GENERAL INTEREST Quick Takes
Scotland bans unconventional development
The Scottish government has confirmed its de facto ban on hydraulic fracturing and other methods of developing unconventional oil and gas (UOG) resources.
Energy Minister Paul Wheelhouse cited “the incompatibility of UOG development with climate change policy.”
The decision, he said, “means the Scottish government will not issue licenses for new UOG development, and that Scotland’s planning framework will not support development using unconventional oil and gas extraction techniques, including coalbed methane and hydraulic fracturing.”
Wheelhouse had told Parliament in October 2017 that a moratorium on hydraulic fracturing imposed in 2015 “would remain in place indefinitely” and said local authorities had been informed of an effective ban on UOG development.
After a court challenge, the government said it had not implemented a ban.
Wheelhouse called the new decision “a finalized policy.” A final policy due in this year’s first quarter was delayed for public consultation (OGJ Online, Mar. 27, 2019).
Norway shrinking oil and gas divestment
Norway is shrinking divestment by its sovereign wealth fund of equity holdings in oil and gas companies (OGJ Online, Nov. 17, 2017).
The program, implemented to lower the country’s exposure to oil-price risk, has applied to companies in a category labeled “exploration and production” in a stock-exchange index.
The category included refining and marketing.
The index owner this year redistributed “exploration and production” companies into two new categories: “oil: crude production” and “oil refining and marketing.”
The Finance Ministry on Oct. 1 specified that divestment by the Global Pension Fund Global (GPFG) applies only to the former category.
The move apparently excludes integrated oil and gas companies from divestment.
The ministry said 95 companies were in the “crude: oil producer” category in mid-September, representing 0.8% of the GPFG’s benchmark for equities.
When the original program was adopted, the fund’s oil and gas equities represented about 4% of its holdings.
The ministry said phaseout of investment in the newly narrowed category “will be made gradually over time.”
Citizen to acquire Roan Resources for $1 billion
Citizen Energy Operating LLC, a Warburg Pincus LLC affiliate, agreed to acquire Roan Resources Inc., Oklahoma City, in an all-cash transaction valued at $1 billion. The deal includes Roan’s funded net debt of $780 million as of Sept. 30.
According to Roan Resources’ web site, the company holds a consolidated 177,000-acre position in the Merge-SCOOP-STACK plays in Oklahoma’s Anadarko basin. It estimates a resource potential of more than 2 billion boe. In this year’s second quarter, the company produced 50,800 boe/d (26% oil, 29% natural gas liquids, and 45% gas).
Roan has appointed Rick Gideon as its chief executive officer. He was previously senior vice-president of US operations at Devon Energy Corp. Gideon will assume his new responsibilities immediately. To allow him time to assess the operations plan, the company said it will temporarily reduce its drilling and development activity and suspend all completion activity.
Under the terms of the merger agreement, Roan stockholders will receive $1.52 in cash for each share of Roan common stock. The all-cash purchase price represents a premium of 24% over the closing price of company shares as of Sept. 30.
The transaction is expected close during this year’s fourth quarter or in first-quarter 2020, subject to Roan stockholder approval, regulatory approvals, and other customary closing conditions.
Roan Resources LLC was formed in the second quarter of 2017 by Linn Energy Inc. and Citizen Energy II LLC (OGJ Online, June 17, 2017). In September 2018, Linn and Roan Holdings LLC agreed to combine their respective 50% equity interests in Roan Resources LLC into a publicly traded company, Roan Resources Inc., as part of a master reorganization agreement (OGJ Online, Sept. 18, 2018).
Chevron sets new greenhouse gas reduction goals
Chevron Corp. has established new goals to reduce its net greenhouse gas (GHG) emission intensity. The company intends to lower upstream oil net GHG emission intensity by 5-10% and upstream natural gas net GHG emission intensity by 2-5% from 2016 to 2023.
