GENERAL INTEREST Quick Takes
Maverick acquires Permian properties from ConocoPhillips
Maverick Natural Resources agreed to acquire certain Permian basin producing properties from ConocoPhillips Co. for $440 million.
The assets to be acquired produced over 11,000 boe/d (50% oil) from the Central Basin Platform and Northwest Shelf of the Permian basin during September 2021. The 144,500 net-acre position spans Andrews and Ector counties in Texas and Eddy and Lea counties in New Mexico and is largely operated and held by production.
The deal—approved by Maverick’s board of directors and majority equity owner EIG Global Energy Partners—will be funded by a fully committed $500 million reserve-based loan provided by JPMorgan Chase Bank, NA, Royal Bank of Canada, Citizens Bank, NA, KeyBank National Association, and KeyBanc Capital Markets Inc.
Pro forma for the acquisition, Maverick’s production exceeded 78,000 boe/d in September 2021, said Chris Heinson, chief executive officer.
Subject to customary closing conditions and funding, the deal is expected to close in second-quarter 2022.
Earthstone to acquire Bighorn Permian for $860 million
Earthstone Energy Inc. has agreed to acquire the assets of privately held Bighorn Permian Resources LLC in a cash and stock deal valued at $860 million.
Earthstone will acquire about 110,600 net acres (98% operated, 93% WI, 99% HBP) in the Midland basin, primarily in Reagan and Irion counties. November 2021 average daily production was 42,400 boe/d (25% oil, 57% liquids).
Bighorn Permian Resources LLC was previously known as Sable Permian Resources. The company merged assets with American Energy - Permian Basin LLC and served as its parent company. Sable and certain of its affiliates filed for bankruptcy in the Southern District of Texas in June 2020 and emerged in February 2021.
The deal increases Earthstone’s existing footprint with 49 gross (35 net) Earthstone-identified drilling locations.
Production is expected to be held flat to moderate growth on an annual basis based on continuously running the four rigs currently operated by Earthstone and Chisholm in the Midland basin and the Delaware basin, respectively.
In December, Earthstone agreed to acquire assets of privately held Chisholm Energy Holdings LLC in New Mexico’s northern Delaware basin (OGJ Online, Dec. 16, 2021).
The $770 million cash portion of the Bighorn deal is expected to be funded with cash on hand and proceeds from a private placement of equity and borrowings under the company’s senior secured revolving credit facility.
Earthstone obtained commitments from existing lenders to increase the borrowing base and elected commitments under its credit facility to a total of $1.325 billion from the current $625 million upon both the anticipated February 2022 closing of the previously announced Chisholm acquisition and the closing of the Bighorn acquisition.
Subject to closing conditions, the deal is expected to close early in this year’s second quarter with an effective date of Jan. 1, 2022.
In 2022, Earthstone expects a capital expenditure budget of $410-440 million. With the two acquisitions, the company plans 2022 production of 76,000-80,000 boe/d (40% oil, 68% liquids).
ExxonMobil to move headquarters as part of continued restructure
ExxonMobil Corp. will move its corporate headquarters to its campus north of Houston from Irving, Tex. as part of a continued restructure. The company also plans to combine its chemical and downstream companies and centralize its technology and engineering service organizations.
Effective Apr. 1, the company will be organized along three business lines—ExxonMobil Upstream Company, ExxonMobil Product Solutions, and ExxonMobil Low Carbon Solutions. They will be supported by a single technology organization, ExxonMobil Technology and Engineering, and other centralized service-delivery groups.
In a Jan. 31 release, the operator said it is on track to exceed $6 billion in structural cost savings by 2023, compared to 2019, driven by savings from the new business structure and measures such as centralizing procurement, digital transformation of processes, and right-sizing programs in 2020. The 2020 measures included a 1,900-employee reduction in its Houston workforce (OGJ Online, Oct. 29, 2020).
Karen McKee, formerly president of ExxonMobil Chemical Company has been appointed to lead ExxonMobil Product Solutions.
Linda DuCharme, formerly president of ExxonMobil Upstream Integrated Solutions and ExxonMobil Upstream Business Development, has been appointed to lead ExxonMobil Technology and Engineering Company.
ExxonMobil Upstream Company will be led by Liam Mallon, formerly president of ExxonMobil Upstream Oil and Gas Company.
The headquarters relocation is expected to be complete mid-2023.
Woodside withdraws from Myanmar
Woodside Petroleum Ltd. will withdraw from all its interests in Myanmar.
Woodside has operated in Myanmar since 2013, conducting a number of exploration and drilling campaigns. The company holds a 40% interest and operatorship in the A-6 joint venture and participating interests in exploration permits AD-1 and AD-8.
Woodside flagged its concern following the State of Emergency declaration in February 2021 when it placed all its business decisions in the country under review. It cited the deteriorating human rights situation.
