GENERAL INTEREST — Quick Takes
Chesapeake to sell assets in US shale plays
Chesapeake Energy Corp. plans to sell midstream assets in the Marcellus, Utica, Eagle Ford, Haynesville, and Niobrara to Access Midstream Partners for $2.16 billion in a transaction expected to close by Dec. 31.
The announcement is the latest in a series for ongoing divestitures for Chesapeake, which has faced financial, governance, and legal questions. The Oklahoma City-based independent previously said it seeks to cut its $14.3 billion in long-term debt to $9.5 billion (OGJ Online, Aug. 13, 2012).
Chesapeake also sold midstream assets in Texas and Oklahoma for $175 million.
Chesapeake anticipates completing the sale of its remaining midstream assets, including Midcontinent and other assets, by the end of the 2013 first quarter for $425 million.
Total proceeds from Chesapeake's midstream exit are expected to reach nearly $4.9 billion when all the announced deals have been finalized.
Rosneft finalizes plans to buy stake in TNK-BP
OAO Rosneft finalized plans to buy a 50% stake in TNK-BP from the AAR Consortium (Alfa Group, Access Industries, and Renova Group) for $28 billion as outlined in a previously announced agreement in principle.
Separately, Rosneft recently finalized plans with BP PLC for Rosneft to buy the other half of the Russian oil venture in cash and stock in a deal similar to the AAR pact. BP will own nearly 20% interest in Rosneft and have two representatives on the board (OGJ Online, Nov. 26, 2012). Closing of Rosneft's acquisition from AAR, subject to approvals from Russian and European antitrust regulators, is expected during first-half 2013. Rosneft Pres. Igor Sechin said his company planned to begin the integration process as soon as possible.
German Khan, member of the Alfa Group supervisory board and TNK-BP executive director, said the transaction is expected to boosts Russian economy potential and reflect "Russia's leading role on the global oil and gas industry."
Alaska governor discussing gas exports to Asia
Alaska Gov. Sean Parnell discussed the possible export of natural gas from Alaska to Asia during a Dec. 10 meeting in Juneau with Korea Gas Corp.'s Chief Executive Kangsoo Choo. Parnell said he has scheduled meetings with other potential buyers of Alaska gas.
A consortium of energy companies plans to build a $45 billion pipeline to move gas from Alaska's North Slope via the proposed Alaska Pipeline Project to a port on the southern coast, where gas would be processed at a proposed liquefaction plant and sent to Asia via LNG vessels.
ExxonMobil Corp., ConocoPhillips, BP PLC, and TransCanada Corp. have been in communication with Parnell's office about their plans. The companies say they are working within a framework set out by the Alaska Gasline Inducement Act.
Parnell considers getting Alaska's gas produced and sent to markets as one of the state's top priorities.
"These efforts are critical because an Alaska project must compete with other large-scale LNG projects under development around the world," the governor said.
UK decommissioning relief details welcomed
Oil & Gas UK welcomed publication by the UK Treasury of details of agreements between the government and oil and gas operators covering tax relief for decommissioning offshore facilities.
The possibility of limits on deductibility of decommissioning costs arose in a tax increase announced early in 2011 and was a major point of industry criticism of the move (OGJ Online, Mar. 25, 2011).
Since then, the government has taken steps to restore incentives for oil and gas development in mature and challenging areas and in a budget announcement last March committed to restoring certainty about decommissioning relief (OGJ Online, Mar. 23, 2011).
Mike Tholen, Oil & Gas UK economics and commercial director, said the newly published details on decommissioning will help operators make investment decisions.
"Long-term certainty on decommissioning relief will, at no cost to government, facilitate the sale of assets to companies most suited to invest in them, provide renewed confidence for late life investment by current and new owners, and liberate new funds for use in extending the productive lives of many mature fields," he said.
Exploration & Development — Quick Takes
Hess finds oil with deepwater Pecan well
Hess Corp. reported the Pecan-1 exploratory well offshore Ghana found an estimated 245 net ft of oil pay in two separate Turonian intervals. Hess filed a notice of discovery with the minister of energy for the well, which went to total depth of 15,420 ft in 8,245 ft of water on the Deepwater Tano-Cape Three Points license.
Hess said an extensive data acquisition program was undertaken and the well was sidetracked to obtain bypass cores. The well is now being suspended. Hess is license operator with 90% interest, and Ghana National Petroleum Corp. has 10%.
Pecan-1 is the company's fifth discovery on the license and follows the previously reported discoveries at Almond (53 net ft oil pay), Beech (146 net ft oil pay), Hickory North (98 net ft gas-condensate pay), and Paradise (120 net ft oil pay and 295 net ft gas-condensate pay), the company said.
Hess said it will next drill the Cob prospect, about 15 miles northeast of Pecan-1. Predevelopment and further exploration activities are planned in 2013.