The metrics apply to all upstream Chevron oil and natural gas, whether Chevron has operational control or not, the company said in a press statement.
The new reduction goals build on other actions Chevron is taking to address climate change by lowering the company’s carbon intensity, increasing its use of renewable energy and investing in breakthrough technologies. Earlier this year, the company established reduction goals for methane emission intensity and flaring intensity.
EP Energy files petitions under Chapter 11
EP Energy Corp., a Houston independent with programs in the Eagle Ford, Permian, and Northeastern Utah areas, filed voluntary petitions under Chapter 11 reorganization in the US Bankruptcy Court for the Southern District of Texas.
The process will allow the company to pursue a reduction in debt to improve its long-term position, said Russell Parker, EP Energy president and chief executive officer, who said the company’s business operations are expected to continue without interruption throughout the process.
The company ended this year’s second quarter with $52 million in cash, $355 million in borrowings outstanding on the RBL Facility, and $27 million in letters of credit, resulting in $299 million of available liquidity and $4.6 billion of net debt. Subsequently, on Aug. 1, EP Energy borrowed $268 million under its RBL Facility.
“The company has reached an agreement in principle on a comprehensive restructuring with a number of its key creditors but made the decision that the protection of Chapter 11 would help the parties get the deal over the finish line,” Parker said. Over the coming days and weeks, he said, the company will work with creditors and stakeholders to propose a plan of reorganization.
In connection with the Chapter 11 filing, EP Energy has filed several customary motions with the court seeking authorization to support its operations while the process continues, including authority to continue to make payments to lessors and royalty owners in the ordinary course of business, including those payments that were made prior to Oct. 4. The company also expects to pay vendors in full for goods and services provided on or after Oct. 4.
Looney to succeed Dudley as BP chief
Bernard Looney will become group chief executive and a director of BP PLC in February, succeeding Bob Dudley, who will retire at the end of March.
Looney is now chief executive, upstream, responsible for worldwide exploration, development, and production. He joined BP in 1991 as a drilling engineer and has held operating positions in the North Sea, Vietnam, and the Gulf of Mexico.
After working with BP Alaska, he became head of the group chief executive’s office and worked for John Browne and Tony Hayward, Dudley’s predecessor.
Dudley has worked 40 years with BP and Amoco Corp., which BP acquired in 1998. He was appointed group chief executive in October 2010, when the company was reeling from the Macondo disaster in the Gulf of Mexico in April of that year.
Among earlier roles, he served as president and chief executive officer of the Russian joint venture TNK-BP during 2003-08.
Lamar McKay is departing his position as deputy group chief executive to serve as chief transition officer.
Exploration & Development Quick Takes
CNPC exits South Pars 11 project off Iran
State-owned Petropars Co. of Iran will develop Phase 11 of giant South Pars gas field alone following withdrawal from the project by China National Petroleum Corp.
The Chinese company had been designated operator after Total SA exited the project in August 2018. Total acted in response to reinstatement of sanctions against the Islamic Republic after the US withdrew the preceding May from the 2015 Joint Comprehensive Plan of Action (JCPOA) addressing Iranian nuclear development.
When Total signed the South Pars 11 contract with National Iranian Oil Co. in July 2017, it became the first western company to return to Iran after the lifting of international sanctions under the JCPOA (OGJ Online, July 3, 2017).
CNPC suspended investment in South Pars 11 last December. Bijan Zangeneh, Iran’s minister of petroleum, announced the company’s withdrawal from the contract on Oct. 6.
“The fate of the South Pars Phase 11 has been determined, and Petropars will continue developing the project alone,” he told reporters, according to the official Shana News Agency.
South Pars 11 is to produce 2 bcfd of gas and 80,000 b/d of condensate. The original contract covers two platforms with 12 wells each. A later contract is planned for pressure-booster platforms for which Petropars, a unit of NIOC, is believed to need international assistance.
