GENERAL INTEREST Quick Takes
Southwestern Energy to acquire Indigo Natural Resources for $2.7 billion
Southwestern Energy Co. has agreed to acquire Haynesville shale producer Indigo Natural Resources LLC for $2.7 billion.
The deal adds to Southwestern Energy’s northeast and southwest Marcellus assets, increases high-return dry gas inventory with 149,000 net acres and some 1,000 locations in the gassy Haynesville, increases net production to over 4 bcfed (about 85% natural gas), and expands 2022 estimated margins by 12% resulting from low cost access to premium markets in the growing Gulf Coast LNG corridor, the company said in a statement June 2.
Indigo is one of the largest private US natural gas producers, with core dry gas assets across the stacked pay Haynesville and Bossier zones in northern Louisiana. Indigo currently produces 1.0 bcfd net and expects to produce 1.1 bcfd net upon closing. As of Mar. 31 and adjusted for the sale of its Cotton Valley assets, Indigo had $631 million of net debt and a leverage ratio of 1.1 times.
Total consideration of $2.7 billion will be comprised of $400 million in cash, $1.6 billion in SWN common stock, and $700 million of assumed 5.375% senior notes due 2029.
Southwestern expects to invest at maintenance capital levels again in 2022, with activity across all its operating areas. On the acquired acreage, the company expects to run a 4-rig program in 2022 to keep production roughly flat at 4.1 bcfd, placing 30-40 wells to sales. With a maintenance capital program, the company projects 14 years of economic inventory at current strip prices across its assets in Appalachia and Haynesville.
Synergies are expected to be $20 million in G&A reductions with further operational and financial cost savings anticipated, the company said.
The deal is expected to increase projected cumulative free cash flow to $1.2 billion from 2021 to 2023.
The deal is scheduled to close in this year’s fourth quarter, subject to regulatory approvals, customary closing conditions, and Southwestern Energy shareholder approval.
Empire Petroleum acquires operated New Mexico oil and gas assets
Empire New Mexico LLC, a subsidiary of Empire Petroleum Corp., Tulsa, has acquired producing oil and gas assets and related gathering assets in Lea County, NM, from ExxonMobil Corp.’s XTO Holdings LLC.
The acquired operated assets are comprised of 700 gross oil, gas, and injector wells and encompass about 40,000 net acres of Permian leasehold. The properties are characterized by high working and net revenue interests, producing some 1,100 net boe/d (67% oil), the company said in a release May 18.
Eunice Monument (EMSU) and Arrowhead Grayburg fields (AGU) lie on the northwestern edge of the Permian basin’s Central Basin Platform in southeastern Lea County, about 15 miles southwest of Hobbs.
Empire believes the assets have current infill drilling and return-to-production well potential.
EMSU field was discovered in March 1929 with most field development occurring in 1934-1937 as the second largest carbonate reservoir in the Texas-New Mexico Permian area. USGS estimates known recoverable efficiency in Eunice field and surrounding satellites near 40% with primary and secondary recovery of an estimated 4.5 billion original oil bbl in place, Empire said. Well development in the EMSU was on 40-acre spacing and the field was produced under primary means until unitization of the field occurred in February 1985 as a secondary waterflood. Productive intervals at Eunice are mostly Queen, San Andres, and Grayburg formations.
With this acquisition Empire operates in five states (Texas, Louisiana, North Dakota, Montana, New Mexico) with an aggregate of over 100,000 net leasehold acres and 1,800 net boe/d.
Comet Ridge awarded new Mahalo permit in Bowen basin
Comet Ridge Ltd., Brisbane, has been awarded a new exploration permit in the Bowen basin of Queensland directly east of its three permits and two production licences in the region.
The 338-sq km permit (ATP 2063), known as Mahalo Far East block, lies northeast of the company’s development-ready Mahalo coal seam gas project.
The award follows that of Mahalo North (ATP 2048) in April 2020 and Mahalo East (ATP 2061) in September 2020. All are owned 100% by Comet Ridge.
The new permit contains a large volume of gas in place and provides significant upside to the Mahalo hub which is close to existing pipeline connections to the Australian east coast gas market, the company said.
Mahalo Far East block also contains conventional sandstone reservoir potential beneath the coal measures that will be explored during appraisal of coal seam gas resources.
Comet has achieved commercial gas flow rates in its initial Mahalo programs, including the Mahalo-7 and Mira-6 lateral pilot wells in two separate pilot areas. The overall project has received environmental approvals and production leases for development.
Lukoil subsidiary becomes sole owner, operator of Wolgodeminoil
Wolgodeminoil, the joint Russian-German joint venture between Wintershall Dea and RITEK, a subsidiary of Lukoil, is to become wholly owned and solely operated by RITEK. Wintershall Dea transferred its 50% interest on May 27.
