GENERAL INTEREST Quick Takes
ExxonMobil plans $17-billion after-tax impairment
ExxonMobil completed a review of its forward business plans and said it will prioritize near-term capital spending on assets with the highest potential future value and work toward additional expense management.
Near-term capital spending will be allocated to developments in Guyana and the US Permian basin, targeted exploration in Brazil, and chemicals performance products. The company expects $16-19 billion in capital and exploration expenditures in 2021. Thereafter, annually through 2025, spending plans were reduced to $20-25 billion from $30-35 billion.
Certain assets have been removed from the development plan and an after-tax impairment of $17-20 billion is expected in this year’s fourth quarter, the company said in a news release Nov. 30.
Assets removed from the company’s development plan include certain dry gas resources in the Appalachian and Rocky Mountains, Oklahoma, Texas, Louisiana, and Arkansas in the US, and in western Canada and Argentina. The resulting non-cash, after-tax fourth quarter impairment charge estimate is slightly less than the $25-30 billion the company noted around its third quarter earnings.
The company said it expects to exceed planned 2020 cost savings of $10 billion and work toward additional expense management, including business line reorganizations and a global workforce reduction of 15% by yearend 2021. The reduction reiterates plans already noted by the company, including a cut to US jobs primarily impacting management offices in Houston, Tex. (OGJ Online, Oct. 29, 2020).
The company announced an estimated third-quarter 2020 loss of $680 million, compared to net earnings of $3.17 billion for the prior year’s third quarter.
Headwater acquires Marten Hills oil assets
Headwater Exploration Inc. has closed a deal to purchase Marten Hills area assets from Cenovus Energy Inc., Alberta. Headwater acquired a 100% working interest in 2,800 b/d of medium gravity oil production (average 22˚ API) and 270 net sections of Clearwater play rights. Total land acquisition is 189,000 acres with 172,800 acres with Clearwater rights. Marten Hills lies 250 km north of Edmonton, Alta.
In November, Headwater noted a 2021 preliminary pro forma outlook that included expected capital expenditures of $60-70 million (Can.) and average production of 6,000-6,500 boe/d (90% oil). Headwater has committed to spend $100 million on the acquired lands by Dec. 31, 2022.
Headwater said it plans to continue Cenovus’ efforts to de-risk the 250 sections of exploration acreage. The six historical exploration wells drilled by Cenovus have established four potential development areas, which Headwater intends to follow-up on using a methodical delineation approach.
Total consideration paid by Headwater consists of $35 million (Can.) in cash, 50 million common shares, and 15 million purchase warrants exercisable at $2.00/common share with a 3-year term.
As a result of the transaction, Cenovus owns, through Cenovus Marten Hills Partnership, 50 million Headwater shares representing 25.6% of the company’s issued and outstanding common shares. Including the common shares issuable if the warrants are fully exercised, Cenovus would own 65 million Headwater shares representing 30.9% of the company’s issued and outstanding shares.
Chevron sets $14 billion budget for 2021
Chevron Corp. set a 2021 organic capital and exploratory spending budget of $14 billion and lowered its 2022-2025 annual capital guidance to $14-16 billion.
The company will continue to prioritize investments that are expected to grow long-term value and deliver higher returns and lower carbon, including over $300 million in 2021 for investments to advance the energy transition, it said in a Dec. 3 media release.
Chevron’s 2022-2025 capital guidance is significantly lower than its previous guidance of $19-22 billion, which excluded Noble Energy. During this time period, as capital is expected to decrease for a major expansion in Kazakhstan, the company expects to increase investments in the Permian basin, other unconventional basins, and the Gulf of Mexico.
In the upstream business, $6.5 billion is allocated to currently producing assets, including about $2 billion for Permian unconventional development. Some $3.5 billion of the upstream program is planned for major capital projects underway, of which about 75% is associated with the Future Growth Project and Wellhead Pressure Management Project (FGP/WPMP) at Tengiz field in Kazakhstan (OGJ Online, Apr. 15, 2020). The remaining $1.5 billion is allocated to exploration, early stage development projects, and midstream activities.
Drilling & Production Quick Takes
Aker advances Hod redevelopment with approval
Aker BP received approval Dec. 8 from the Ministry of Petroleum and Energy for its plan to redevelop Hod field in the Valhall area in the North Sea.
The operator submitted its plan for development and operation (PDO) to the authority in June.
Hod lies in Block 2/11 in the southern part of the Norwegian sector of the North Sea, some 12 km south of Valhall Central Complex, 6 km south of the Valhall Flank South platform. It is being developed with a normally unmanned installation that will be remotely operated from Valhall. Total project investments are estimated at 5.7 billion kroner. Production start is expected in first-quarter 2022.
