OGJ Newsletter
GENERAL INTEREST Quick Takes
ExxonMobil reports first quarter loss of $610 million
Exxon Mobil Corp. estimated a first quarter 2020 loss of $610 million compared with earnings of $2.4 billion a year earlier (OGJ Online, Apr. 26, 2019). Results included a $2.9 billion charge from identified items reflecting noncash inventory valuation impacts from lower commodity prices and asset impairments. Cash flow from operating activities was $6.3 billion. Capital and exploration expenditures were $7.1 billion.
Oil-equivalent production was 4 million b/d, up 2% from first-quarter 2019, with a 7% increase in liquids partly offset by a 5% decrease in gas. Excluding entitlement effects and divestments, oil-equivalent production was up 5% from the prior year, with upstream liquids production up 9% on growth in the Permian basin and Guyana. Permian production grew 20% from fourth quarter 2019 and was up 56% from the first quarter of 2019.
In April, the company announced plans to reduce its 2020 capital spending by 30% and cash operating expenses by 15% (OGJ Online, Apr. 7, 2020). Capex is now expected to be $23 billion for the year, down from previous guidance of $33 billion.
Norwegian authorities to implement production cuts
Authorities will cut Norwegian oil production by 250,000 b/d in June, and by 134,000 b/d in this year’s second half help hasten the oil price recovery following a steep, sudden drop in oil demand.
A “more rapid stabilization of the oil market” than the market mechanism alone could ensure was considered important for sound resource management and the Norwegian economy at large, according to a Norwegian Petroleum Directorate statement Apr. 30.
The Norwegian Petroleum Directorate assisted the Ministry of Petroleum and Energy in its work on the production regulation.
In addition to the production cuts, said Minister of Petroleum and Energy Tia Bru in a statement, start of production on multiple fields will be postponed to 2021. “Overall Norwegian production in December 2020 will amount to 300,000 [b/d] lower than the companies had planned. This regulation will cease at the end of the year.”
The cut will be distributed across individual fields and will be carried out by issuing revised production permits. Companies will be consulted before revised production permits are issued.
This cut is based on a reference production of 1,859,000 b/d of oil. A cut of 250,000 b/d in June 2020 thus yields an upper limit for oil production on the Norwegian shelf of 1,609,000 b/d in June.
A cut of 134,000 b/d in the year’s second half will yield an upper limit for average oil production from the Norwegian shelf during that time of 1,725,000 b/d.
Cuts apply to Norwegian oil production, thus, some fields—including gas and condensate fields, transboundary fields, and mature fields in a late phase—are exempt.
Beach Energy accused of invalid contract termination
Beach Energy Ltd., Adelaide, has been accused by US drilling company Diamond Drilling Inc. of an invalid termination of its drilling contract for the Ocean Onyx semi-submersible to drill in the offshore Otway basin.
Beach said that Diamond Drilling has filed a voluntary Chapter 11 petition in the US bankruptcy court in the Southern District of Texas and at the same time filed the complaint in that court seeking a determination that the drilling contract with Beach remains valid. Diamond is seeking damages, the amount to be determined at trial.
Beach said it denies the claim and will defend any action suggesting that the contract was not validly terminated.
Last week Beach said that the Ocean Onyx had arrived in Victorian waters in mid-April, but that date was later than had been agreed and specified in the contract. The company exercised its right to terminate the agreement (OGJ Online, Apr. 20, 2020).
Despite the commencement of legal proceedings, Beach said it is still engaged in “without prejudice discussions” with regard to the future operations of the Ocean Onyx and the company’s Victorian Otway basin drilling program.
Beach added that offshore drilling is unlikely to begin until the financial year 2021.
Diamond Drilling has five of its deep-water rigs in Australasian waters, including Ocean Monarch and Ocean Onyx.
Johan Castberg components en route to Singapore
The turret mooring system (TMS) for Equinor’s Johan Castberg floating production, storage, and offloading (FPSO) vessel is en route to Singapore for integration into the vessel’s hull. Drydocks World Dubai fabricated all four TMS modules under contract with SBM Offshore.
The first two modules, the bogie support structure and lower turret, arrived in Singapore late 2019 and early 2020. The manifold and gantry modules were completed and safely loaded for transport in mid-April 2020 with delivery to the Singapore yard planned for May.
The turret is an 8,000-ton bogie turret accommodating 21 riser slots for the new-build Johan Castberg FPSO, which will develop Skrugard, Havis, and Drivis discoveries in the Barents Sea, offshore Northern Norway. The FPSO will be permanently moored in 372-m water depth by means of three bundles of five mooring lines.
Johan Castberg’s recoverable resources are 450-650 MMboe, according to the Norwegian Petroleum Directorate. The development is in PL 532 about 240 km northwest of the Melkoya LNG plant in Hammerfest and 100 km north of Snohvit field.