The transfer has been confirmed by the Russian Federal Antimonopoly Service (FAS).
Wolgodeminoil started production in Zalivnoye field in 2019. To increase efficiency at Molodezhnoye, Avilovskoye, and Dobroye fields, gas-powered CHP units were installed to meet the company’s own electricity needs.
Wolgodeminoil is active in 14 districts of the Volgograd region as well as five districts of the Saratov region and is producing oil and natural gas from 12 fields.
Exploration & Development Quick Takes
ADNOC JV lets contract to progress Belbazem block development
Al Yasat Petroleum Operations Co. Ltd. has let a $744-million contract for full field development of the Belbazem offshore block to the National Petroleum Construction Co. (NPCC). The block, which lies 120 km northwest of Abu Dhabi city, consists of Belbazem, Umm Al Salsal, and Umm Al Dholou fields.
The award is part of ADNOC’s efforts to maximize value from all Abu Dhabi fields as it expands oil production capacity to 5 million b/d by 2030.
The scope of the award covers engineering, procurement, construction, and commissioning activities for offshore facilities required to enable full production capacity of 45,000 b/d light crude with about 35°API gravity and 27 MMscfd associated gas from Belbazem.
The project includes three offshore wellhead towers, one in each of the block’s three fields, interconnecting subsea pipelines, and cables to Zirku Island some 60 km from Belbazem. It also covers development of greenfield facilities for water injection, produced water treatment, gas compression, and associated utilities, as well as brownfield works for tie-in to existing infrastructure at the island.
Leading up to the award, Al Yasat undertook a front-end engineering design (FEED) competition and reduced the originally scheduled tender time by up to 12 months and enabled capex savings of about $190 million (OGJ Online, July 29, 2019). First oil is expected in 2023.
Al Yasat is a subsidiary of Abu Dhabi National Oil Co. and joint venture with China National Petroleum Corp. ADNOC and CNPC hold 60% and 40% stakes in Al Yasat, respectively.
Ithaca Energy lets contract for Captain field EOR project
Ithaca Energy (UK) Ltd. has let an engineering, procurement, construction, and installation (EPCI) contract to TechnipFMC for the Captain enhanced oil recovery (EOR) project in the UK North Sea.
Ithaca Energy sanctioned the Captain field EOR Stage 2 project after receiving field development plan addendum consent from the Oil and Gas Authority (OGJ Online, Apr. 8, 2021).
TechnipFMC will design, manufacture, deliver, and install subsea equipment including a rigid riser caisson, water injection flexible flowline, umbilicals, and associated equipment.
Captain field, in Block 13/22a, lies about 145 km northeast of Aberdeen in the outer Moray Firth in water depths of 105.5 m.
TechnipFMC has valued the contract at $75-250 million.
Captain is operated by Ithaca Energy with 85% interest. Dana Petroleum (E&P) Ltd. holds the remaining 15%.
Equinor, partners select joint development concept for Haltenbanken East
Equinor Energy AS and partners selected a concept for developing six discoveries in a joint unitization project on Haltenbanken in the Norwegian Sea. The development concept is a subsea tie-back to Åsgard B platform, using existing facilities and infrastructure, partner Spirit Energy said in a release May 19.
Haltenbanken East will be developed as a unit between four different licenses. It comprises six discoveries and three prospects with a combined volume in the order of 100 MMboe, mostly gas.
The project will be executed in two phases. In the first phase, six wells will be drilled on five of the discoveries. The second phase includes the last discovery and three prospects, planned to be drilled as sidetracks from existing wells.
The discoveries, said Gunn Gadeholt, asset manager at Spirit Energy, “were basically considered stranded assets–it would not have been economically viable to develop any of them on their own.”
A final investment decision is expected in first-half 2022 with submission of a plan for development and operations (PDO) to Norwegian authorities in second-half 2022.
Equinor is operator in Haltenbanken East (57.7%) with partners Spirit Energy AS (11.8%), Vår Energi AS (24.6%), and Petoro AS (5.9%).
Petrobras lets subsea contract for Santos basin presalt
Petrobras let a contract to Subsea 7 SA for development of Mero-3 field, about 200 km off the coast of Rio de Janeiro, Brazil, in 2,200 m of water in Santos basin presalt.
Contract scope includes engineering, fabrication, installation, and pre-commissioning of 80 km of rigid risers and flowlines for the steel lazy wave production system, 60 km of flexible service lines, 50 km of umbilicals, and associated infrastructure, as well as installation of FPSO mooring lines and hook-up.