Steel jacket and topsides are currently under construction at Kværner’s yard in Verdal and will be transported to the field as early as summer 2021.
To date, Aker BP has awarded 100 contracts worth over 1 million kroner for construction of the Hod B platform.
Aker BP is operator with 90% interest. Pandion Energy holds the remaining 10%.
CGX delays offshore Guyana exploration
CGX Energy Inc. rescheduled exploration activities in Corentyne block, offshore Guyana. Subject to documentation, the government of Guyana is expected to extend by 1 year the deadline to drill the next well to Nov. 27, 2021.
The joint venture identified two potentially highly prospective large channel sand reservoir complexes from recently processed 3D seismic data in the northern region of the block. This region is near Stabroek block, Guyana, and Block 58, offshore Suriname. The prospects, mapped within the Upper Cretaceous, Santonian, and Miocene intervals, are primarily stratigraphic traps composed of sandstone accumulations and deemed analogous to many of the discoveries in Guyana basin spanning both Guyana and Suriname.
The Corentyne block covers 1.125 million net acres in shallow water. During 2012 drilling to assess Corentyne’s potential, CGX found water-bearing sandstones with hydrocarbon shows in the Eagle-1 wildcat. CGX then owned 100% of the license.
CGX is operator in Corentyne with joint venture partner Frontera Energy.
OGDCL discovers gas in Balochistan Province
Oil and Gas Development Co. Ltd. (OGDCL), Islamabad, discovered gas from exploratory well Lakhirud X-1 in Musa Khel District, Balochistan Province, Pakistan.
The well was drilled to a depth of 3,000 m and tested at 2.5 MMscfd of gas and 18 b/d water through a 32/64-in. choke at 600 psi well head flowing pressure from the Mughal Kot formation.
OGDCL is operator and 100% owner of Lakhirud exploration license.
Drilling & Production Quick Takes
Vaalco acquires seismic to support Etame Marin drilling
Vaalco Energy Inc. has acquired nearly 1,000 sq km of new dual-azimuth proprietary 3-D seismic data over the entire Etame Marin block, offshore Gabon, to support the next drilling campaign scheduled for late 2021 or early 2022.
Subsurface imaging will be enhanced by combining the newly acquired seismic with legacy data to produce the first continuous 3-D seismic over the entire block, the company said Dec. 7. The data will be used to optimize and derisk future drilling locations and potentially identify new drilling locations.
Processing of the data is expected to begin in January 2021 with all data expected to be fully processed and analyzed by fourth-quarter 2021. Cost for acquisition and processing will be $14-16 million gross.
Vaalco is operator of Etame with 33.6% interest (31.1% working interest). In November, Vaalco agreed to acquire Sasol Gabon SA’s 27.8% working interest in the block. At closing, the deal will bring Vaalco’s total working interest to 58.8%.
Obsidian to reinitiate Cardium development drilling
Obsidian Energy Ltd. has increased its 2020 capital program by $3.2 million to $56 million (Can.) to reinitiate its light oil Cardium development program with plans to begin drilling activity on the first pad within its Central Alberta Willesden Green asset.
While the company expects to finalize the size and scope of its first-half 2021 development program over the coming weeks, it will begin drilling on a three well pad in early December.
The asset produced 20,661 boe/d as of third-quarter 2020.
BPC plans Trinidad, Tobago, Suriname work program
Bahamas Petroleum Co. PLC (BPC) expects to produce 2,500 b/d at an extraction cost of less than $20/bbl after a comprehensive 2021 work program in Trinidad, Tobago, and Suriname.
The base program will consist of two appraisal wells, up to two production wells, and two exploration wells, subject to permitting. Production and potential development could be further accelerated with an additional 11 production wells and one extra exploration well.
Drilling of Saffron #2 appraisal in Saffron field, Trinidad, will start in February 2021 with up to seven production wells to follow through 2021. Also in February 2021, an appraisal will be drilled and tested in Weg Naar block in Suriname. Wider field development with up to six production wells will follow through 2021.
By end-2021, reprocessing of the entire 3D seismic grid will be completed over the South West Peninsula (SWP) of Trinidad, high-grading Saffron lookalike prospects for drilling, with up to two initial exploration wells.
Depending on technical outcomes, speed of permitting approvals, and rig and funding availability, an accelerated 2021 work program could include up to a further eight Saffron production wells in Trinidad and Tobago, up to a further three Weg naar Zee production wells in Suriname, and one further exploration well in the SWP.
Expected capital expenditure is up to $20 million for the base work program and up to $35 million if all developments and exploration activities are accelerated.