Woodside completed relinquishment of offshore blocks AD-2, AD-5, and A-4 in 2021 and is in the process of withdrawing from blocks AD-6, AD-7, and A-7.
The company will now begin arrangements to formally exit blocks AD-1 and AD-8, the A-6 joint venture, and the A-6 production sharing contract held with the Myanmar Oil and Gas Enterprise.
Woodside Chief Executive Officer Meg O’Neill said that while Woodside had hoped to develop the A-6 gas resources with its JV partners and deliver energy to Myanmar’s domestic market, there was no longer a viable option for the company to continue its activities, nor other future activities in-country.
Exploration & Development Quick Takes
Beacon Offshore lets contract for Shenandoah development
Beacon Offshore Energy LLC has let a contract to Subsea 7 SA for subsea installation services for the Shenandoah development offshore Gulf of Mexico in water depths up to 6,300 ft.
Shenandoah lies 160 miles off the coast of Louisiana in Walker Ridge Blocks 51, 52, and 53 (OGJ Online, Aug. 26, 2021). It is expected to come online as early as late 2024. Multiple wells are expected to develop an estimated 100-400 million bbl, targeting previously discovered oil-bearing Upper and Lower Wilcox reservoirs.
The project covers the tie-back of four subsea wells to the Shenandoah host infrastructure through a subsea manifold with dual flowlines and risers.
The work scope, valued at $150-300 million by the service provider, includes engineering, procurement, construction, installation (EPIC) and commissioning of the subsea equipment including structures, umbilicals, and production and gas export flowlines.
Subsea 7’s scope also includes the wet tow and hook-up of the semi-submersible FPS to the field and mooring system installation.
Project management and engineering will begin immediately at Subsea 7’s offices in Houston, Tex. Fabrication of flowlines and risers will take place at Subsea 7’s spoolbase in Ingleside, Tex., with offshore operations scheduled for 2024.
Santos JV flows gas to surface in Beetaloo wells
Santos Ltd. has flowed gas to surface from two horizontal wells during an extended test of the Mid-Velkerri B shale reservoir in permit 161 in the Beetaloo subbasin onshore Northern territory.
Results for the Tanumbirini 2H and 3H wells have been encouraging over an initial 30-day period following 11-stage (for T2H) and 10-stage (for T3H) fracture stimulation campaigns, partner Tamboran Resources Ltd. said.
T2H peaked at 4 MMcfd of gas after a weather-related shut-in mid-January. The well has stabilized at a 14-day average of 1.7 MMcfd over a 600 m unoptimized fracture stimulated horizontal section (normalized at 2.6 MMcfd over 1,000 m).
T3H peaked at 10 MMcfd following the same weather-related shut-ins and planned maintenance. The well has stabilized at a 10-day average of 1.5 MMcfd over 600 m unoptimized fracture stimulated horizontal section (normalized at 2.5 MMcfd over 1,000 m).
Incorporating the results from the previous Tanumbirini-1 vertical well with T2H and T3H, Tamboran said it has developed an independent model into optimizing effective fracture stimulation within the Mid-Velkerri B shale formation.
The modelling indicates the shale section can flow more than 5 MMcfd per 1,000 m. The figure was verified by Subsurface Dynamics Inc.
The same modelling is planned to maximize design efficiency of fracture stimulation of the Maverick-1H well to be drilled this year.
The JV will continue the T2H and T3H flow test program to gather more information on the reservoir.
Santos is operator of the permit with 75% interest. Tamboran holds 25%.
Drilling & Production Quick Takes
Neptune increases production at Gjøa
Neptune Energy Norge AS increased production from the Gjøa platform in the Norwegian North Sea by 2 MMboe from 2020 to 2021. Gross production was 42 MMboe in 2021 compared with 40 MMboe in 2020. Most of the production was gas (76%), all of which is exported through FLAGS pipeline to St. Fergus gas terminal in the UK.
The increased production was due mainly to production start-up from the Gjøa P1 infill development in February and Duva field tieback in August 2021 (OGJ Online, Aug. 23, 2021). In addition, production from the tie-back field Vega, operated by Wintershall Dea, and Gjøa field itself, has been better than expected. Estimated reserves on Gjøa have increased by 38% since the plan for development and production was approved in 2007.
The operator expects to bring on stream a fourth tie-in field to Gjøa infrastructure, Wintershall’s Nova field, said the company’s head of Norway operations, Martin Borthne (OGJ Online, May 11, 2020). “In addition, we plan to drill two exploration wells in the area and continue to mature other nearby discoveries and exploration opportunities as tie-in candidates.”
Gjøa has 73.4 total million std cu m original recoverable reserves (14.9 million oil, 40 million gas, and 18.5 million NGL) with 11.1 million (1 million oil, 7.1 million gas, and 3 million NGL) remaining.
