GENERAL INTEREST — Quick Takes
EPA delays proposal to regulate methane emissions
The US Environmental Protection Agency has delayed plans to issue proposals to regulate methane emissions from oil and gas operations until this year, OGJ has learned (see story, p. 44).
It reached the decision a week after the American Lung Association issued results of a survey it commissioned that found 63% of respondents supporting the agency establishing the first federal methane emissions limits.
Greenberg Quinlan Rosner and Perception Insight surveyed 1,000 registered voters nationally by telephone Nov. 13-18, ALA said on Dec. 10, 2014, as it released findings that also showed 43% favorable impressions of EPA and 42% unfavorable feelings toward the oil and gas industry.
"The poll shows that a large, bipartisan majority of American voters support a methane pollution standard that will protect public health," Perception Insight President Marc DelSignore said. "Support increases, in particular, with Republicans who move from being tied on the initial question to a 14-point margin in support after hearing arguments from both sides."
Speakers at a Center for Strategic and International Studies conference 2 days earlier outlined a broad range of methane emissions differences which need to be addressed before trying to impose national regulations (OGJ Online, Dec. 8, 2014).
American Petroleum Institute officials previously said that domestic producers are reducing wellhead methane emissions already and don't need ill-conceived, overly prescriptive federal regulations (OGJ Online, Dec. 5, 2014).
Moody's: Midterms dim fracing regulations prospects
Results of 2014's congressional elections have reduced the prospect of the federal government enacting its own hydraulic fracturing regulations, Moody's said in a Dec. 17, 2014, report. It noted that Republicans, who generally have taken the position that state regulations are sufficient, will assume control of the US Senate in addition to the House this month.
This change in Washington's political climate means oil and gas producers can avoid the consequences of higher costs from federal regulation, the New York credit rating service said. It cited an Independent Petroleum Association of America estimate that one proposal could raise costs by as much as $100,000/well.
"However, the biggest benefit of not having federal regulation is the time to receive permits, which likely would have slowed," the report added.
Operators face growing regulations of their exploration and development of unconventional resources on state and local levels, it said. Courts in Pennsylvania and New York have upheld communities' rights to ban fracing even if state law allows it, and new local restrictions face legal challenges in Colorado and Texas, the Moody's report said.
It also pointed out that New York Gov. Andrew Cuomo (D) banned the technology's use within the state following a 3-year study (OGJ Online, Dec. 17, 2014).
House Dems ask Jewell to bar leasing in Arctic
US Rep. Jared Huffman (D-Calif.) and 30 other House Democrats urged US Interior Sec. Sally Jewell to reject the second supplemental environmental impact statement for OCS Lease Sale 193 and bar oil and gas leasing in the Arctic Ocean.
"In light of the long history of legal disputes around this lease sale and the near complete inability to respond to an oil spill in this remote and sensitive region, we believe that no leasing should proceed in the Arctic Ocean," they said in a Dec. 17 letter to the secretary.
The federal lawmakers sent the letter as their comments on Sale 193's second supplemental EIS before the comment period closes at midnight EST on Dec. 22, 2014.
The US Bureau of Ocean Energy Management prepared the second SEIS after the federal district court for Alaska remanded Sale No. 193 back to the US Department of the Interior agency to address deficiencies the US Ninth Circuit Court of Appeals found in the sale's original 2007 final EIS in January.
BOEM also held seven public hearings in Alaska, where it accepted comments on the new document.
Huffman, who is a House Natural Resources Committee member, and the other Democrats said Shell Offshore Co., which acquired tracts in the original 2008 lease sale, "seeks weaker regulations and authorization to return to the Chukchi Sea with a larger, noisier, and more polluting drilling program... despite the major flaws of its 2012 drilling program and unanswered questions about how it has addressed those failures," they told Jewell in their letter.
"Your decision on Lease Sale 193 will set a precedent for our actions on drilling, climate change, and protection of the Arctic region," they said.