PROCESSING Quick Takes
Sinochem starts up ethylene plant at Quanzhou complex
Sinochem Quanzhou Petrochemical Co. Ltd., a wholly owned subsidiary of Sinochem Group Co. Ltd., has commissioned its previously announced ethylene expansion project as part of the initial stage of the operator’s second-phase development of its 12-million tonnes/year (tpy) integrated refining complex entered into service in June 2014 at Quanhui Petrochemical Industrial Park, Hui’an County, in Quanzhou City, Fujian Province, on the southeast coast of mainland China (OGJ Online, Mar. 27, 2019; July 10, 2014).
Equipped with KBR’s proprietary Selective Cracking Optimum Recovery (SCORE) technology and SCORE SC-1 furnaces, the new 1-million tpy ethylene plant is now operating, KBR said on Dec. 7.
Commissioning of the new ethylene complex—which actually began in September with startup of the plant’s 400,000-tpy high-density polyethylene (HDPE) unit, followed by a 130,000-tpy butadiene extraction unit, as well as six other units—is part of the first phase of Sinochem Quanzhou Petrochemical’s broader second-phase expansion program at Quanzhou to further increase crude processing capacity, chemical integration, and sophistication of operations at the complex, according to the operator’s website.
Identified broadly as its refining and chemical integration optimization project (RCIOP), Sinochem Quanzhou Petrochemical said the entire 32.5-billion yuan program—a key project in China’s 13th 5-Year-Plan period—includes a nearly 3.5-billion tranche that seeks to expand crude oil processing capacity of the complex by 3 million tpy to 15 million tpy, as well as add the following unit capacities:
- Continuous reforming (including pressure swing adsorption), 2.6 million tpy.
- Aromatics extraction, 1.4 million tpy.
- Hydrocracking, 2.2 million tpy.
- Light hydrocarbon recovery, 2.2 million tpy.
- Dry gas desulfurization, 26,300 tpy.
- LPG desulfurization-mercaptans removal; 360,000 tpy.
According to project documents filed with Fujian Province in midyear 2020, Sinopec Engineering Construction Co. Ltd. previously delivered a feasibility study for the entirely of the RCIOP and is delivering engineering and basic design for the bulk of the new units to be added.
The operator has yet to disclose a more specific timeline for the fully proposed RCIOP.
Petroineos to shutter units at Grangemouth refinery
Petroineos Refining Ltd., a joint venture of Ineos AG-formed Ineos Investments (Jersey) Ltd. and China National Petroleum Corp.’s PetroChina Co. Ltd. (PetroChina) subsidiary PetroChina International London Co. Ltd., is planning to permanently shutter two processing units as part of a reconfiguration strategy at Petroineos Manufacturing Scotland Ltd.’s 210,00-b/d Grangemouth integrated refinery complex on the Firth of Forth in Scotland.
Designed to adapt the plant to reflect the global decline in demand for fuels and align its capacity to meet local demand in Scotland, Northern England, and Northern Ireland, the proposed plan aims to mothball the refinery’s crude distillation unit 1 (CDU-1) as well as its FCC unit, both of which have been offline throughout the coronavirus (COVID-19) pandemic, Petroineos said.
The move, which also aims to protect at least 450 jobs of the refinery’s more than 630 full-time employees, comes as the global refining industry faces challenges, including increasing electrification of the transport fleet and more fuel-efficient vehicles that have led to reduced demand for fuel, a trend that has only accelerated this year by the COVID-19 health crisis, according to the company.
Permanent mothballing of the CDU-1 and FCC units will reduce future incurred costs associated with operating the two older plants to ensure a viable, longer-term business, Petroineos said.
While shuttering of one of two CDUs at the Grangemouth refinery—Scotland’s only—will halve the country’s crude processing capacity, Petroineos’s proposed plan seeks primarily to ensure the site’s ongoing sustainability, according to Franck Demay, chief executive officer of Petroineos Refining.
“As a national critical infrastructure, it is vital we retain a productive capacity of fuels in Scotland,” he said.
“For almost a century, the Grangemouth refinery has reliably produced high-quality fuels for the domestic market and for export. We firmly believe that only by taking action now will we preserve one of Scotland’s last large manufacturing sites and a significant contributor to the Scottish economy,” Demay added.
On Nov. 16, Petroineos was scheduled to enter a statutory consultation period with its Grangemouth workforce and their representatives to discuss the proposed refinery reconfiguration plan.
Petrobras advances sell-off of Brazilian refining assets
Petróleo Brasileiro SA (Petrobras) has received binding proposals for the sale of four of its refineries as part of the operator’s program to divest its Brazilian refining and related logistics assets that resumed in March following a previous delay in the process to allow potential buyers enough time to conduct thorough due diligence amid interruptions to normal business operations as a result of the coronavirus (COVID-19) health crisis (OGJ Online, June 25, 2020; Mar. 20, 2020; Jan. 31, 2020).