Neptune Energy is operator at Gjøa (30%) with partners Petoro AS (30%), Wintershall Dea Norge AS (28%), and OKEA ASA (12%).
Petrobras reduces production targets
Petrobras PBR reduced its 2022-2026 production targets to about 2.6 MMboe/d from its initial forecast of 2.7 MMboe/d in November 2021, reflecting a reduced share of interest by co-participation agreements in Atapu and Sepia fields (OGJ Online Dec. 20, 2021). The agreements are expected to go into effect May 1.
The downward revision is a result of Petrobras’s reduced stake in the fields after losing to a TotalEnergies-led consortium during Brazil’s second transfer-of-rights production sharing auction on Dec. 17. Petrobras exercised its right to hold at least a 30% operating stake in the winning consortium for both fields ahead of the auction.
Atapu, within Block BM-S-11A, started production last year and achieved 160,000 b/d via floating, production, storage, and offloading unit (FPSO) Carioca about 200 km off the coast. A second FPSO is expected to increase overall oil production to around 350,000 b/d.
Sépia, in Block BM-S-24, started production this year with a first FPSO and has achieved a plateau of 180,000 b/d. A second FPSO is expected to increase production to about 350,000 b/d.
Petrobras is operator at Atapu and Sépia PSCs. After the co-participation agreements take effect, it will have 52.5% interest in Atapu with partners TotalEnergies SE (22.5%) and Royal Dutch Shell PLC (25%), and 30% interest in Sépia with partners QatarEnergy Co. (21%), TotalEnergies (28%), and Petronas Co. (21%).
PROCESSING Quick Takes
NSRP clarifies reports alleging lengthy idling of Vietnam’s largest refinery
Nghi Son Refinery & Petrochemical LLC (NSRP) has secured necessary support from its stakeholders to avert any indefinite shutdown of its 200,000-b/d refinery and petrochemical complex in Thanh Hoa Province in Vietnam.
While NSRP did previously seek relevant approvals from joint-venture owners PetroVietnam (25.1%), Kuwait Petroleum Europe BV (35.1%), Idemitsu Kosan Co. Ltd. (35.1%), and Mitsui Chemical Inc. (4.7%) on a plan to idle the refinery beginning in mid-February to help improve immediate funding needs, the partners have agreed to and approved a solution involving a short-term closure that will allow NSRP to maintain operations and sustainability of the refinery without need of a lengthy shutdown, NSRP said in a Jan. 30 release.
Responding to a media reports implying the refinery would remain indefinitely shuttered due to the operator’s financial difficulties, NSRP said those reports were based on unauthorized and confidential business information, as well as assumptions.
NSRP revealed no further details regarding the length of the refinery’s short-term operational suspension or the scope of its funding challenges.
Addressing the media reports separately, PetroVietnam said in a Jan. 26 release that—while refinery continues to operate “relatively stably, producing and selling products that meet market requirements”—overall restructuring of NSRP is now “a necessary and urgent need.”
Specifically, PetroVietnam said NSRP’s “risk of shutting down on Feb. 13…due to serious financial difficulties” does not stem from the Vietnamese state-owned operator’s failure to approve certain provisions of agreements between the partnership, including early payment under a fuel products offtake agreement (FPOA).
While PetroVietnam concedes production, efficiency, and finances of the NSRP JV has been impacted by the rising global demand for renewable energy sources, sharp drops to processing profit margins, and unfavorable market fluctuations resulting from the COVID-19 pandemic, shortcomings in NSRP’s governance—which is operated by “foreign parties”—also has contributed to the JV’s current financial difficulties.
“[A]ccording to [NSRP’s charter, its board of management] is responsible for the efficiency of production and business activities, including the import of crude oil and the operating capacity of the plant,” PetroVietnam said.
NSRP’s decision to voluntarily cancel import of two crude oil tankers in January 2022—which led to the risk of the refinery’s complete shutdown—is the “responsibility of the NSRP executive board, not related to [PetroVietnam’s agreements with NSRP],” according to PetroVietnam.
PetroVietnam said it is in negotiations with foreign capital contributors on the NSRP overall restructuring plan.
Fully commissioned in December 2018, the NSRP processes 100% Kuwaiti crude oil into products for Vietnam’s domestic market (OGJ Online, Dec. 12, 2018).
Pemex completes purchase of Deer Park refinery
Pemex subsidiary Pemex Transformación Industrial (PTI) Norteamérica SA de CV has completed a deal with former 50-50 joint venture partner Shell PLC subsidiary Shell Oil Co. to acquire full ownership of Shell Deer Park Refining LP’s 340,000-b/d refinery in Deer Park, Tex.
