GENERAL INTEREST — Quick Takes
BP posts first-half net loss of $2.73 billion
BP PLC recorded a $2.25-billion net loss in the second quarter and $2.73-billion net loss for the first half. Those totals compare with a $6.27-billion net loss in second-quarter 2015 and $4.16-billion net loss for first-half 2015.
The firm says its quarterly results were impacted by lower oil and gas prices and significantly lower refining margins, partly offset by the benefit of lower cash costs throughout the group as well as lower exploration write-offs.
The second-quarter results include the previously reported $5.2-billion pretax charge for the Macondo well blowout, whose total cumulative pretax charge to BP is $61.6 billion (OGJ Online, July 15, 2016).
Companywide production during the quarter averaged 2.09 million boe/d, down 1% year-over-year. First-half production averaged 2.26 million boe/d, up 2.3% year-over-year. BP expects planned new upstream projects to add 800,000 boe/d of production by 2020, with 500,000 boe/d of new capacity expected by yearend.
Organic capital expenditure for the first half was $7.9 billion. Full-year capex is now expected to be below $17 billion. During the half, BP received $1.9 billion from divestments, including the partial sale of its interest in Castrol India.
"We continue to reset our capital and cost base and are moving steadily towards our aim of rebalancing organic sources and uses of cash by 2017 in a $50-55/bbl oil-price range," said Brian Gilvary, BP's chief financial officer.
Interests, roles shifting in Argentina block
Holders of interests in the Coiron Amargo Block in Argentina's Nequen basin and a unit of Royal Dutch Shell PLC have entered a series of agreements that would subdivide the southern part of the 100,000-acre tract and adjust holdings and roles.
The block has conventional oil production from the Jurassic Sierras Blancas formation and unconventional potential in the Lower Cretaceous Vaca Muerta shale. It's divided into a northern exploitation concession of 26,598 acres and a southern evaluation concession of 72,738 acres.
According to Madalena Energy Inc., Calgary, which holds 35% interest in the total block, the agreements would divide the southern concession into two evaluation lots: Coiron Amargo Southeast and Coiron Amargo Southwest.
Parties to the agreements, in addition to Madalena, are Shell unit O&G Developments Ltd. SA, not previously an interest holder in the block; ROCH SA; Apco Oil & Gas International Inc., a subsidiary of Pluspetrol Resources Corp.; and provincially owned Gas y Petroleo del Nequen SA.
Subject to governmental approvals, Madalena will assign its interest in Coiron Amargo Southwest to the counterparties and increase its working interest in Coiron Amargo Southeast to 90% and become operator. Gas y Petroleo will retain its 10% working interest in Coiron Amargo Southeast.
Madalena will continue to hold 35% working interest in the northern exploitation concession, where Apco will become operator.
ROCH has been operator of the Coiron Amargo block with a 10% interest. Besides the ROCH and Madalena shares, interests before the new agreements take effect are Apco 45% and Gas y Petroleo 10%.
Silver Run to buy Delaware basin producer
Silver Run Acquisition Corp., Houston, has agreed to acquire a controlling interest in Centennial Resources Production LLC and expects to be renamed Centennial Resource Development Corp.
Centennial, formed in 2013 by an affiliate of NGP Energy Capital Management LLC of Irving, Tex., has producing acreage in the Delaware basin of Texas.
Silver Run's acquisition, subject to conditions including approval by its shareholders, will occur under an assignment from Riverstone Holdings LLC, which on July 6 agreed to buy 89% interest in Centennial from funds controlled by NGP.
Riverstone will buy Silver Run Class A common stock for about $810 million. Funds managed by Capital World Investors and by Fidelity Management & Research Co. will buy $200 million of Silver Run stock.
Proceeds of those stock sales will fund part of the cash consideration in the Centennial acquisition.
After closing, Riverstone and affiliates will own about 51% of Silver run. NGP will retain an equity stake of about 11%.