Total to spud Isabella wildcat off UK
Total E&P North Sea UK Ltd. this month will spud an exploratory well on the Isabella prospect in the Central UK North Sea, reports Delek Group, whose wholly owned subsidiary Ithaca Energy Inc. holds a 10% revenue interest.
The 30/11a-7 (Isabella-1) well will test Triassic Joanne and Judy sands. The Joanne is the primary target. The well is to be drilled to 5,380 m in 80 m of water about 260 km offshore.
Other revenue interests are Neptune E&P UKCS, 50%; Total, the operator, 30%; and Edison Euro Oil Exploration, 10%.
BOEM announces region-wide OCS gulf lease sale
The US Department of the Interior’s Bureau of Ocean Energy Management announced plans to hold a Gulf of Mexico region-wide oil and gas lease sale on Mar. 18, 2020, offering 78 million acres. Lease Sale 254, which would include all unleased areas in federal waters in the gulf that are not subject to congressional moratorium, will be the sixth held under the 2017-22 federal OCS leasing program, BOEM said in a press statement.
Excluded from the lease sale are blocks adjacent to or beyond the US Exclusive Economic Zone in the area known as the northern portion of the Eastern Gap and whole blocks and partial blocks within the current boundaries of the Flower Garden Banks National Marine Sanctuary.
The 2017-22 program calls for 10 region-wide sales in the gulf where resource potential and industry interest is high and oil and gas transportation systems are well established, officials said. Two region-wide sales will be held each year and will include all available blocks in the combined western, central, and eastern gulf planning areas.
The Gulf of Mexico Outer Continental Shelf, covering about 160 million acres, is estimated to contain 48 billion bbl of undiscovered technically recoverable oil and 141 tcf of undiscovered technically recoverable natural gas.
FAR acquires additional block interests off Gambia
FAR Ltd., Perth, has acquired an additional 10% interest in the prospective exploration Blocks A2 and A5 offshore Gambia in West Africa. FAR now has a 50% working interest and operatorship. PC Gambia Ltd., a subsidiary of Malaysian national company Petronas, has the other 50%.
The permits lie directly south and on trend with the SNE oil and gas discovery offshore Senegal in which FAR also has an interest. Samo-1, an earlier well drilled by FAR on Block A2, was plugged as a dry hole, but it did find oil shows at several levels indicating the potential presence of an active hydrocarbon system.
FAR said it had since conducted extensive geotechnical studies that have led to the identification of additional target intervals to those mapped prior to the drilling of Samo-1.
FAR said the Gambian government has issued two licenses such that the A2 and A5 permits now have a 3-year initial exploration period plus two optional extension periods of 2 years each.
There is a commitment to drill one well in the first 2 years on either block and to acquire 450 sq km of 3D seismic in the first 3 years. A signature bonus of $4.5 million has been paid for the two licenses. A 3D survey is planned late this year to further delineate some newly identified prospects. The next well is planned for 2020.
Drilling & Production Quick Takes
Hibernia oil production restarting again
Production is resuming at Hibernia oil field offshore Newfoundland and Labrador after a second shutdown forced by an oil release, reports Hibernia Management & Development Co. Ltd., the operator.
Output ceased on July 17 after a spill from a storage cell. The Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) estimated size of the release at 12,000 l.
The second spill occurred on Aug. 17 as production was restarting when an estimated 2,194 l. of oil overflowed from a drain tank (OGJ Online, Aug. 19, 2019).
Average production from the field was 125,000 b/d in June, according to the C-NLOPD.
Hibernia Management & Development shareholders are ExxonMobil Canada (33.125%), Chevron Canada Resources (26.875%), Suncor (20%), Canada Hibernia Holding Corp. (8.5%), Murphy Oil (6.5%), and Equinor Canada Ltd. (5%).