Johan Castberg license partners are Equinor (50%), Vår Energi (30%), and Petoro (20%).
Exploration & Development Quick Takes
Repsol makes two discoveries in deepwater Mexico
Repsol made significant deepwater Mexico oil discoveries with Polok-1 and Chinwol-1 exploration wells in Block 29 in the Salina basin. Both wells confirmed high quality reservoirs with excellent properties, and consortium partners will evaluate all data for the discoveries’ appraisal plan, to be submitted to Mexico’s hydrocarbons regulator CNH before yearend.
The discoveries were drilled by Maersk’s Valiant deepwater drillship 12 km apart and 88 km from the Mexican coastline of Tabasco, in 600 m water.
The Polok-1 exploration well was drilled to 2,620 m total depth and encountered more than 200 m net oil pay from two zones in the lower Miocene. The Chinwol-1 exploration well was drilled to 1,850 m total depth and encountered more than 150 m net oil pay from three zones in the lower Pliocene.
Wireline formation testing performed on both wells showed good flow capacity in multiple stations along the Miocene and Pliocene reservoir units.
Repsol recently received approval from CNH to drill the company’s third deep water exploration in Block 10, offshore Veracruz, also to be spudded by Valiant.
Block 29 consortium partners are Repsol (30%, operator), PC Carigali Mexico Operations, the Mexican subsidiary of Petronas(28.33%), Wintershall DEA (25%), and PTTEP México E&P Ltd. (16.67%).
BW Energy delays new development offshore Gabon
BW Energy Ltd. may delay final installation of DTM-6H in the Dussafu Marin license, offshore Gabon, due to the COVID-19 pandemic. Completed in March, the well was to be hooked up to FPSO BW Aldo in June. COVID-19 restrictions also have suspended drilling of DTM-7H and the subsequent exploration well.
The delays come as part of the company’s first quarter financial and operating results, and on the heels of the previously reported plan to defer Ruche Phase 1 development (OGJ Online, Mar. 19, 2020).
BWE’s total revised capital spending program for 2020 now amounts to $115 million, of which about $49 million was spent as of the end of March. Net cash flow from operating activities for the first quarter was $49.8 million and total available liquidity was $168.3 million in cash with no debt as of Mar. 31.
Dussafu daily production from four wells (DTM-2H, DTM-3H, DTM-4H and DTM-5H) to the FPSO BW Adolo is currently 17,500 b/d (gross) compared to 11,800 b/d on average in 2019. Projected Dussafu daily production for 2020 is 15,000 - 16,500 b/d.
Gross production from Tortue averaged 11,485 b/d for first quarter 2020 and total gross production of 1.05 million bbl of oil. BW Energy share of gross production was 768,150 bbl of oil.
Production activities in Gabon remain uninterrupted.
Novatek registers Bukharinskiy license area for LNG production
Arctic LNG 1, a wholly owned subsidiary of Novatek, intends to begin full-scale geological and geophysical activities in the Bukharinskiy subsoil license area on the Gydan Peninsula of the Yamal-Nenets Autonomous Region and begin drilling of the first exploratory well in the upcoming exploration 2020-2021 season following registration of license SLH 16637 NR.
Terms of the license, which was obtained up to 2050, stipulate that the resource base should be used for LNG production at gas liquefaction facilities located in the YNAO and the adjacent water area.
The license, partially in the shallow waters of the Ob and Taz bays, lies near the Artic LNG 1’s Geofizicheskiy and Trekhbugorniy license areas and Soletsko-Khanaveyskoye field (OGJ Online, Sept. 3, 2019). The Bukharinskiy license area has estimated hydrocarbon resources of 1,190 billion cu m of natural gas and 74 million tons of liquids, or 8.4 billion boe, according to the Russian resource classification system.
Drilling & Production Quick Takes
International rig count down 144 units in April
The international rig count for April reached 915, a decrease of 144 units from March and down 147 units from the 1,062 counted in April 2019, according to Baker Hughes data (OGJ Online, Apr. 3, 2020).
The international offshore rig count for April was 228, down 16 units from March, and down 23 units from the 251 counted in April 2019.
The worldwide rig count for April was 1,514, down 450 units from the 1,964 counted in March, and down 626 units from the 2,140 counted in April 2019.
The average US rig count for April was 566, down 206 from March, and down 446 from the 1,012 counted in April 2019.
Europe was down 11 units with 112 in April and up 14 units year-over-year. Effective June 7, 2019, Ukraine has been added to the Baker Hughes International Rig Count.
Latin America is down 80 units from the previous month with 89 units and down 101 units year-over-year.
The Asia-Pacific region is down 40 with 191 units month-over-month and down 45 units from its year-ago average.