Mark Papa, a Riverstone partner who was chairman and chief executive officer of EOG Resources Inc. during 1999-2013, will lead Centennial after the transaction.
Centennial holds 42,500 net acres, mainly in Reeves and Ward counties and produces about 7,200 boe/d net to its interests. It estimates net proved reserves at 48.6 million boe.
The company has identified 1,357 gross potential locations for horizontal drilling.
Silver Run estimates the initial enterprise value of the combined company at $1.735 billion and the equity value after closing of $1.835 billion.
Exploration & Development — Quick Takes
Lundin begins three-well campaign in Barents Sea
Lundin Norway AS, a wholly owned subsidiary of Lundin Petroleum AB, has begun its 2016 exploration and appraisal campaign in the Loppa High area of the southern Barents Sea.
Comprising three wells to be drilled by the winterized Leiv Eiriksson semisubmersible drilling rig, the campaign begins with the reentry of the Alta-3 appraisal well 7220/11-3A, which was drilled last year on the eastern flank of the Alta discovery (OGJ Online, Sept. 30, 2015).
Occurring on PL609, the objective of the reentry is to deepen the well to further assess the quality of the Permian carbonate reservoir section and to conduct a production test.
The original Alta-3 well found a gross hydrocarbon column of 120 m, and all three Alta wells drilled to date have proven pressure communication. The Alta discovery is estimated to contain gross contingent resources of 125-400 million boe.
Following completion of the Alta-3 well, the rig will move farther north on PL609 to reenter the suspended Neiden exploration well 7220/6-2 that was partially drilled last year.
The well was suspended immediately above the prognosed reservoir section last October because of winter restrictions for the Island Innovator drilling rig. The Neiden prospect is estimated to hold gross unrisked prospective resources of 204 million boe.
The third well to be drilled in the campaign is an exploration well targeting the Filicudi prospect on PL533 to the northwest of the Alta discovery and south of the Statoil ASA-operated Johan Castberg discovery.
The prospect is expected to contain Jurassic sandstone reservoir analogous to the Johan Castberg discovery. Filicudi is estimated to contain gross unrisked prospective resources of 258 million boe.
Lundin Norway is operator of both PL609 and PL533 with 40% and 35% working interest in the licenses, respectively. The Leiv Eiriksson rig has been contracted for three firm well slots with an additional six optional well slots.
Aramco lets for gas field off Saudi Arabia
Saudi Aramco has let a $1.6-billion engineering, procurement, construction, and installation (EPCI) contract to Chiyoda Corp. to complete the second phase of Hasbah natural gas field, part of the two-field Al Wasit gas project.
The consortium will be involved in the construction of two streams of three wellhead platform topsides, one tie-in platform with flare platforms, and bridges tied together by umbilicals and in-field pipelines. Other work includes interconnecting trunk lines to the Fadhili gas plant onshore. According to Chiyoda, the scope covers 40% of the contract value.
Aramco commissioned the field in March and expects to reach a combined 2.5 bcfd from Hasbah and nearby Arabiyah fields (OGJ Online, Mar. 24, 2016). Both fields are in about 50 m of water, 150 km northeast of Jubail.
The Emas Chiyoda Subsea joint venture includes Chiyoda Corp. and Ezra Holdings Ltd., both with equal holdings. The contract term is 6 years, with an option to extend by another 6 years. The engineering and fabrication component has commenced with the offshore execution phase commencing in fourth-quarter 2017.
BOEM schedules Lease Sale 248 for western gulf
The US Bureau of Ocean Energy Management has scheduled western Gulf of Mexico Lease Sale 248 for Aug. 24 in New Orleans (OGJ Online, Apr. 5, 2016).
The auction includes all available unleased areas in the western gulf planning area for oil and gas exploration and development, covering 23.8 million acres located 9-250 nautical miles offshore Texas. It includes 4,399 blocks in 16-10,975 ft of water.
