API: SEC disclosure proposal poses problems
The US Security and Exchange Commission's proposed rule to require resource extraction companies to disclose payments to the US and foreign governments could create competitive problems for US-listed companies, the American Petroleum Institute said in a comment it filed with the SEC.
Section 1504 of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which became law in December, added a section to the 1934 Securities Act calling for the SEC to issue rules requiring resource extraction issuers to include in an annual report any payments made by the issuer, or by a subsidiary or other entity controlled by the issuer, to the US or a foreign government for oil, gas, or mineral development.
The requirement would be to provide information about the type and total amount of payments made for each development project, and the type and the type and total amount paid to each government, the SEC said. A resource extraction issuer also would have to provide certain information regarding those payments in an interactive data format, as specified by the commission, it added.
"The unilateral approach to revenue disclosure proposed by the SEC would give foreign oil and gas companies access to confidential, proprietary information that they could use against US-listed companies when competing for crucial energy resources around the globe," said Misty McGowen, a director in API's office of federal relations, after submitting API's comments to the SEC.
McGowen said API supports the World Bank-backed Extractive Industries Transparency Initiative approach, which encourages disclosure by all oil and natural gas companies of payments made to foreign governments. The trade association hopes that the SEC works out anticompetitive aspects of the statute before finalizing the rule, McGowen said.
The SEC has extended the comment period on its proposal, which was scheduled to end on Jan. 31, until Mar. 2.
API document discusses fracing's surface impacts
The American Petroleum Institute released a third guidance document for hydraulic fracturing, covering practices to minimize associated surface environmental impacts. Two earlier guidance documents present well construction and integrity guidelines, and describe best practices for water management.
The latest document, HF-3, deals with recommended practices at the surface of wells which use fracing to produce oil and gas from tight shales. "We're trying to prevent runoff of materials from the site," explained Stephanie Meadows, a senior policy advisor at API.
"The idea is to keep materials there in a properly constructed containment area," she told reporters during a Feb. 2 teleconference. "There also is a big push for producers to speak with local authorities and landowners about what's going on. HF-3 also deals with handling any materials which leave the site."
The new document does not replace RP-51R, "Environmental Protection for Onshore Oil and Gas Production and Leases," a recommended practice which API adopted in July 2009, Meadows said. That document discusses environmentally sound practices and reclamation guidelines for all domestic onshore production operations, including water handling and gas compression facilities. HF3 tries to address surface environmental impacts specifically associated with fracing and complement the two earlier fracing guidance documents.
Meadows said that API's release of the latest fracing guidance document was timely since US President Barack Obama was scheduled to visit Pennsylvania on Feb. 3 to discuss economic recovery and job creation measures.
"While he's there, he will be standing on top of the second-largest natural gas formation in the world, the Marcellus Shale, which potentially could supply significant amounts of gas, produce new revenue for states and communities, and provide a major number of new jobs," she said. "We call on the president to lend the full weight of his office to development of this resource in New York, Pennsylvania, and West Virginia."
More information about HF-3 and other API standards and recommended practices associated with fracing can be found at API's web site.
Chesapeake, CNOOC eye Niobrara in Rockies
CNOOC Ltd.'s CNOOC International Ltd. will join Chesapeake Energy Corp. in a Niobrara-focused exploration and production program in the Denver-Julesburg and Powder River basins.
The companies plan to develop as much as 5 billion bbl of oil equivalent of net unrisked, unproved resource potential, after deducting royalties averaging 20%, in the next few decades.
CNOOC Ltd. will pay $570 million to purchase a 33.3% undivided interest in Chesapeake's 800,000 net oil and gas leasehold acres in the basin and agreed to fund 66.7% of Chesapeake's share of drilling and completion costs until a further $697 million has been paid, likely by the end of 2014.
Chesapeake expects to expand the operation from five operated rigs to 10 by the end of 2011 and 20 by the end of 2012. It operates 16 producing wells in the two basins that have reached initial production rates of up to 1,000 b/d of oil and 3 MMcfd of gas.
Chesapeake as operator will conduct all leasing, drilling, completion, operations, and marketing. CNOOC Ltd. will have the option to acquire a 33.3% share of any additional acreage acquired by Chesapeake in the area and the option to participate with Chesapeake for a 33.3% interest in midstream infrastructure related to production generated from the assets.
The deal is Chesapeake's sixth industry development agreement and its second with CNOOC Ltd.