As part of the transaction approved by the US Committee on Foreign Investment in late 2021 and finalized on Jan. 20, Pemex purchased the entirety of Shell’s 50.005% interest in the JV for $596 million, plus an additional payment of $325 million to cover hydrocarbon inventory to be valued at the end of January in an estimated range of $300-350 million, Shell and Pemex said in separate releases.
Alongside Pemex’s offer of continued employment to existing refinery employees, Pemex and Shell have entered into certain product offtake and crude supply agreements for Pemex’s now 100%-owned refinery.
The parties also previously agreed to maintain integration and close collaboration between the refining complex and Shell Chemical LP’s Deer Park chemical plant—which Shell will continue to own and operate—to capture synergies and economies of scale for both sites.
Pemex—which held a 49.995% interest in the Deer Park JV since 1993—said full ownership of the Deer Park refinery will enable the state-run operator to help supply the fuels Mexico requires to achieve self-sufficiency in line with Mexican President Andrés Manuel López Obrador business policy to advance the country’s national oil industry, as well as ensure its energy independence and security (OGJ Online, Oct. 19, 2020).
Fully funded by Mexico’s federal Fondo Nacional de Infraestructura (Fonadin), Pemex’s purchase of the Deer Park refining assets required no accrual of additional public debt.
Rosneft lets contract for proposed complex at Ryazan
PJSC Rosneft has finalized a contract award to Maire Tecnimont SPA for delivery of engineering, procurement, and construction (EPC) services on grassroots vacuum gas oil (VGO) hydrocracking complex to be built at Rosneft subsidiary JSC Ryazan Oil Refining Co.’s (RORC) 17.1-million tonnes/year (tpy) refinery in Russia’s Central Federal District, about 200 miles southeast of Moscow (OGJ Online, Oct. 28, 2021).
As part of EPC contract, Maire Tecnimont subsidiaries Tecnimont SPA and MT Russia LLC will provide design, supply of equipment and materials, construction, startup and commissioning, and project finance services for the proposed 40,000-b/d (2.2-million tpy) VGO hydrocracking complex, Maire Tecnimont said on Jan. 26.
The planned complex will enable RORC to increase conversion of heavy VGO volumes from the refinery’s vacuum distillation unit into Russian Class 5 (Euro 6-quality equivalent) gasoline, kerosine, and diesel fuels for Russia’s domestic market, according to the service provider.
Maire Tecnimont—which valued the EPC contract at about €1.1-billion—said a timeline for its duration of work will be defined and disclosed following Rosneft’s final investment decision (FID) on the project and fulfillment of other unidentified conditions.
In a separate Jan. 26 release, Rosneft confirmed it remains in discussion with banks to secure financing for RORC’s VGO complex but did not reveal a timeframe for taking FID.
To be equipped with energy-efficient technologies and equipment that includes an automated control system to help reduce the plant’s carbon footprint, the proposed VGO hydrocracking complex—if realized—will feature hydrocracking units, hydrogen production units, elemental sulfur production units, as well as associated off-site installations.
TRANSPORTATION Quick Takes
Whistler natural gas pipeline extends Midland lateral
Whistler Pipeline LLC is expanding Whistler natural gas pipeline’s Midland basin footprint with a new 36-in. OD lateral extending northwest into Martin County, Tex. The Martin County lateral will lengthen the existing 50-mile Midland lateral by 35 miles and connect to multiple processing sites in the county. The lateral is scheduled to be in service fourth-quarter 2022.
Whistler’s 42-in. OD trunkline runs 450 miles from the Waha header to the Agua Dulce hub in South Texas, transporting as much as 2 bcfd.
The pipeline is owned by a consortium of MPLX LP, WhiteWater Midstream, and a joint venture between Stonepeak Infrastructure Partners and West Texas Gas Inc. It began full commercial service July 1, 2021.
Gastrade takes FID on Greek regasification terminal
Gastrade SA has taken final investment decision (FID) for construction of a 5.5-billion cu m/year LNG regasification terminal in Alexandroupolis, Greece. FID was for the planned Independent Natural Gas System of Alexandroupolis, of which the terminal is a part, and clears the way to start building.
Gas from the terminal, expected to be completed by end-2023, will supply regional markets in southeast Europe. Regasification contracts have been signed for 50% of its capacity.
A 28-km pipeline will connect the floating storage and regasification unit planned for the terminal to the National Natural Gas Transmission System of Greece. Natural gas will then be shipped throughout Greece and Bulgaria and as far afield as Moldova and Ukraine.
Bulgarian-state Bulgartransgaz EAD owns 20% of Gastrade. Greek companies Hellenic Gas Transmission System Operator (DESFA) and DEPA Commercia, Cyprus’ GasLog Ltd., and private individual Asimina‐Eleni Copelouzou also each own 20%.