Chevron, Falcon to explore Karoo basin
Falcon Oil & Gas Ltd., Dublin, agreed to work exclusively with a South African unit of Chevron Corp. to seek unconventional exploration opportunities in the Karoo basin in South Africa.
Falcon has a technical cooperation permit that gives the independent exclusive rights to obtain an exploration permit on 7.5 million acres in the southern part of the basin.
The new agreement provides for Falcon to work exclusively with Chevron Business Development South Africa Ltd. for 5 years in jointly obtaining exploration permits, subject to the parties mutually agreeing participation terms applicable to each permit. Falcon is to disclose when a permit is awarded. Chevron will advance Falcon $1 million now for past costs.
Falcon noted that the Karoo basin covers 236,000 sq miles or nearly two thirds of the country, with the 70,800-sq mile southern part of the basin potentially favorable for shale gas. A large part of Falcon's 11,719-sq mile TCP is in the prospective area, along the southern boundary.
The Permian Ecca Group has three potential gas shales in the Ecca formation. The most promising of these is the highly organic-rich, thermally mature shale of the Whitehall formation. This unit is regionally persistent in composition and thickness and can be traced across most of the basin.
Advanced Resources International Inc., Arlington, Va., estimated the undiscovered petroleum-initially-in-place and the prospective undiscovered resource attributable to these shales on behalf of the US Energy Information Administration. That April 2011 report concluded that the Lower Ecca Group shales contain 1,834 tcf of risked gas in-place with a risked recoverable shale gas prospective resource of 485 tcf.
BHP Billiton awarded deepwater blocks
Trinidad and Tobago announced that BHP Billiton and its partners have been awarded all four of the deepwater blocks approved by the Caribbean twin-island nation in its 2012 deepwater bid round. According the country's Ministry of Energy and Energy Affairs BHP Billiton and its partners were awarded Blocks TTDAA 5, TTDAA 6, TTDAA 28, and TTDAA 29.
The four production-sharing contracts will see, in the first phase, at least six deepwater exploration wells drilled and 5,330 sq km of 3D seismic.
In winning Block TTDAA 5, BHP Billiton was able to stave off strong competition from several consortia including Repsol, Centrica, BG Trinidad & Tobago, Elenilto, State Oil Co. of Azerbaijan Republic, Caspian Drilling Co., and Cairn Energy.
BHP Billiton already operates in Trinidad and Tobago in Angostura field where it found 300 million bbl of oil and 1.7 tcf of gas in what the company calls the Greater Angostura area off the island's east coast.
Trinidad and Tobago also announced that no award was made for Block TTDA 1 as both bids submitted for that block did not met one or more of the required benchmarks established by the Technical Evaluation Committee of the Ministry of Energy and Energy Affairs.
The bids were submitted by two consortia, BG T&T/Centrica and Elenilto/SOCAR/Caspian Drilling Co. Trinidad and Tobago's Ministry of Energy and Energy Affairs has said its Technical Evaluation Committee estimated the possible gas reserves in these blocks at 2.4-23.6 tcf and possible oil reserves of 428-4,200 million bbl.
The deep waters around Trinidad and Tobago have never been explored and in the last year, the island nation has awarded six blocks for exploration in the deep water, four to BHP Billiton and its partners and two to BP PLC.
Drilling & Production — Quick Takes
Rosneft, ExxonMobil agree to tight oil pilot
Rosneft and ExxonMobil Corp. signed a pilot development agreement finalizing a previously announced joint project to assess the possibility of commercial production of tight oil at the Bazhenov and Achimov formations in Western Siberia.
The agreement supports implementation of the companies' August 2011 long-term strategic cooperation agreement (OGJ Online, Aug. 30, 2011).
The joint venture will run a pilot program with Rosneft holding 51%. Work will be carried out at Rosneft's 23 license blocks covering more than 10,000 sq km. Drilling is expected to begin in 2013.
Rosneft and its production subsidiaries will provide workers and access to existing infrastructure. ExxonMobil will provide up to $300 million in financing along with technologies and expertise. In addition, ExxonMobil will provide production management services for drilling complex horizontal wells.
The pilot program will include drilling new horizontal and vertical wells using the latest fracturing technologies, deepening existing wells, and redevelopment of idle wells.
Syncrude lets oil sands tailings contracts
Syncrude Canada Ltd. has let two contracts to KBR for module fabrication and field construction of a full-scale plant for processing tailings from its oil sands mines northeast of Fort McMurray, Alta.
The plant will dewater fine tailings with centrifuges in a process that Syncrude says reduces overall volume by 50% or more. The process yields a soft, clay-rich material that can be used in land reclamation. Water is recycled for plant operations. The new facility will represent the first phase of a commercial plant due in operation by 2015.