BASF, Gazprom cancel asset swap
BASF and OAO Gazprom have agreed not to complete an asset swap that was scheduled for yearend 2014.
"We regret that the asset swap will not be completed," said Kurt Bock, chairman of BASF SE.
It was originally planned that two blocks of the Achimov formation in the Urengoi gas and condensate field in Western Siberia would be jointly developed by Gazprom and BASF subsidiary Wintershall Holding GMBH (OGJ Online, Nov. 14, 2012).
In return, Wintershall would have transferred a jointly operated gas trading and storage business to Gazprom.
Additionally, Gazprom would have received a 50% share in a Wintershall subsidiary's exploration and production activities in the southern North Sea.
The gas trading business will continue to operate as a 50-50 joint venture of Gazprom and Wintershall.
Exploration & Development — Quick Takes
Mexico uses PSCs in first Round One step
Mexico is offering production-sharing contracts to companies incorporated in the country for exploration of 14 shallow-water areas in Round One bidding for oil and gas opportunities (OGJ Online, Nov. 10, 2014).
The law firm Mayer Brown reports PSCs with 3 to 5-year exploration terms will be awarded "pursuant to economic criteria contained in the bidders' proposals, based on a weighted formula that includes consideration of the share of operating profits offered to the state and a multiplier of the minimum investment commitment per contract area."
Companies from outside Mexico may participate in all phases of bidding. The government's National Hydrocarbons Commission (CNH), however, may execute exploration and production contracts only with commercial entities incorporated in Mexico.
State oil firm Pemex is authorized to bid by itself or in association with other operators under the same bidding terms.
The bidding invitation for exploration of the 14 shallow-water areas is the first step in Round One.
The Ministry of Energy's tentative schedule for subsequent 2015 steps in the round is for bidding invitations in January for shallow-water, in February for onshore, in March for the Chicontepec basin and unconventional, and in April for deep water.
Apache awarded Western Australia offshore permit
After reporting its planned divestment of Western Australian and Canadian assets to Woodside Petroleum Ltd., Apache Corp. has been awarded an exploration permit in the latest round of Australia's offshore licensing (OGJ Online, Dec. 16, 2014).
Block WA-505-P lies in the Roebuck basin about 200 km north of its significant Phoenix South-1 oil find made in 2014.
Apache's work commitments include $9.2 million (Aus.) spent on about 400 sq km of 3D seismic and related technical analysis in the first 3-year term of the license. The secondary work program between years four and six includes the commitment to drill a $20.4 million exploration well.
The bidding process for this permit began prior to Apache's head office decision to exit many of its Australian operations as well as those elsewhere in the world, and there is speculation that Woodside may be interested in adding this latest permit to its acquisition list. However, it is also significant that Apache did not include the Phoenix South-1 block in the sale.
Looking at the government's latest bid round overall, Industry Minister Ian Macfarlane announced a total of $660 million has been pledged in new offshore exploration areas.
Other successful bidders were Statoil ASA in WA-506-P on the deepwater margin of the North West Shelf, guaranteeing $50 million in the first 3 years and $216 million in the second 3 years; Liberty Petroleum in Vic/P70 in the southeast margin of the Gippsland basin, guaranteeing $81.3 in the first 3 years, including two wells; and Santos Ltd.-Origin Energy Ltd. in NT/P85 in the Bonaparte basin, guaranteeing a spend of $28.3 million in the first term and $36 million, including one well in the second.
Odyssey Oil & Gas-Black Swan Resources won WA-507-P in the Northern Carnarvon basin with a guarantee of $2.25 million, while Pathfinder Energy was awarded WA-508-P and WA-509-P in the Browse basin for guaranteed expenditure of $2.1 million and $10.6 million, respectively.
AWE pulls out of Otway permit
AWE Ltd., Sydney, has decided to pull out of Perth-based WHL Energy Ltd.'s offshore Otway basin permit Vic-P67 after a series of time extensions for deciding about moving to the exploration drilling phase in the permit.