As a result of offering this area for lease, BOEM estimates a range of economically recoverable hydrocarbons to be discovered and produced of 116-200 million bbl of oil and 538-938 bcf of natural gas.
Lease Sale 248 will be the 11th offshore sale in the gulf and the final sale for the western planning area under the Obama administration's Outer Continental Shelf oil and gas leasing program for 2012-17. BOEM says the sale builds on the first 10 in the current 5-year program, which offered more than 60 million acres and netted nearly $3 billion.
Leases issued from this sale will also be the first for which BOEM will accept requests for extended initial periods, and confirm whether the lessee has earned such extension, a task previously performed by the Bureau of Safety and Environmental Enforcement.
BOEM releases draft EIS for possible Cook Inlet sale
The US Bureau of Ocean Energy Management released a draft environmental impact statement for a potential oil and gas lease sale in Alaska's Cook Inlet. The sale currently is scheduled for June 2017, the US Department of the Interior agency said.
A notice of the draft EIS's availability was scheduled to appear in the Federal Register on July 22, opening a 45-day comment period ending on Sept. 6, BOEM said in its July 15 announcement. Public meetings also will be held in Anchorage on Aug. 15, Homer on Aug. 17, and Kenai-Soldotna on Aug. 18.
BOEM said that the draft EIS analyzes important environmental uses and resources within the inlet off Alaska's southcentral coast. These include sea otter and beluga whale populations, human subsistence activities, and commercial salmon and Pacific halibut fishing. The draft EIS also analyzes a range of alternatives which will be considered.
Specifically, the area identified for the potential OCS Sale No. 244 is close to existing leases in state waters, avoids nearly all of the areas designated as critical habitat for the beluga whale and northern sea otter, avoids the critical area for the Stellar sea line, and excludes much of the subsistence-use area for the Alaska Native villages, BOEM said.
Drilling & Production — Quick Takes
BLM to review second NPR-A production well plan
The US Bureau of Land Management said it intends to conduct an environmental review for what would be the second oil and gas production well in the National Petroleum Reserve-Alaska.
ConocoPhillips Alaska Inc. submitted in August 2015 an application for the Greater Mooses Tooth-2 (GMT-2) project, which would include a drill site, access road, pipelines, and other facilities, BLM's Alaska State Office in Anchorage said.
It said the proposed project would be on BLM-managed land that has been selected for conveyance to Kuukpik Corp., an Alaska Native corporation organized under the 1971 Alaska Native Claims Settlement Act.
An associated pipeline and access road would cross both Kuukpik Corp. and BLM-managed public land within the 23 million-acre NPR-A and connect with the Greater Mooses Tooth-1 (GMT-1) development project that BLM finally approved in February 2015, BLM's Alaska office said.
The site is 8 miles southwest of GMT-1 and about 20 miles southwest of ConocoPhillips Alaska's producing Alpine field on Alaska state land, it added. BLM originally analyzed the proposed development in its 2004 Alpine Satellite Development Plan (ASDP), and it also is subject to the 2012 NPR-A Integrated Activity Plan, which was approved in February 2013, BLM said.
BLM now will prepare a supplemental environmental impact statement to the ASDP to evaluate new circumstances and information, including changes to the project's design, new data on climate change, and the US Fish and Wildlife Service's 2008 listing of the polar bear as a threatened species, it indicated.
BLM Alaska said that a 30-day public comment period on the proposed draft supplemental EIS for GMT-2 began on July 29, when it was slated to be published in the Federal Register.
Noble begins production at Gunflint in Gulf of Mexico
Noble Energy Inc., Houston, has started production at the Gunflint oil development on Mississippi Canyon Block 948 in the deepwater Gulf of Mexico.
The two-well field is ramping up and is expected to reach minimum gross production of 20,000 boe/d, with oil representing 75% of the produced volumes. The net amount to Noble is expected to be at least 5,000 boe/d, with potential for additional volumes depending on available capacity at the third-party host facility.