Project management and engineering will commence immediately at Subsea 7’s offices in Rio de Janeiro and Paris. Fabrication of the pipelines will take place at Subsea 7’s spoolbase at Ubu in the state of Vitória and offshore operations are scheduled to be executed in 2023 and 2024, using Subsea 7’s fleet of reeled rigid pipelay vessels.
Mero field is owned by the Libra consortium. Petrobras is operator with 40%. Partners are Shell (20%), TotalEnergies (20%), CNPC (10%), and CNOOC Ltd. (10%).
Drilling & Production Quick Takes
Equinor adds well intervention at Martin Linge
Equinor Energy AS exercised an option to add well intervention work at Martin Linge field offshore Norway to the previously agreed work scope for the ultra-harsh environment jack up rig Maersk Intrepid.
The well intervention scope has an estimated duration of 29 days. The firm value of the contract extension is about $9.9 million, including integrated services but excluding potential performance bonuses.
The contract extension is entered under the Master Framework Agreement between Equinor and Maersk Drilling, in which the parties have committed to collaborate on technology advancements and further initiatives to limit greenhouse gas emissions (OGJ Online, Feb. 11, 2021).
Equinor is operator with 70%. Petoro AS holds 30%.
State Gas begins Rolleston West CSG project drilling
State Gas Ltd., Brisbane, has begun drilling the first well at its Rolleston West coal seam gas project in the Bowen basin of southeast Queensland.
Rougemont-1 is the first of two wells that will evaluate the prospective Bandanna coal seams in permit ATP 2062, which was awarded to the company late last year.
The well, on the crest of a plunging nose in the Bandanna formation, has a planned total depth of 800 m and expects to intersect the coals at 500-780 m depth.
Elsewhere the Bandanna coals are commercially viable in the Santos-Gladstone LNG group’s Arcadia Valley production and are the main play in Comet Ridge’s Mahalo development.
State Gas’s two-well program is designed to confirm coal thickness, permeability, and gas content in the license.
After initial evaluation is complete, the wells will be suspended prior to production testing.
Santos starts Bayu-Undan infill drilling
Santos has started the Bayu-Undan Phase 3C infill drilling program offshore Timor-Leste.
The progress marks the first drilling campaign in Bayu-Undan field as Timor-Leste offshore waters, following ratification of the Maritime Boundary Treaty between Timor-Leste and Australia, said Autoridade Nacional do Petróleo e Minerais.
The program comprises three production wells to develop additional natural gas and liquids reserves, extending field life and production from the offshore facilities and the Darwin LNG plant. The infill drilling program will add over 20 MMboe gross reserves.
The wells will be drilled using the Noble Tom Prosser jack up rig. First production is expected in third-quarter 2021.
Santos is operator with 43.4% interest. Partners are SK E&S Co. Ltd. (25%), INPEX Corp. (11.4%), Eni SPA (11%), JERA Co. (6.1%), and Tokyo Gas Co. Ltd. (3.1%).
PROCESSING Quick Takes
Nacero lets new contract for proposed Texas GTG plant
Nacero Inc., Houston, has let a contract to Bechtel Corp. to provide engineering and construction for a newly proposed natural gas-to-gasoline (GTG) plant to be built in Penwell, Ector County, Tex., in the heart of the Permian basin.
As part of the contract, Bechtel will deliver front-end engineering and design (FEED) for the Penwell plant that, once in operation, will be the world’s first gasoline manufacturing plant to incorporate carbon capture, sequestration, and 100% renewable power, the service provider said.
Upon completing the FEED, Bechtel said it will deliver a lump-sum turnkey price proposal for engineering, procurement, and construction (EPC) of the project based on sustainable design and execution to bring about carbon reduction in the supply chain and reduce the carbon footprint of the project during construction.
The proposed $6.5-7.5-billion Penwell GTG plant will use a feedstock of low-cost natural gasoline, biomethane captured from farms and landfills, and mitigated flared gas from the Permian basin to produce 70,000 b/d of finished gasoline component ready for blending to US commercial grades. The second phase of construction, which will take an additional 2 years, will bring plant capacity to 115,000 b/d, according to Bechtel.
The plant’s sequestered CO2 will be transported via an existing on-site pipeline for use in enhanced oil recovery. The plant also will produce blue hydrogen and will receive all of its electricity from renewable sources, much of which will be produced from solar panels colocated with the processing and production installations on the 2,600-acre site, Nacero said.
Construction is slated to begin by yearend, but no timeframe for startup has been disclosed.
Nacero previously entered agreements with Haldor Topsoe AS under which Topsoe will supply its technology and catalysts for the Penwell plant as well as Nacero’s other US GTG plants, which currently include proposed projects in Arizona and Pennsylvania (OGJ Online, Mar. 26, 2020).