Centrifuging technology is one of Syncrude's responses to a 2009 directive on tailings management by the Energy Resources Conservation Board of Alberta (OGJ Online, Dec. 2, 2009).
Other tailings-management methods Syncrude is developing include water-capping, in which fresh water is deposited over tailings in a settling pond to form a lake, and composite tails, in which the addition of gympsum and sand accelerates the settling of fine tails.
Tailing ponds hold the mixture of water, solids, and other fluids left over from the initial processing of mined oil sands. Because fine tailings settle out slowly, cycling of tailing ponds can require decades. In the meantime, more tailing ponds must be built, requiring more surface disturbance.
The ERCB's tailings-management directive addressed that problem. Earlier this year a study conducted for Alberta Innovates—Energy and Environment Solutions, a government agency, by an industry consortium outlined nine "roadmaps" for tailings management (OGJ Online, Aug. 31, 2012).
Statoil lets Gullfaks compression contract
Statoil AS let a $70 million subsea compression contract to Subsea 7 for the Gullfaks C platform in the aging Gullfaks oil field in the Norwegian North Sea.
Subsea 7 will provide engineering, installation, and commissioning of a 15.5-km integrated power service umbilical, a protection structure, a subsea compressor station, pipeline spools, and tie-ins.
Subsea 7 is working on the engineering aspect and expects offshore operations will start in 2015.
Earlier this year Jannicke Nilsson, Statoil head of operations North Sea West, said subsea compression might boost Gullfaks production by 3 billion cu m of natural gas (OGJ Online, Apr. 13, 2012).
PROCESSING — Quick Takes
Statoil issues FEED agreement for gas plants
Statoil Petroleum AS has signed a 3-year frame agreement with a unit of Foster Wheeler's global engineering and construction group for front-end engineering design (FEED) services at the Karsto and Kollsnes gas processing plants.
The contract covers future projects at the plants, located near Stavanger and Bergen, respectively. Statoil is acting on behalf of Gassco, which operates both plants, which in turn are owned by the Gassled joint venture, with Statoil as technical service provider.
The frame agreement includes an option for Statoil to extend it for 2 years and for Foster Wheeler to execute concept studies as well as FEEDs, Foster Wheeler said.
The Karsto plant treats gas and condensate from 28 fields on the Norwegian continental shelf that are connected to the plant by subsea pipelines. Karsto ranks as the world's third largest LPG export port and is the largest in Europe.
The Kollsnes processing plant treats gas from North Sea fields Troll, Kvitebjorn, and Visund and can handle as much as 143 million standard cu m/day.
DCP Midstream to build Eagle Ford cryogenic plant
DCP Midstream LLC and DCP Midstream Partners LP plan to build a cryogenic plant to provide gas processing services for producers in the liquids-rich Eagle Ford shale of South Texas.
The new Goliad plant will be constructed by the previously announced DCP Eagle Ford joint venture, which is owned two-thirds by DCP Midstream and one-third by DCP Midstream Partners.
The Goliad plant, expected to be completed by first-quarter 2014, is designed to have gas processing capacity of 200 MMcfd.
The DCP enterprise said Goliad will be its seventh plant in South Texas.
BP unit to expand Brazilian ethanol plant
BP Biofuels will spend $350 million to double the capacity of its Tropical sugarcane mill in Edeia, Goias State, Brazil, in a project that will enable the facility to process 5 million tons/year of sugarcane and produce 450 million l./year of ethanol equivalent.
The facility also will be able to supply about 340 Gw-hr of electricity to the Brazilian national grid. The expanded facility is expected to reach full operation late in 2014 or early in 2015.
BP owns 100% of the Tropical mill and operates two other Brazilian ethanol mills in Itumbiara in Goias and Ituiutaba in Minas Gerais.
TRANSPORTATION — Quick Takes
Crosstex to build Phase II Louisiana NGL expansion
Crosstex Energy companies, Crosstex Energy LP and Crosstex Energy Inc., will build Phase II of their Cajun-Sibon NGL pipeline extension and fractionator expansion in Louisiana. Phase I construction is underway with a mid-2013 service-date targeted (OGJ Online, Feb. 8, 2012).
Phase II, which Crosstex expects to finish second-half 2014, will include:
• Expansion of the Cajun-Sibon pipeline by an additional 50,000 b/d of raw-make NGL for a total project capacity of 120,000 b/d.
• Installation of a 100,000-b/d fractionator adjacent to the Crosstex's Plaquemine natural gas processing plant.
• Conversion of its Riverside fractionator to a butanes-plus plant.
• Construction of a 32-mile extension of Crosstex LIG's Bayou Jack lateral to provide gas services to customers in the Mississippi River corridor.
• Installation of four pump stations totaling 13,400 hp.
