforms, then to the Sullom Voe terminal in the Shetland Islands.

According to government data, Thistle produced an average 26,349 cu m/month of oil through October last year. Its peak production year was 1982 at 598,635 cu m/month.

EnQuest holds a 99% interest in Thistle and Britoil Ltd., 1%.

Imperial commissioning Kearl oil sands mine

Imperial Oil has begun commissioning its initial Kearl oil sands mining development in the northern Athabasca region of Alberta and expects production of diluted bitumen from the first froth-treatment train to begin this quarter (OGJ Online, Jan. 19, 2012). Production will ramp up to 110,000 b/d of bitumen over several months.

Cost of the initial development is expected to be $12.9 billion (Can.).

An $8.9-billion expansion project sanctioned in 2011 will boost production by a further 110,000 b/d.

Imperial said the combined projects will develop 3.2 billion bbl of bitumen at a cost of about $6.80/bbl, an increase from $6.20/bbl estimated earlier.

The higher cost reflects resequencing of work related to module transportation and an early onset of winter and harsh weather during start-up. Imperial said permitting and regulatory issues related to module transportation in the US required nearly 2 years to settle.

Eni, Sonatrach start up MLE natural gas field

Eni SPA and state-owned Sonatrach have started production of rich natural gas from Menzel Ledjmet East (MLE) field on Algerian Block 405b, about 1,000 km from Algiers.

A plant at the field yields 9 million cu m/day of sales gas, 15,000 b/d of oil and condensate, and 12,000 b/d of LPG.

Eni and Sonatrach jointly operate MLE field.

The Italian company acquired its interest in the Berkine basin field through its 2008 acquisition of First Calgary Petroleum, which held a 75% stake (OGJ Online, Sept. 9, 2008).

PROCESSINGQuick Takes

Marathon completes BP refinery purchase

Marathon Petroleum Corp. has completed its purchase of BP's 451,000-b/cd refinery at Texas City, Tex., and will rename it Galveston Bay Refinery (OGJ Online, Oct. 8, 2012).

The purchase price includes $598,000 cash, $1.1 billion for hydrocarbon inventory, and an earn-out payable over 6 years of $700,000 based on assumed future margins and throughput.

In addition to the high-conversion refinery, Marathon Petroleum acquires a 1,040-Mw cogeneration facility, four light product terminals in the US Southeast, retail marketing contract assignments for 1,200 branded sites selling 61,000 b/d of gasoline, three intrastate natural gas liquids pipelines originating at the refinery, and a 50,000 b/d allocation of BP's Colonial Pipeline Co. shipper history.

Williams lets contract for Canadian PDH plant

Williams Cos., Tulsa, has awarded a preliminary engineering contract for its proposed Canadian propane dehydrogenation (PDH) plant to Fluor Corp., Irving, Tex.

The plant under study would be near Redwater, Alta. It would use propane recovered from Williams's fractionator there and convert it into polymer-grade propylene.

Williams announced last year it was considering the plant (OGJ Online, July 20, 2012). At that time, Williams said the PDH unit would have a capacity of about 1 billion lb/year and cost $600-800 million.

TRANSPORTATIONQuick Takes

Genesis Energy plans Louisiana pipeline

Genesis Energy LP plans to build an 18-mile, 20-in. OD crude oil pipeline connecting its existing Port Hudson, La., terminal to ExxonMobil Corp.'s 500,000-b/d Baton Rouge refinery via the Maryland terminal and Anchorage tank farm. The 350,000-b/d pipeline will also access other local refineries with capacity totaling 140,000 b/d.

The company also plans to build a crude oil unit train terminal at the Baton Rouge Maryland site. At Port Hudson, Genesis will build 200,000 bbl of storage, complementing its 216,000 bbl of existing capacity, and improve its barge dock and truck station.

Genesis plans to begin construction early this year, with Port Hudson upgrades and the crude oil pipeline expected to be completed by yearend and the Maryland unit train terminal to enter service second-quarter 2014. Genesis will spend about $125 million on the projects.

The company is a 50-50 partner with Enterprise Products Partners LP in the Southeast Keathley Canyon Pipeline Co. LLC, expected to transport 115,000 b/d of crude oil from the deepwater offshore Gulf of Mexico Lucius development by mid-2014 (OGJ Online, Jan. 4, 2012).

Magellan to add crude services at Galena Park

Magellan Midstream Partners LP plans to build a pipeline and terminal system at its Galena Park, Tex., terminal to deliver crude from its pipeline system to refineries in Houston and Texas City. Magellan's Galena Park terminal currently handles refined products.

The company expects the $50-million project to enter service by mid-2014, supported by long-term committed volumes.

Blueknight Energy Partners LP earlier this week agreed to buy 30% of the Pecos River crude oil pipeline project, which will deliver into Houston via Magellan's Longhorn Pipeline (OGJ Online, Feb. 5, 2013). Magellan's Galena Park products terminal has 117 tanks with total storage of rough 12.5-million bbl.

Blueknight buys into Pecos River crude pipeline

Blueknight Energy Partners LP (BKEP) has agreed with Advantage Pipeline LLC to acquire 30% ownership in the 70-mile Pecos River crude oil pipeline from Pecos, Tex., to Crane, Tex. The 16-in. OD pipeline will allow West Texas producers to deliver to Gulf Coast markets through a connection to Magellan Midstream Partners LP's Longhorn Pipeline at Crane.

BKEP will operate the pipeline under a long-term agreement with Advantage. Advantage said construction will begin promptly with initial service expected by end-May.

Magellan Midstream announced it was proceeding with the conversion to crude service and reversal of the Crane-to-Houston segment of Longhorn in 2011. Initial capacity is 135,000 b/d, expandable to 225,000 b/d if demand warrants (OGJ Online, Feb. 22, 2012).

DOE approves FTA status for Pangea LNG

Pangea LNG (North America) Holdings LLC has received authorization form the US Department of Energy to export LNG to free-trade-agreement (FTA) nations from its planned South Texas LNG Project being developed on Corpus Christi Bay.

Pangea LNG will be authorized to export as much as 8 million tonnes/year from US gas fields for 25 years beginning on the date of its first export. Pangea LNG has also filed with DOE to export LNG to non-FTA countries; that application is pending.

The terminal is planned for a 550-acre complex on the 45-ft deep La Quinta Ship Channel. South Texas LNG is subject to federal, state, and local regulatory approvals, the company said, with the US Federal Energy Regulatory Commission acting as lead agency.

The company said it will begin the FERC pre-filing process by this year's second quarter and expects the project to be in operation by at least 2018.