The Middle East down 8 units month-over-month at 420 and up 8 units year-over-year.
The average Canadian rig count for April was 33, down 100 units from the 133 counted in March, and down 33 units from the 66 counted in April 2019.
Cabot to drill 60 to 70 wells in 2020
Cabot Oil & Gas Corp. expects to drill, complete and produce 60 to 70 natural gas wells in 2020, with two-thirds placed on production between mid-May and late August. In the first quarter, the company drilled 22 wells and completed 13.
Details were provided as part of the company’s financial and operating results for first-quarter 2020.
First quarter daily production was 2,363 MMcfed (100% natural gas), a 4% increase relative to first quarter 2019.
Second quarter production guidance is 2,175-2,225 MMcfed. The decline is primarily driven by lighter turn-in-line schedule during the first 4 1/2 months of the year with only 13 wells on production between the beginning of the year and mid-May, a consequence of longer cycle times for larger pads with longer laterals during first and second quarters. Additionally, forecasts show modest price-related curtailments during natural gas shoulder season. The second quarter guidance also reflects impact of unplanned downtime related to remedial work on one well on a large pad which deferred over 230 completed stages from first quarter to the second, leading to lower first quarter capital spending.
Full-year production guidance has decreased to 2,350-2,375 MMcfed from 2,400 MMcfed to reflect the above operational changes. “The midpoint of our updated production guidance range implies flat production levels year-over-year, with fourth quarter 2020 exit volumes expected to be flat to the fourth quarter of 2019,” said Dan O. Dinges, chairman, president, and chief executive officer.
Net income for first quarter 2020 was $53.9 million compared to $204.9 million in first quarter 2019. First quarter 2020 adjusted net income was $54 million compared to $307.8 million in the prior-year period. First quarter 2020 net cash provided by operating activities was $204.9 million compared to $585.3 million in the prior-year period.
Cabot has reaffirmed its 2020 capital program of $575 million.
Mubadala to curtail 2020 Manora field activities
Mubadala Petroleum (Thailand) Ltd. and Tap Oil Ltd. have cancelled or deferred noncritical 2020 expenditure originally planned for Manora oil field, Thailand.
The 2020 Manora work program and budget has been reduced by $14 million, said partner Tap Oil as part of its first quarter report. A $3.9 million (gross) exploration well and $7.3 million (gross) in operating capital and workover costs were cancelled. Up to $2.8 million in capital expenditures were deferred until 2021. Further initiatives are underway to optimize cashflow.
The partners are working to identify further infill drilling opportunities to maintain Manora production and have undertaken extensive technical analysis on a three well 2020 development drilling and workover program. Choice of wells, drilling locations, volumes, and risks have been evaluated and the partners are considering economics, cost, production optimization, and risk mitigation opportunities before making a final investment decision.
Manora field lies in the G1/48 concession, Gulf of Thailand, in 44 m of water about 80 km from the coast. It is estimated to hold 20 million bbl (gross). First quarter 2020 production averaged 5,536 b/d, at least 5.0% above the partners’ base 2020 plan.
Mubadala is operator with 60% interest. Partners are Tap Energy 30% and Northern Gulf Petroleum 10%.
PROCESSING Quick Takes
Equatorial Guinea, Marathon let contract for modular refinery
Equatorial Guinea’s Ministry of Mines and Hydrocarbons (MMH) and strategic partner Marathon Oil Co. have let a contract to VFuels LLC, Houston, to execute the feasibility study for construction of a modular crude oil refinery in Punta Europa, Malabo, on Bioko Island.
As part of the study—which is scheduled to be completed within 12 weeks of the contract’s signature—VFuels will deliver engineering and design of the proposed 5,000-b/d modular refinery to supply finished products for consumption by Equatorial Guinea’s domestic market, the African Energy Chamber (AEC) said on Apr. 23.
The refining project comes as part of MMH’s initiative of the Year of Investment 2020, which is seeking investments for a modular refinery and storage tanks in the continental region, as well as promotion of other projects derived from methanol, among others.
The contract award, for which no value was disclosed, follows MMH’s December 2019 order for dismantling of a methanol plant owned by Atlantic Methanol Production Co. LLC at the Punta Europa gas complex—owned by Marathon Oil 45% as well as partners Noble Energy Inc. 45% and Sociedad Nacional de Gas de GE SA 10%—and its conversion into a modular crude oil refinery (OGJ Online, Dec. 19, 2019).
MMH’s late-2019 order was followed a January 2020 meeting between the government of Equatorial Guinea and Marathon Oil executives at which the parties agreed both to the refining project and an immediate start to feasibility studies related to methanol gasoline and derivatives, AEC said.
Viva Energy cuts back Geelong refinery operations
Viva Energy Australia will cut back production from the Geelong refinery, 50 km west of Melbourne, citing COVID-19 restrictions and the precipitous fall in demand for its petroleum products.