• Construction of 57 miles of NGL pipelines starting at Crosstex's Eunice fractionator and connecting to the new Plaquemine fractionator.
Crosstex entered into 10-year sales agreements with Dow Hydrocarbons and Resources LLC to deliver up to 40,000 b/d of ethane and 25,000 b/d of propane produced at the Plaquemine fractionator into Dow's Louisiana pipeline system. Crosstex will also deliver 70,000 MMbtu/day of natural gas to Dow's Plaquemine petrochemical plant.
Phase I of the project includes a 130-mile, 12-in OD. pipeline extending Crosstex's existing 440-mile Cajun-Sibon NGL pipeline system to connect its Eunice NGL fractionation in south central Louisiana to Mont Belvieu supply pipelines in East Texas. The pipeline will have an initial capacity of 70,000 b/d of raw-make NGL. Phase I also expands the Eunice fractionator to 55,000 b/d from 15,000 b/d, increasing Crosstex's interconnected fractionation capacity in Louisiana to roughly 97,000 b/d of NGL. Work on the Eunice expansion began in this year's third quarter.
Crosstex estimates the total cost for both phases of the project at $680-700 million.
Montana completes pipeline safety review
Montana's Oil Pipeline Safety Review Council, formed July 20, 2011, in the wake of ExxonMobil Pipeline Co.'s 1,000-bbl crude spill into the Yellowstone River, has issued its recommendations to the governor's office. Among the council's recommendations were increased funding for government inspections and upgrades to pipeline systems by the operating companies.
Other recommendations included Montana's Department of Environmental Quality (DEQ) maintaining an agreement with the US Pipeline and Hazardous Material's Safety Administration (PHMSA) to keep the Montana pipeline safety map current, holding twice-yearly meetings on pipeline safety, and coordination of geospatial information regarding pipelines and the states waterways. The recommendations, however, are non-binding.
The July 1 spill from ExxonMobil's 69-mile, 12-in. OD Silvertip pipeline prompted US Environmental Protection Agency assessment of 47 miles of the Yellowstone's riverbank, reporting light-to-moderate oil coverage on shoreline and island vegetation (OGJ Online, July 19, 2012).
Gorgon-Jansz LNG project costs continue to rise
Costs for the Chevron Corp.-led Gorgon-Jansz LNG project offshore Western Australia have risen by $9 billion (Aus.) to an estimated $52 billion (Aus.) for the first three trains. In addition, the schedule for first LNG cargo has slipped into 2015.
The new figure is the result of an extensive review of the project during the last 6 months by Chevron as operator. In 2009, Chevron gauged the project would cost $43 billion (Aus.).
The cost increase and the delay were blamed on the strengthening Australian dollar, an increase in labor costs, plus productivity issues. Chevron says the currency impacts and a change in the mix of currencies accounts for one third of the increase in the project's capital expenditure.
But Chevron Vice-Chairman George Kirkland insisted that the project economics are still attractive.
"Investment requirements may have grown," he said, "but oil prices which directly impact the overall revenue stream have increased approximately 80% over the same period."
Kirkland added that the LNG nameplate capacity has increased by 4% to 15.6 million tonnes/year from the three trains.
At this point, the project is 55% complete.
There was no word on the mooted fourth train that Chevron said several months ago would enter front-end engineering and design stages by yearend. Speculation is that the cost increase of the first three trains has set the fourth train on the backburner for the time being.
BHP Billiton sells out of Browse LNG project
BHP Billiton has sold all its interests in the Woodside Petroleum-led Browse LNG joint venture to PetroChina for $1.63 billion. The interests comprise an 8.33% stake in the East Browse JV and a 20% interest in the West Browse JV.
BHP referred to the Browse project as a nonstrategic asset and to the sale as an excellent opportunity for BHP and PetroChina.
The deal has yet to be finalized through the regulatory authorities. In addition other members of the JV—Royal Dutch Shell PLC, BP PLC, Mitsubishi, Mitsui, and Woodside Petroleum—do have a period of time to decide whether they will match the PetroChina offer through preemptive rights.
In August, Shell increased its interest in the Browse JV by exchanging its 33% interests in North West Shelf permits WA-20-P and WA-42-R with Chevron Corp.'s 16.7% and 20% interests in the Browse permits. It remains to be seen whether Shell will be interested in an additional stake.
Shell is known to be keen on using floating LNG technology to develop the Browse fields as opposed to a pipeline to James Price Point on the Kimberley coast or a pipeline down to the Burrup Peninsula to back-fill the North West Shelf Project.
This is despite the fact that the terms of the retention lease on the fields—Torosa, Calliance, and Brecknock—stipulate that development must be through an LNG plant at James Price Point.
For its part BHP did not seem keen on either FLNG or James Price Point and rumored to favor the Burrup Peninsula option. For BHP that preference is now academic.