China Beibu Gulf oil field projects approved
CNOOC Ltd. has internally approved the project investment and overall development plans for Weizhou 6-12 and Weizhou 12-8 West oil fields in Block 22/12 in Beibu Gulf in the South China Sea.
The plans will be submitted to China government authorities for formal approvals. Final investment decisions are expected by the end of February, and production is to start by the end of 2012.
Upon reaching a final investment decision, proved and probable reserves of 24 million bbl will be booked for the project.
Estimated gross development costs for the project have not significantly changed, said 19.6% interest holder Roc Oil (China) Co., Sydney. The project will use existing CNOOC-operated facilities, including water disposal wells, oil and gas transport facilities, and the Weizhou Island oil terminal.
A new CNOOC-operated integrated processing platform will host production from two unmanned platforms on WZ 6-12 and WZ 12-8 West fields and support production from other new CNOOC Ltd. fields. Eleven development wells will be drilled in 2012-13.
Provision has been made to drill several exploratory prospects from the two platforms to further test reservoir limits and identify nearfield prospects. The prospects are being matured, and success will potentially increase the development area's commercial reserves and possibly the peak production rate.
WZ 12-8 East field, also in the approved development area, is undergoing feasibility studies. If commercially attractive, its development will constitute the second phase of an integrated development following completion of the current WZ 6-12 and WZ 12-8 West project.
Project participating interests besides Roc Oil are CNOOC 51%, Horizon Oil (Beibu) Ltd. 14.7%, Petsec Petroleum LLC 12.25%, and Oil Australia Pty. Ltd. (Majuko Corp.) 2.45%.
Total seeks partner for France shale permit
Total SA is seeking a partner to replace Devon Energy Corp. on its Montelimar shale gas permit in France.
A share of up to 50% could be offered in the 5-year exploration permit awarded in March 2010 (OGJ Online, May 10, 2010).
The permit covers more than 4,300 sq km, and Total committed to a €37.8 million financial outlay. It requested a 1,859 sq km north extension in early November.
All shale gas knowledge in France and throughout Europe is based on old information extrapolated from US data. Total's spokesman Florent Segura told OGJ that Total is engaged in preliminary geological and geochemical studies that will take a year.
When the studies are completed, Total will drill three exploratory wells and then assess development feasibility, bringing it near the end of the permit span.
Environmentalists are increasingly up in arms against shale gas exploration and development in France, and some have even sought a moratorium on permit issuance. Environment Minister Nathalie Kosciusko-Morizet said this was legally impossible but that she would remain vigilant for any environmental damage.
Drilling & Production — Quick TakesSakhalin-1 drills 7.67-mile extended-reach well
Exxon Neftegas Ltd., operator of the Sakhalin-1 project, drilled the world's longest extended-reach well at Odoptu field, off Far East Russia, ExxonMobil Corp. said.
The Odoptu OP-11 well reached a measured total depth of 40,502 ft and a horizontal displacement of 37,648 ft. Exxon Neftegas completed the well in 60 days.
Odoptu, one of three Sakhalin-1 Project fields, is 5-7 miles off northeast Sakhalin Island.
ExxonMobil said the project involves "one of the most challenging sub-arctic environments in the world."
The first Sakhalin well was drilled in 2003, and the project has drilled six of the world's 10 record extended-reach wells. The specially designed Yastreb rig has been used throughout.
Since startup, the Sakhalin-1 project has produced 300 million bbl of oil for export to world markets. It also has supplied 235 bcf of associated natural gas locally.
Sakhalin-1 includes Chayvo, Odoptu, and Arkutun Dagi oil and gas fields. Potential recoverable resources are 2.3 billion bbl of oil and 17.1 tcf of gas.
BP joins nonprofit venture MWCC
BP PLC said Jan. 31 it has joined the Marine Well Containment Co. LLC (MWCC). Last year, BP announced plans to join the organization and to share its response experience and equipment (OGJ, Sept. 20, 2011, Newsletter).
MWCC, a nonprofit joint venture, was organized following the April 2010 blowout of BP's deepwater Macondo well in the Gulf of Mexico off Louisiana. The blowout resulted in an explosion and fire on Transocean Ltd.'s Deepwater Horizon semisubmersible and a massive oil spill.
Chevron Corp., ConocoPhillips, ExxonMobil Corp., and Royal Dutch Shell PLC formed the MWCC to provide emergency equipment and response services for future oil spills in the gulf (OGJ Online, July 21, 2010).