Johan Sverdrup comes on stream in Norwegian North Sea
Johan Sverdrup field Phase 1 production came on stream Oct. 5 on Utsira High in the Norwegian North Sea. Production is expected to ramp up quickly with eight production wells already drilled or in the process of being drilled, reported project partner Lundin Petroleum AB.
A field center consists of four platforms—drilling, processing, living quarters, and riser platform. Phase 1 plateau production of 440,000 b/d is expected by mid-2020.
Equinor AS operates Johan Sverdrup with 42.6% interest. Partners are Lundin Norway AS 20%, Petoro AS 17.36%, Aker BP ASA 11.57%, and Total SA 8.44%.
Johan Sverdrup field has recoverable reserves of 2.7 billion boe (95% oil, 3% dry gas, the remainder NGL). The field has a production capacity of 660,000 b/d after Phase 2 comes onstream in fourth-quarter 2022 (OGJ Online, Sept. 3, 2019).
Lundin Petroleum said Johan Sverdrup at its peak is expected to produce 25% of all petroleum production on the Norwegian Continental Shelf.
Johan Sverdrup is being operated with electricity supplied from shore and is expected to be one of the lowest carbon dioxide emitting fields worldwide. CO2 emissions are expected to be less than 1 kg/bbl, about 25 times less than the world average.
Post-Phase 1 plateau, field operating costs are expected to be less than $2/bbl and the full-field breakeven oil price is forecast at less than $20/bbl.
Johan Sverdrup—the third-largest oil field on the NCS by reserves—lies on Blocks 16/2, 16/3, 16/5, and 16/6 about 155 km west of Karmoy and 40 km south of Grane field. The field was proven by Lundin in 2010 through well 16/2-6 (Avaldsnes).
Oxy to use solar for EOR work in Permian basin
Occidental Petroleum Corp. has started a solar facility to power an enhanced oil recovery operation in the Permian basin’s Goldsmith field in Ector County, Tex.
Through its Oxy Low Carbon Ventures (OLCV) subsidiary, Oxy also announced it signed a long-term power purchase agreement for 109 Mw of solar energy beginning in 2021 for Permian operations.
The solar facility expands on Oxy’s commitment to lower its carbon footprint by using emissions-free power for operations. Oxy said the 120-acre field is the first large-scale solar facility of its kind to directly power oil and gas operations in Texas.
It features 174,000 photovoltaic panels with a total capacity of 16 Mw. First Solar manufactured the photovoltaic panels and is under contract with OLCV to operate the facility.
OLCV also recently signed a 12-year solar power purchase agreement with a joint venture between Macquarie’s Green Investment Group and Core Solar LLC, whose solar project in West Texas will be operational in 2021.
Oxy of Oman has signed a memorandum of understanding with GlassPoint Solar, Fremont, Calif., for the possible use of steam raised with solar energy for injection in Mukhaizna heavy oil field in south-central Oman (OGJ, Nov. 14, 2018).
Previously, Chevron Corp. generated steam from its solar-to-steam project for EOR at Coalinga heavy oil field in Kern County, Calif. (OGJ Online Nov. 7, 2011).
PROCESSING Quick Takes
JV formed to produce IMO 2020-compliant marine fuels
Freepoint Commodities LLC and Rigby Refining LLC have signed definitive contracts to form a joint venture to develop processing plants around the world to help meet the growing demand for International Marine Organization (IMO) 2020-compliant marine fuel.
The JV’s first project will be the design and construction of a 10,000-b/d fuel oil processing plant in the US Gulf Coast. The facility will be equipped with Rigby’s proprietary process to remove sulfur from fuel oil and produce low-sulfur, IMO 2020-compliant marine fuel, the companies said.
While Freepoint did not reveal a precise USGC location for the manufacturing site, the company did confirm it will provide the feedstock to and market production from the plant, which is scheduled for start-up sometime in 2021.
Beginning in 2020, the IMO will require that marine bunkers contain no more than 0.5 wt % sulfur. The current maximum is 3.5 wt % outside “emission control areas,” where the sulfur limit since 2015 has been 0.1 wt %.