Anchorage Investments lets contract for PP unit at proposed Suez complex
Anchorage Investments Ltd. has let a contract to a division of Lummus Technology LLC to provide technology licensing and additional services for a polypropylene (PP) unit to be built at subsidiary Anchor Benitoite’s proposed grassroots petrochemical complex in Suez, Egypt, near the southern boundary of the Suez Canal.
As part of the contract, Lummus Novolen Technology GMBH will license its proprietary Novolen gas-phase PP technology for a new 590,000-tonnes/year PP unit at the complex, as well as deliver basic design engineering, training, catalyst supply, and operator-training simulator services for the project, Lummus said on May 20.
Then Novolen PP plant will produce PP using propylene produced from another unit within the complex, said Dr. Ahmed M. A. Moharram, founder and managing director of Anchorage Investments.
The service provider disclosed no further details regarding a value of the contract or the duration of the project.
This latest contract award follows Anchorage Investments’ award to Honeywell UOP to license C3 Oleflex technology for a propane dehydrogenation plant at the complex that will produce 750,000 tpy of on-purpose, polymer-grade propylene.
Requiring an overall investment of nearly $2 billion, Anchor Benitoite’s proposed petrochemical complex at Suez will house five major installations with various production units equipped to produce a total of 1.75 million tpy of petrochemical products, including propylene, polypropylene, crude acrylic acid, n-butanol, and butyl acrylate, according to Anchorage Investment’s website.
Intended to help Egypt increase its competitiveness and position as a petrochemical hub as well as attract investment, the complex will have deep-sea access to the port and connection to multiple nearby pipelines, enabling product distribution to domestic and global markets, the company said.
TRANSPORTATION Quick Takes
Venture Global LNG launches 1-million tpy CCS plans
Venture Global LNG Inc. plans to capture and sequester carbon at its 10-million tonne/year (tpy) Calcasieu Pass and 20-million tpy Plaquemines LNG plants. The company expects to sequester a total of 500,000 tpy from the two sites. Venture Global anticipates using similar infrastructure to capture and sequester 500,000 tpy from its 20-million tpy CP2 LNG plant once permitted.
Having concluded a comprehensive engineering and geotechnical analysis, Venture Global is launching, subject only to regulatory approvals, a shovel-ready carbon capture and sequestration project, compressing CO2 at its sites and transporting it to saline aquifers where it will be permanently stored.
Venture Global began interruptible service on its TransCameron pipeline in April, which will supply Calcasieu Pass.
Tellurian signs 10-year supply agreement, pushes FID
Tellurian Inc. and Gunvor Singapore Pte. Ltd. signed a 10-year sales agreement for 3-million tonnes/year (tpy) of LNG indexed to a combination of the Japan Korea Marker (JKM) and the Dutch Title Transfer Facility (TTF), netted back for transportation charges. LNG would be delivered free on board from Tellurian’s proposed 27.6-million tpy Driftwood LNG plant near Lake Charles, La.
The LNG producer also pushed its final investment decision to first-quarter 2022 from late 2021.
Tellurian said it intends to market up to 10 million tpy of its 16.6-million tpy Phase 1 on a JKM, TTF, or blended price basis.
The company last year withdrew prefiling for its 2.3-bcfd Permian Global Access pipeline, and has since announced plans to produce its own natural gas. Its only previous sales arrangement was a non-binding heads-of-agreement with Total SE for 1 million tpy, signed before either of these decisions.
The Gunvor agreement will generate about $12 billion in revenue, according to Tellurian.
Cowen & Co. described the moves as “a step back” given that Tellurian “appears [to] now need to secure offtake for the full Phase 1 vs. previously planning to own 40% of the project” (6.6 million tpy), “making FID more challenging.”
Invenergy, BW complete FSRU financing for El Salvador LNG-to-power
Invenergy and BW LNG have closed a $128.3 million package with IDB Invest to finance the floating storage and regasification unit (FSRU) component of their Energía del Pacífico LNG-to-power project in El Salvador. BW Tatiana will be Central America’s first FSRU the project will meet 30% of El Salvador’s energy demand upon its 2022 completion, the companies said.
BW Tatiana, with a regasification capacity of 280 MMcfd, will be permanently moored at the Port of Acajutla, Sonsonate, El Salvador. Invenergy and BW LNG will jointly commission, operate, and maintain the 137,000-cu m storage capacity FSRU.
Regasified LNG will be transported via subsea pipeline to the onshore 378-Mw natural gas-fired power plant. A 44-km, 230 kV electric transmission line will connect the power plant’s output to the Central American Electrical Interconnection System.
Royal Boskalis Westminster NV will install EDP’s pipeline under a turnkey contract that includes dredging and laying roughly 1.8-km of 24-in. OD line from the onshore power plant to the offshore FSRU, and backfilling over the line.