BP said equipment that it will bring to the MWCC includes riser, manifold, and containment systems deployed for use during the Deepwater Horizon response. In addition to the transfer of equipment, BP also will bring its information and supporting records, drawings, permits, licenses, and other technical information it developed throughout the spill response.
These items will be part of the MWCC interim response system aimed at enhancing deepwater safety and environmental protection in the gulf. MWCC companies are involved with the engineering, procurement, and construction of equipment and vessels for the system.
BP noted that it's also involved in industry efforts to improve prevention, well intervention, and spill response. This includes rig inspections and implementation of new requirements on blowout preventer certification and well design.
BOEMRE: Apache permanently plugging well in gulf
Apache Corp. is working to permanently plug a well near East Cameron Block 278 Platform B in the Gulf of Mexico off Louisiana, the US Bureau of Ocean Energy Management, Regulation, and Enforcement said Jan. 29.
Workers evacuated the platform Jan. 16 after noticing a hydrocarbon sheen (OGJ, Jan. 24, 2011, Newsletter). Apache operates the platform and owns 50% interest. Stone Energy Corp., Lafayette, La., owns the remaining interest.
The platform, in 173 ft of water, had not been in production for nearly a decade. It was used to process natural gas and condensate from other facilities. Apache was permanently plugging nonproducing gas wells when the sheen was noticed.
Under BOEMRE's supervision and approval, Apache reboarded the platform Jan. 19 and "began work to kill the leaking well," BOEMRE said. A remotely operated vehicle is being used to monitor the well to ensure safe operations.
"Well-control procedures from the platform were successful in stopping the flow of natural gas from the well," BOEMRE said.
A jack up drilling rig belonging to Hercules Offshore Inc. arrived at the area Jan. 23 in case it were to be needed to drill a relief well if the well-plugging operations cannot be completed successfully, BOEMRE said.
PROCESSING — Quick TakesMarcellus cryogenic plant starts up
Another Marcellus gas processing plant has been started up near Cameron, W.Va.
Caiman Energy LLC, Dallas, announced it has completed the 120-MMcfd Fort Beeler Plant 1 and signed a long-term processing agreement with Chesapeake Energy Corp. for production from Marshall and Wetzel counties.
Caiman Energy LLC's natural gas processing plant at Fort Beeler near Cameron, W.Va. Photo from Caiman Energy.
In the same announcement, Caiman said it expects to complete the 200-MMcfd Fort Beeler Plant II by yearend, bringing the company's total natural gas processing capacity at Fort Beeler to 320 MMcfd.
Caiman said it will also explore construction of a third cryogenic plant with a capacity of 200 MMcfd as early as second-quarter 2011. Caiman Energy Pres. and Chief Executive Officer Jack Lafield said, "We expect to have total processing capacity of 520 MMcfd on line" by second-half 2012 (OGJ Online, Mar. 11, 2010).
Caiman noted other recent midstream service agreements with long-term acreage dedications that include contracts with Gastar Exploration Ltd., Stone Energy, Grenadier Energy Partners LLC, and Drilling Appalachian Corp. It also has agreements in place with AB Resources LLC and Chief Oil & Gas LLC, which it said are its initial anchor tenants in the Marcellus. Existing customers also include Trans Energy Inc. and Republic Energy LLC.
The new agreements bring Caiman's total dedicated acreage in Marcellus rich gas processing in Marshall and Wetzel counties to more than 160,000 acres. Including dedications in lean Marcellus gas in Pennsylvania and West Virginia, Caiman said it now has nearly 500,000 acres of Marcellus acreage dedicated to its midstream operations.
Caiman operates more than 60 miles of high-pressure, large-diameter pipeline in the Marcellus shale and an additional 60 miles of gas gathering lines under construction. Lafield said that by yearend, Caiman expects to have invested more than $400 million for infrastructure in the Marcellus.
DOE to convert heating oil reserve to ULSD
New, more-stringent standards by some US Northeast states were behind the Feb. 1 announcement by the US Department of Energy that it will convert inventory in the Northeast Home Heating Oil Reserve to ultralow-sulfur distillate fuel oil.
Congress authorized the 2 million bbl reserve in the 2000 Energy Policy Act as a government-owned heating oil stockpile for emergencies. About 69% of the US households that use heating oil are in the Northeast.
New York and other states in the region are implementing standards requiring replacement of higher sulfur heating oil (with 2,000 ppm) to the ULSD, which has 15 ppm, DOE's Fossil Energy office said. DOE will sell the 2 million bbl of inventory in the reserve as a result, it said.