It is understood the significant drop in world oil prices is behind the withdrawal. AWE has no further claim against recovered costs. WHL still believes the permit has excellent value. The company has identified 14 prospects with a total potential of 1 tcf of gas and 31 million bbl of condensate and LPG following its 3D survey earlier this year.
The permit also contains the La Bella gas discovery made a number of years ago by BHP Petroleum, now BHP Billiton Ltd.
WHL began farmout negotiations in October 2014.
Another potential partner, fellow Perth company Tap Oil Ltd. has an option to acquire an initial 10% interest in the permit, for which it will pay $3.6 million (Aus.) as a first commitment.
Drilling & Production — Quick Takes
ExxonMobil begins Bass Strait drilling campaign
The ExxonMobil Corp.-operated joint venture with BHP Billiton Ltd. and Santos Ltd. has begun a $335 million (Aus.) offshore drilling campaign in Bass Strait encompassing five Turrum field wells to bolster the $4.5-billion Kipper-Tuna-Turrum development project that came on stream in November 2013.
Four gas development wells and one oil development well will be directionally drilled from the new Marlin B platform. The program will continue into the second half of this year.
Turrum holds an estimated 1 tcf of gas and 110 million bbl of oil and gas liquids.
Turrum and Tuna are held 50-50 by ExxonMobil and BHP Billiton, while Kipper field is Santos 35%, and ExxonMobil and BHPB 32.5% each.
In other moves, ExxonMobil has abandoned its project targeting coal seam gas in the onshore Gippsland coal measures of the Latrobe Valley citing policy challenges.
There has been a moratorium on fracing wells onshore Victoria for several years.
Statoil lets contract to Schlumberger for Mariner field
Statoil ASA has awarded an integrated drilling and well services contract for the Mariner heavy oil field in the UK North Sea to Schlumberger Oilfield UK PLC.
The 4-year contract begins in January and has options for additional 4-year periods. It has 22 service components, including drilling, completion, electrical submersible pumps, cement, fluids, and logistics support.
Mariner is 150 km east of the Shetland Isles. Drilling is expected to start in 2016 and production in 2017. Statoil has 65.11%; JX Nippon Exploration & Production (UK) Ltd. 28.89%; and Dyas Mariner Ltd. 6%.
The main Mariner platform will have one drilling rig and one well intervention and completion unit. In addition, a newbuild jack up rig will be next to the Mariner installation, working through well slots on the platform for the first 4 years. Over the field's lifetime, as many as 130 well targets are planned, Statoil said (OGJ Online, Apr. 10, 2013).
Statoil is establishing an integrated operations team in Aberdeen. Gunnar Breivik, managing director for Statoil Production UK, said the company "will be working closely with both the service supplier and the drilling contractor Odfjell and rig contractor Noble [Energy Inc.] to plan and optimize operations."
Breivik said the contract's performance-based compensation format rewards "meters drilled and completed rather than usage of time and material."
The contract with Schlumberger also includes options for the Bressay field, currently in the "concept evaluation phase."
Comstock to suspend oil drilling in Eagle Ford, TMS
Due to low crude oil prices, Comstock Resources Inc., Frisco, Tex., plans to suspend its 2015 oil-directed drilling activity on properties in the Eagle Ford shale in Texas and Tuscaloosa Marine shale (TMS) in Mississippi.
Comstock will instead target natural gas on its Haynesville shale natural gas properties in North Louisiana. The company "believes that improved completion technology, including longer laterals, will provide strong returns on drilling projects at current natural gas prices."
Comstock has released its rig in the TMS and will postpone drilling activity in the area until oil prices improve.
The company currently operates four rigs drilling on its Eagle Ford properties. Two will be released in early 2015 while the other two will move to start a drilling program in the Haynesville.