The development is a subsea tie-back to the Gulfstar One facility owned by Williams Partners LP and Marubeni Corp. Noble operates Gunflint with 31.14% working interest. Partners are Ecopetrol America Inc. 31.5%, Samson Offshore Mapleleaf LLC 19.13%, and Marathon Oil Corp. 18.23%.
Over the past year, Noble has overseen the gulf startups of the Big Bend and Dantzler developments. It also has interest in the Marathon Oil Corp.-operated Alba B3 compression platform offshore Equatorial Guinea, where production startup was reported this month (OGJ Online, July 14, 2016).
Badra field oil production reaches 67,000 b/d
PJSC Gazprom Neft says oil production has reached 67,000 b/d from Badra field in eastern Iraq. The company recently commissioned its tenth production well, the P-07, which is producing more than 6,500 b/d.
Gazprom Neft is drilling four other wells: P-10, BD-2, P-14, and P-19. In addition, a third process line was constructed at the field's central processing facility in June, and the first line of an associated petroleum gas treatment facility is 60% complete.
The field began producing May 31, 2014. It reached 45,000 b/d in September 2015.
Operator Gazprom Neft has 30%. Other partners are Iraqi Oil Exploration Co. 25%, Korea Gas Corp. 22.5%, Petronas 15%, and TPAO 7.5%.
PROCESSING — Quick Takes
Firms eye development of USGC petchem complex
Saudi Arabian Basic Industries Corp. (SABIC) and ExxonMobil Corp. affiliate ExxonMobil Chemical Co. are exploring potential development of a jointly owned grassroots petrochemical complex to be built at the US Gulf Coast.
If developed, the project-which would include a steam cracker and derivative units-would be built in Texas or Louisiana near natural gas feedstock, ExxonMobil said.
Before making final investment decisions for the project, the companies said they first plan to conduct necessary studies as well as work with state and local officials to help identify a potential site with adequate infrastructure access.
Further details regarding the proposed development, including an estimated cost and timeline for construction, were not disclosed.
This latest possible joint venture involving SABIC follows an announcement by the company last month that it has partnered with Saudi Aramco to conduct a joint feasibility study for development of a fully integrated crude oil-to-chemicals complex in Saudi Arabia (OGJ Online, June 28, 2016).
ExxonMobil's Beaumont refinery due new unit
ExxonMobil Corp. will add a new unit designed to increase production of ultralow-sulfur fuels at its 345,000-b/d refinery in Beaumont, Tex.
Due to begin construction during this year's second half, the project will involve installation of a 40,000-b/d selective cat-naphtha hydrofining unit (SCANfining) unit to produce gasoline that will meet the US Environmental Protection Agency's Tier 3 gasoline sulfur specifications, which take effect Jan. 1, 2017, ExxonMobil said.
To be ExxonMobil's largest capital investment in more than a decade at Beaumont's refining operations, the unit addition will improve product yield as well as help increase energy efficiency at the plant, said Fernando Salazar, manager of the Beaumont refinery.
Licensed by ExxonMobil, SCANfining hydroprocessing technology is a catalytic hydrodesulfurization process based on a proprietary catalyst system developed specifically for selective removal of sulfur from fluid catalytic cracking (FCC) naphtha that limits olefins hydrogenation to preserve octane content.
The SCANfining unit at Beaumont is scheduled for startup in 2018. This latest project at Beaumont follows ExxonMobil's 2015 announcement that it will expand the refinery's capacity to accommodate increased processing of light crudes from US shale (OGJ Online, Aug. 12, 2015).
Intended to add capacity for advantaged domestic crudes as well as to improve overall energy efficiency at the complex, the proposed 20,000-b/d expansion is due to be commissioned sometime in 2017, the company told investors on May 25.