It said the sale of heating oil from the reserve's sites in New England and the New York Harbor will commence on Feb. 3 from 11 a.m. to 2 p.m. EST with an initial 1 million bbl offer from Hess Corp.'s First Reserve Terminal in Perth Amboy, NJ, using an interactive online bidding system.
The sale will be open to all registered bidders who have posted a required $250,000 guarantee, DOE said. It added that for purposes of this sale, it has waived two requirements limiting the quantity of heating oil which may be awarded to a bidder and his affiliates, and requiring a bidder to certify that he is customarily engaged in the sale and distribution of heating oil.
Locations, delivery points, pricing policies, and both minimum and maximum quantities offered will be posted in the sale notice. DOE said that more than one offering is planned until it achieves its sales goal, and that notices will be sent to potential bidders before each additional sales offer.
Chevron to build lube plant at Mississippi refinery
Chevron Corp. unit Chevron Lubricants will build a lubricants plant at the company's Pascagoula, Miss., refinery. It estimated the cost of the Pascagoula base oil project at $1.4 billion.
The plant will manufacture 25,000 b/d of premium base oil, the main ingredient in production of top-tier motor oil that, the announcement said, helps "improve fuel economy, lower tail-pipe emissions, and extend the time between oil changes." In addition to motor oil, base oil is also used to make lubricants for high-tech machinery and equipment used in the commercial and industrial sectors of the economy.
Construction is to be completed by yearend 2013. The project will roughly double Chevron's premium base oil production, said the announcement. The company currently manufactures premium base oil at its refinery in Richmond, Calif., and a joint-venture plant in Yeosu, South Korea.
Premium base oil produced in Pascagoula is to serve markets in North America, Latin America, and Europe.
The base oil plant will use Chevron's Isodewaxing technology, which it began using commercially in 1993. The company said about two-thirds of the world's premium base oil is manufactured with this technology.
The Pascagoula plant is Chevron's largest wholly owned refinery with capacity to process 330,000 b/d of oil to produce gasoline, jet fuel, diesel, and other products. The refinery began operating in 1963.
TRANSPORTATION — Quick TakesINGAA forms executive-level pipeline task force
The board of the Interstate Natural Gas Association of America formed an executive-level pipeline tax force and named Christopher A. Helms, executive vice-president and group chief executive of NiSource Gas Transmission & Storage, as its chairman.
"For the past several years, the focus of the nation's interstate natural gas pipelines has been on a safety culture for both our companies and our suppliers, and we believe we can provide leadership and work with regulators and other stakeholders toward the common goal of safe transportation of natural gas," Helms said Jan. 27 following the INGAA board's meeting.
The task force, which will consist of INGAA board members, will oversee development of the next pipeline safety standard level because gas is a critical US fuel, Helms said.
Cheniere unit signs another LNG export agreement
Cheniere Energy Partners LP's subsidiary Sabine Pass Liquefaction LLC has concluded a nonbinding memorandum of understanding with Sumitomo Corp. under which Sumitomo intends to contract for up to about 1.5 million tonnes/year of processing capacity at the Sabine Pass LNG terminal in Cameron Parish, La.
Under the MOU, Sumitomo and Sabine agreed to negotiate definitive agreements for Sumitomo to contract bidirectional capacity. The final agreements would be subject to, among other conditions, receipt by each party of internal approvals, Sabine Pass's receipt of regulatory approvals, and a final investment decision by Sabine Pass to construct the liquefaction.
Charif Souki, chairman and chief executive officer of Cheniere Energy Partners, said, "With this MOU we have up to 7.7 million tpy of LNG processing capacity reserved. We have reached our targeted capacity for the first two trains and look forward to advancing discussions and entering into definitive agreements."
Cheniere Partners owns 100% of the Sabine Pass LNG terminal, which has sendout capacity of 4 bcfd and storage capacity of 16.9 bcf of gas equivalent.
As currently contemplated, said the company's announcement, Sabine Pass liquefaction would be designed and permitted for up to four modular LNG trains, each with peak processing capacity of up to about 7 MMcfd of natural gas and average liquefaction processing capacity of about 3.5 million tpy.
The initial project phase will include two modular trains and capacity to process about 1.2 bcfd of pipeline-quality gas. Cheniere said it intends to conclude contracts for at least 5 MMcfd/train of liquefaction capacity. With regulatory and company approvals, LNG export could commence as early as 2015, said the announcement.
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