DRPIC lets contract for Duqm refinery
Duqm Refinery & Petrochemical Industries Co. LLC (DRPIC), Muscat—a joint venture of state-owned Oman Oil Co. and Kuwait Petroleum Corp. subsidiary Kuwait Petroleum International Ltd.—has let a contract to Galfar Engineering & Contracting SOAG, through a contractor, for work on DRPIC’s long-planned 230,000-b/d refinery and petrochemical complex to be built in the Duqm Special Economic Zone in Duqm, Al Wusta Governate, on Oman’s southeastern coast (OGJ Online, Oct. 8, 2018).
As part of the $59.9-million contract, Galfar will deliver mechanical, electrical, instrumentation, and piping fabrication works for Saipem SPA’s subpackages A and C for the refinery’s off-site facilities, the service provider said.
Galfar is scheduled to complete its scope of work on the contract in late November 2020.
The contract falls under DRPIC’s award to a consortium of Saipem and McDermott International Inc. (formerly CB&I) of engineering, procurement, and commissioning Package 3, covering EPC, commissioning, and operation services for the project’s associated off-site installations, including a product storage and export terminal at Duqm Port, a crude tank farm at Ras Markaz, and an 80-km crude oil pipeline from Ras Markaz to the refinery complex (OGJ Online, Feb. 15, 2018).
The Duqm refinery will include units for hydrocracking, hydrotreating, delayed coking, sulfur recovery, hydrogen generation, and Merox treating. With more than 25% of the nearly $6-billion project now completed, DRPIC said it hopes to launch preliminary test runs at the site by yearend 2021.
TRANSPORTATION Quick Takes
First unit at Elba Island liquefaction project starts up
The first of 10 liquefaction units at the $2-billion Elba Liquefaction Facility at Elba Island near Savannah, Ga., is in service, said Elba Liquefaction Co. LLC (ELC). The 51-49 joint venture of Kinder Morgan Inc. and EIG Global Energy Partners, respectively, said progress is being made on the remaining nine units.
Previously only an LNG import terminal, the facility is now also able to produce LNG for export. With the first unit in service, the company is now earning 70% of the expected total daily revenue of the liquefaction units.
Start-up activities are under way on the second and third units, the commissioning of units four through six is ongoing, and construction on the remaining units is largely complete, ELC said. Under full development, the Elba project is expected to have a total capacity of 2.5 million tonnes/year of LNG for export.
ELC will own the liquefaction units and other ancillary equipment. Certain other facilities associated with the project are wholly owned by KMI. The project is supported by a 20-year contract with Royal Dutch Shell PLC, who is subscribed to 100% of the liquefaction capacity (OGJ Online, July 16, 2015).
DOE okays Eagle Jacksonville LNG project exports
The US Department of Energy issued an order on Oct. 4 that approves exports of US-produced LNG from the proposed Eagle Jacksonville project along the St. Johns River in Jacksonville, Fla. Ultimately owned by Ferus Natural Gas Fuels LP, the project plans to export small-scale amounts of LNG, serve the US market, and provide LNG as a shipping fuel, DOE said.
DOE said the order gives Eagle LNG authority to export as much as 0.14 bcfd of gas as LNG from the proposed operation by ocean-going vessel or by International Organization for Standardization container to any country with which the US does not have a free-trade agreement requiring national treatment for gas trade, and with which trade is not prohibited by US law or policy.
The US Federal Energy Regulatory Commission gave Eagle LNG authorization to site, construct, and operate the Eagle Jacksonville project in September (OGJ Online, Sep. 23, 2019).
DOE noted that including this announcement, it has approved 34.66 bcfd of exports in the form of LNG and compressed natural gas to non-FTA countries. Of this approved amount, about 15 bcfd is in various stages of operation and construction, it said.