The company plans to drill 19 horizontal wells in 2015, of which 14 will be Haynesville-Bossier shale gas wells and five will be drilled its Eagle Ford acreage.
Thirteen Eagle Ford wells are expected to be completed in 2015. In June, the company drilled the Henry A No. 1H well in Burleson County, Tex., to a vertical depth of 9,514 ft (OGJ Online, June 26, 2014). It tested at a peak 24-hr average production rate of 1,267 boe/d, of which 1,023 b/d was oil and 1.5 MMcfd was natural gas.
The company has 33,900 gross acres-30,400 net-prospective for oil in Burleson County.
Comstock also plans to refrac 10 of its existing Haynesville producing wells as part of the 2015 program.
Comstock-which has budgeted $307 million in 2015 for drilling and completion activities-estimates that the drilling program will generate company-wide oil production of 3.5-3.9 million bbl and natural gas production of 55-60 bcf during the year.
PROCESSING — Quick Takes
Unipetrol's purchase of Czech refinery approved
Unipetrol AS's plan to acquire soon-to-be former partner Eni SPA's interest in Ceska Rafinerska AS (CRC) to become the plant's sole owner would not violate state antitrust laws, the Czech Republic's Office for the Protection of Competition (UOHS) said on Dec. 19, 2014.
After examining the transaction in relation to the wholesale marketing of petroleum products in the relevant regional markets, Unipetrol's purchase of Eni's shares in CRC does not raise fears of any substantial distortions of competition, according to a statement from UOHS, the central authority of state administration responsible for ensuring a competitive business environment.
The preliminary ruling, once finalized, will permit Unipetrol, a subsidiary of Polski Koncern Naftowy SA (PKN Orlen), to take full ownership of the refinery, UOHS said.
UOHS's decision follows Unipetrol's decision in July to exercise its right of preemption to purchase Eni's nearly 32.5% stake in CRC for about $40.8 million after Eni entered preliminary negotiations in May to sell its shares in the refinery to Hungary's MOL Group (OGJ Online, July 3, 2014; May 7, 2014).
Unipetrol's buyout follows the company's overall strategy for 2013-17, released in June 2013, in which the operator said it planned to increase capital spending on projects designed to further integrate the refining and petrochemical segments of its business in order to guarantee secure feedstock supplies for its petrochemical operations.
CRC operates Czech Republic's only two running refineries-in Litvinov and Kralupy-which have a combined crude oil processing capacity of 8.7 million tonnes/year, according to Unipetrol.
IOC wraps study for petrochemical plant at Paradip
Indian Oil Corp. Ltd. (IOC) has completed a detailed feasibility study for setting up a polypropylene (PP) plant as part of a proposed petrochemical complex to be attached to its long-delayed 300,000-b/d, full-conversion refinery at Paradip, Odisha, on India's northeastern coast (OGJ Online, Aug. 14, 2014).
The plant will have a production capacity of 700,000 tonnes/year and will cost about 31.5 billion rupees ($492.6 million), India's Ministry of Petroleum and Natural Gas said on Dec. 17.
IOC's board previously took an investment decision on the PP plant in March, according to the ministry.
The PP plant is scheduled to be commissioned during 2017-18. In addition to the PP plant, IOC also has plans to set up additional derivative units at the Paradip petrochemical portion of Paradip for ethylene glycol, paraxylene and purified terephthalic acid, and petcoke gasification, according to Minister of Petroleum and Natural Gas Shri Dharmendra Pradhan.
Configured to process heavy and high-sulfur crude oil and to produce Euro 5-standard fuels, the $5-billion Paradip refinery, which began some start-up activities in early 2014, is slated to be commissioned fully by late-March or early-April (OGJ Online, Dec. 1, 2014).
ExxonMobil lets contract for Antwerp refinery
ExxonMobil Petroleum & Chemical BVBA has let an engineering, procurement, and construction contract to Fluor Corp. for a delayed coker to be installed at its 320,000-b/d Antwerp refinery (OGJ Online, July 2, 2014).