Alongside the Beaumont refinery's crude unit expansion, ExxonMobil also is executing work to capture price-advantaged US crude supplies at its 500,000-b/d Baton Rouge, La., refinery, including projects to increase the plant's ability to process a wider slate of feedstock, as well as improvements to midstream infrastructure at the site.
ExxonMobil plans to complete the feedstock and logistics flexibility projects at Baton Rouge by yearend.
Par Pacific acquires Wyo. refinery, logistics assets
Par Pacific Holdings Inc., Houston, has completed its previously announced deal with Black Elk Refining LLC for the purchase of Wyoming Refining Co., which operates an 18,000-b/d refinery in Newcastle, Wyo., and through its wholly owned subsidiary Wyoming Pipeline Co. LLC, related logistics assets in the region (OGJ Online, June 15, 2016).
Par Pacific closed the transaction on July 14 for a total consideration of $271.4 million, including an assumption of about $58 million of debt, the company said.
With the acquisition of Wyoming Refining and Wyoming Pipeline now finalized, Par Pacific has taken ownership of the Newcastle refinery as well as the following assets:
• The 140-mile Thunder Creek crude oil pipeline gathering system in northeast Wyoming that provides the refinery direct access to Power River basin crude feedstock as well as direct connection to the Butte pipeline, which enables access to Bakken crude supplies.
• A 40-mile clean products pipeline system that feeds into the Magellan Products pipeline to serve markets in Rapid City, SD.
• A proprietary jet fuel terminal in Rapid City and jet fuel pipeline connecting the terminal to Ellsworth Air Force Base.
• About 650,000 bbl of crude and refined product tankage, with opportunities to expand these already identified.
Upon announcing the proposed deal in June, Par Pacific said it plans to add 4,000 b/d of isomerization capacity at the Newcastle refinery by yearend.
The refinery, which generates a clean product yield of about 95%, currently features the following processing capacities: crude distillation, 18,000 b/d; residual fluid catalytic cracking, 7,000 b/d; catalytic reforming, 3,300 b/d; alkylation, 1,300 b/d; naphtha hydrotreating, 3,300 b/d; and diesel hydrotreating, 6,000 b/d.
TRANSPORTATION — Quick Takes
Canada speeds ban on type of oil rail car
The Canadian government is accelerating its phaseout of railroad tank cars of the type involved in the fatal 2013 derailment of a train hauling crude oil in Quebec. The accident killed 47 persons and destroyed downtown Lac-Megantic (OGJ Online, Aug. 20, 2014).
Starting Nov. 1, transport of crude oil will be prohibited in tank cars designated DOT-111, which are considered the least crash-resistant units in use.
The ban takes effect 6 months earlier than originally scheduled for DOT-111 cars with shells lacking outer steel covers called jackets and 16 months earlier for jacketed DOT-111 cars.
DOE-111 cars are to be phased out for all flammable liquids by Apr. 30, 2025.
Replacement cars have added safety features such as thicker steel, end shields, thermal protection, and valve covers.
Golar, Schlumberger JV targets stranded gas
Golar LNG Ltd. and Schlumberger Ltd. have formed joint-venture OneLNG in an effort to rapidly develop low-cost gas reserves to LNG. The firms say the combination of Schlumberger's reservoir knowledge, wellbore technologies, and production management capabilities, with Golar's low-cost floating LNG approach, will offer gas resource owners faster and lower-cost development, increasing resources' net present value.
Golar owns 51% of the JV and Schlumberger 49%. The firms made an initial commitment covering investment to develop the JV's first project. They will discuss additional debt capital as required on a project-by-project basis.
After reviewing current market opportunities and describing 40% of the world's gas reserves as stranded, the firms expect to conclude five projects within the next 5 years.
Golar last year signed a binding heads of terms with Ophir Energy PLC to supply the Gimi FLNG vessel for use in developing Equatorial Guinea Block R. Gimi is Golar's second FLNG vessel following Hilli, which is scheduled to begin commercial operations off Cameroon in first-half 2017 (OGJ Online, May 6, 2015).