On Dec. 2, Petrobras confirmed receipt of binding proposals for the following refineries and associated assets:
- The 333,000-b/d Refinaria Landulpho Alves (RLAM) refinery and related assets—including four storage terminals and a set of pipelines totaling 669 km—in the Recôncavo Baiano region of Bahia.
- The 46,000-b/d Isaac Sabbá refinery (REMAN)—including a storage terminal—in Manaus, Amazonas.
- The 8,000-b/d Lubrificantes e Derivados de Petróleo do Nordeste (LUBNOR) refinery in Fortaleza, Ceará, which is one of the national leaders in asphalt production, as well as the only plant in Brazil to produce naphthenic lubricants.
- The 6,000-b/d Unidade de Industrialização do Xisto (SIX) unit—including a mine in one of the largest oil shale reserves in the world and a shale processing plant—in São Mateus do Sul, Paraná.
Additionally, Petrobras said it expects to receive binding proposals on Dec. 10 for the 208,000-b/d Refinaria Presidente Getúlio Vargas (REPAR) refinery—with assets that include five storage terminals and a 476-km set of pipelines—in Paraná, as well as the 208,000-b/d Refinaria Alberto Pasqualini (REFAP) refinery—with assets that include two storage terminals and a set of pipelines totaling 260 km—in Rio Grande do Sul.
Delivery of binding proposals for the 130,000-b/d Refinaria Abreu e Lima (RNEST) refinery—which has the potential to double its capacity to 260,000 b/d with startup of a second processing line and includes both a terminal and a 101-km set of short pipelines—in Pernambuco, and the 166,000-b/d Refinaria Gabriel Passos (REGAP) refinery—including a set of pipelines of more than 720 km—in Betim, Minas Gerais, are due in first-quarter 2021, the operator said.
Petrobras, however, did not confirm potential buyers associated with binding proposals for purchase of the refineries.
TRANSPORTATION Quick Takes
APA Group to build new gas pipeline in WA
The APA Group plans to build a 580-km, 304-mm diameter gas pipeline to connect emerging fields in the North Perth basin to the goldfields region in Western Australia.
APA will invest up to $460 million (Aus.) in the new Northern Goldfields Interconnect (NGI), which is scheduled to be operational by mid-2022.
The NGI will form part of the Western Australian gas grid by connecting to APA’s existing Goldfields Gas Pipeline (GGP) that in turn connects to the company’s major Eastern Goldfields network.
This will form an interconnected pipeline network covering around 2,700 km.
The new NGI section of the interconnected grid will add capacity to the overall system as well as increase gas supply options for customers, said Rob Wheals, APA chief executive officer and managing director.
The project could provide a new market for petroleum explorers and producers in the Perth basin such as the Strike Energy-led joint venture at the developing Erregulla gas field.
Turkmenistan to start Afghan TAPI construction in 2021
Turkmenistan in 2021 will begin construction of the 1,125-mile, 33-billion cu m/year Turkmenistan-Afghanistan-Pakistan-India (TAPI) natural gas pipeline in Afghanistan. Turkmenistan plans to complete TAPI’s construction inside its territory this year and then begin work on the line’s Afghanistan segment, according to Foreign Minister Rashid Meredov.
Construction of power transmission and fiberoptic communication lines along TAPI’s route is also nearing completion, according to Turkmenistan’s foreign ministry.
TAPI is laying 56-in. OD pipe from Galkynysh field in Turkmenistan to Fazilka, India, with completion expected in late 2022. This schedule, however, is contingent on the timely completion of work in Afghanistan and the start of construction during 2021 in Pakistan.
The pipeline would run 133 miles in Turkmenistan, 480 miles through Afghanistan (including the cities of Herat and Kandahar), and 512 miles across Pakistan (including Quetta and Multan) before reaching Fazilka at the Indian border.
H-Energy leases Hoegh FSRU for Jaigarh LNG terminal
H-Energy, through its wholly owned subsidiary Western Concessions Private Ltd., has entered into a binding commitment with Hoegh LNG Holdings Ltd. for the supply of its Hoegh Giant floating storage and regasification unit (FSRU) under a 10-year agreement. The vessel will be deployed at its LNG regasification terminal at Jaigarh Port, Ratnagiri district, Maharashtra, India.
The 2017-built Hoegh Giant has storage of 170,000 cu m and has a peak regasification capacity of 750 MMcfd (roughly 6 million tonnes/year). The FSRU will deliver regasified LNG to the 56-km Jaigarh-Dabhol natural gas pipeline, connecting to India’s national gas grid, and will also deliver LNG to truck racks and provide bunkering.
Jaigarh LNG plans to commission its regasification terminal in March 2021. It will be India’s first FSRU-based LNG terminal, according to H-Energy. The company also plans to develop retail LNG and compressed natural gas (CNG) stations across India to enhance their use as transportation fuel.