In addition to EPC services, Fluor's scope of work will include module fabrication, transportation, and installation for the unit, Fluor said.
Led by Fluor's office in the Netherlands, engineering and design work for the project began in June, while construction activities officially started following a groundbreaking ceremony in October, Fluor said. While Fluor did not disclose the value of the lump-sum contract, the service company said it did book the project into its backlog earlier in 2014.
The start of construction on the project follows ExxonMobil's announcement earlier in the year that it would invest $1 billion in to install the delayed coker as part of the company's long-term strategy to help the Antwerp refinery better compete in Europe's challenging industry environment by directly addressing a shortfall in regional refiners' capability to convert fuel oil to products such as diesel.
TRANSPORTATION — Quick Takes
Woodside to buy Apache's Wheatstone, Kitimat share
Woodside Petroleum Ltd. has agreed to acquire interest in the Wheatstone LNG and Kitimat LNG projects, respectively in Western Australia and British Columbia, along with accompanying upstream oil and gas reserves, belonging to Houston independent Apache Corp. for $2.75 billion.
Apache also will be reimbursed for its net expenditure in the Wheatstone and Kitimat LNG projects, estimated at $1 billion, between June 30, 2014, and closing, expected in first-quarter 2015. Based on current estimates, Apache's net proceeds upon closing are expected at $3.7 billion.
In the deal, Woodside will acquire Apache's equity ownership in its Australian subsidiary, Apache Julimar Pty. Ltd., which owns 13% interest in the Wheatstone LNG project and 65% interest in the WA-49-L block, including the Julimar-Brunello offshore gas fields and the Balnaves oil development (OGJ Online, July 11, 2012).
The transaction will also include Apache's 50% interest in the Kitimat LNG project and related upstream acreage in the Horn River and Liard natural gas basins in British Columbia. The sale of the Kitimat LNG project is subject to certain operator consents.
Kuwait Foreign Petroleum Exploration Co. last year agreed to acquire Royal Dutch Shell PLC's 6.4% interest in Wheatstone LNG, nearly doubling Kufpec's interest in the $29 billion (Aus.) LNG project to 13.4% from 7% (OGJ, Jan. 27, 2014, p. 24).
Chevron Canada acquired its 50% interest in Kitimat LNG in 2013 along with half interest in the proposed Pacific Trail Pipeline and in 644,000 acres in the Horn River and Liard basins in British Columbia (OGJ Online, Dec. 26, 2012). The two-train Kitimat project targets a 2016 start-up date.
Apache will retain upstream acreage offshore Western Australia in the Carnarvon, Exmouth, and Canning basins, along with related hydrocarbon reserves and production. Apache will also retain its 49% ownership interest in Yara Holdings Nitrates Pty. Ltd. and 10% interest in the related ammonium nitrate plant.
Woodside delays Browse FLNG development schedule
Woodside Petroleum Ltd. has reported it expects to enter front-end engineering and design phase for the proposed Browse floating LNG (FLNG) development in mid-2015. Partners BP, Japan Australia LNG, PetroChina, and Shell have all agreed to the revised schedule.
Woodside said the delay will take into account the substantial shift in market conditions that will enable the joint venture to seek significantly lower cost outcomes for the Browse project.
Woodside CEO Peter Coleman said the time will be used to maximize long-term economic benefits for the development.
"The JV intends to take the opportunity to go back to the shipyard, the designers and the suppliers and make sure they are beginning to put some of the cost reductions into the numbers that they're showing us," he said. "We don't want to move forward with Browse at this point and miss the opportunity of locking some lower prices into our cost," Coleman added.
Additional activities to be undertaken leading up to FEED include progressing primary approvals for the project, managing the impacts of the maritime boundary changes affecting the Browse retention leases and additional technical work to optimise and derisk the development.
A final investment decision for Browse FLNG is slated for mid-2016.