It is shutting down its residual catalytic cracking unit and one of its crude distillation units in May. One other crude distillation unit and all other processing units will remain operational; however, Viva will reduce its refining intake by about 2.5 million bbl/month.
The Geelong refinery is the second largest in Australia. Formerly owned by Royal Dutch Shell, it was part of the package of Shell’s downstream operations in Australia bought by Viva’s parent, the privately-owned Swiss trading company Vitol Group, in August 2014.
Part of the deal was that the Shell brand would be retained and Melbourne-based Viva Energy Australia became the exclusive distributor of Shell products throughout the country.
Viva said it would use the closure to bring forward major maintenance work at Geelong refinery which was originally scheduled to begin for August through October.
Financial impact of the cutbacks will be minimal given the current low refinery margins, the company said. The refining margin for the March quarter was down to $2.7/bbl with an intake of 10.8 million bbl.
Retail fuel sales at the end of March had fallen by around 40%, while aviation fuel demand had dropped by 90% as a result of the COVID-19 travel restrictions.
Sasol lets contract for South African downstream assets
Sasol Ltd. has let a contract to John Wood Group PLC to serve as an engineering partner under a 5-year partnership framework agreement to support Sasol South Africa (Pty) Ltd.’s portfolio of assets—including its refining and chemicals businesses—across South Africa.
As part of the agreement, Wood will provide integrated services to Sasol ranging from feasibility studies and front-end engineering design through to engineering, procurement, and construction as part of Sasol’s plan to maximize efficiency and drive long-term sustainability of its operations, Wood said on Apr. 29.
Wood will execute yet-to-be-identified projects under the agreement from its South African regional office and on-site project teams with support from the service provider’s global capital projects and technical consulting teams.
A value of the contract was not disclosed.
Sasol’s South African downstream businesses include the Sasol-Total SA jointly owned National Petroleum Refiners of South Africa (Pty) Ltd. (Natref) 108,000-b/d refinery in Sasolburg, South Africa, as well as its wholly owned Secunda Synfuels Operations (SSO), which is the world’s only commercial coal-based synthetic fuels manufacturing site to synthesis gas (syngas) through coal gasification and natural gas reforming. Both the Natref and SSO operations have experienced interruptions amid reduced regional demand resulting from measures aimed at reducing the spread of coronavirus (COVID-19).
TRANSPORTATION Quick Takes
Freeport LNG Train 3 begins commercial operation
Freeport LNG Development LP’s liquefaction plant on Quintana Island in Freeport, Tex., began commercial operation of its 4.64-million tonne/year (tpy) Train 3.
Final commissioning was reached in March (OGJ Online, Mar. 10, 2020).
Zachry Group, as Freeport’s contracting joint-venture lead, partnered with McDermott International Inc. for the project’s pre-front end engineering and design (FEED) in 2011, followed by FEED work for Trains 1 and 2. Chiyoda International Corp. joined the joint venture for work related to Train 3. Project scope includes three pre-treatment trains, a liquefaction plant with three trains, a second loading berth, and a 165,000-cu m full containment LNG storage tank.
The Freeport LNG facility, now in full commercial operation, incorporates the largest electric motor-driven refrigeration compressors in the world.
Freeport last year received US Federal Energy Regulatory Commission approval for Train 4 (OGJ Online, May 17, 2019), which will increase total capacity to 20 million tpy. Train 4 is expected to start operations in 2023.
Midcoast awards Siemens CJ Express expansion contract
Midcoast Energy LLC awarded Siemens Gas and Power a contract to supply two SGT-400 gas turbine compression packages for its 150-mile, 36-in. OD CJ Express pipeline expansion project in east Texas. WHC Energy Services, supported by Universal Pegasus International, will be the engineering, procurement, and contracting (EPC) provider for the pipeline expansion project.
Siemens Gas and Power will supply two SGT-400 mechanical-drive compression packages capable of producing a total of 39,000-hp for an expansion at an existing compression station. The SGT-400 gas turbines will be built at the company’s plant in Olean, NY. The first gas turbine compression trains will be shipped later in 2020 to support the planned early-2021 start of commercial operations by CJ Express.
Midcoast in February 2020 entered into definitive, long-term anchor shipper agreements in support of CJ Express, which adds compression and pipeline to Midcoast’s existing East Texas pipeline system. The expansion will increase gathering capabilities in the Shelby trough area of the Haynesville shale and increase Midcoast’s Clarity pipeline capacity to Gulf Coast demand centers to about 1 bcfd.
CJ Express will begin in San Augustine County, Tex., and run south to an interconnect with Clarity in Hardin County, Tex. (OGJ Online, Feb. 26, 2020).