GENERAL INTEREST Quick Takes
ConocoPhillips to acquire Concho Resources for $9.7 billion
ConocoPhillips has agreed to an all stock deal to acquire Concho Resources for $9.7 billion. Including Concho’s net debt of $3.9 billion, the deal value is $13.6 billion.
The new ConocoPhillips will be the largest independent oil and gas company, with pro forma production of over 1.5 MMboe/d, the companies said in a joint release Oct. 19. Estimated resource base of the combine is some 23 billion boe with a less than $40/bbl WTI cost of supply and an average cost of supply below $30/bbl WTI, the companies said.
The transaction brings together contiguous and complementary acreage positions across the Delaware and Midland basins and includes positions in the Eagle Ford and Bakken in the Lower 48 and the Montney in Canada.
The companies expect to capture $500 million of annual cost and capital savings by 2022 from lower general and administrative costs and a reduction in ConocoPhillips’ future global new ventures exploration program. The de-emphasis of ConocoPhillips’ organic resource addition program is driven by the addition of Concho’s large, low-cost resource base, the companies said. Additional supply chain, commercial and drilling and completion capital efficiency savings are not yet included in the cost-reduction estimates.
The combine will target an average reinvestment level of less than 70% of cash from operations “to ensure sufficient free cash flow generation to fund compelling returns of capital to shareholders,” the companies said.
Upon closing, subject to the approval of both ConocoPhillips and Concho stockholders, regulatory clearance, and other customary closing conditions, Concho’s chairman and chief executive officer Tim Leach will join ConocoPhillips’ board of directors and executive leadership team as executive vice-president and president, Lower 48.
The transaction is expected to close in first-quarter 2021.
Under terms of the deal, approved by the board of directors of each company, each share of Concho common stock will be exchanged for a fixed ratio of 1.46 shares of ConocoPhillips common stock.
Pioneer to acquire Parsley in $4.5-billion deal
Pioneer Natural Resources Co. agreed to acquire Parsley Energy Inc. in an all-stock transaction valued at $4.5 billion as of Oct. 19, 2020. The total value, inclusive of Parsley debt assumed by Pioneer, is $7.6 billion.
The combined Permian exploration and production company will hold some 930,000 net acres with no federal acreage and a production base of 328,000 b/d of oil and 558,000 boe/d as of second-quarter 2020. Based on yearend 2019 proved reserves, the deal increases Pioneer’s proved reserves by 65%.
The combine is expected to result in annual cost savings of $325 million through operational efficiencies and reductions in general and administrative and interest expenses with the expected present value of the savings exceeding $2 billion over a 10-year period, the companies said. Operational savings are expected to be driven by the utilization of shared facilities, overlapping operations, scale efficiencies, and benefits provided by Pioneer’s water infrastructure. Further synergies are expected from adjacent acreage footprints and the ability to drill extended laterals.
Under the terms of the agreement, Parsley shareholders will receive a fixed exchange ratio of 0.1252 shares of Pioneer common stock for each share of Parsley common stock owned. Pioneer will issue about 52 million shares of common stock in the transaction. After closing, existing Pioneer shareholders will own about 76% of the combined company and existing Parsley shareholders will own about 24%.
The deal has been approved by the boards of both companies and is expected to close in first-quarter 2021, subject to customary closing conditions, regulatory approvals, and shareholder approvals. Parsley’s largest investor, Quantum Energy Partners, executed a Voting and Support Agreement in connection with the transaction.
Upon closing, Pioneer’s board of directors will be expanded to 13 to include Matt Gallagher, Parsley’s president and chief executive officer, and AR Alameddine, Parsley’s lead director. Pioneer’s executive management team will lead the combine with the headquarters remaining in Dallas, Tex.
Lundin to acquire Barents Sea portfolio from Idemitsu
Lundin Energy AB subsidiary Lundin Energy Norway AS agreed to acquire from Idemitsu Petroleum Norge AS (IPN) interests in a portfolio of Barents Sea licenses, including a 10% working interest in the Wisting oil discovery and a further 15% working interest in the Alta oil discovery.
The Wisting discovery, in licenses PL537 and PL537B with estimated gross resources of 500 million bbl of oil, is scheduled to be one of the next Barents Sea production hubs. Equinor, as operator of the development phase, is targeting a PDO by end 2022 to benefit from temporary tax incentives (OGJ Online, Dec. 2, 2019).
With the deal, Lundin would increase its interest holding as operator of licenses PL609, PL609B, and PL609D, containing the Alta discovery, to 55% from 40%. Acceleration of Alta development to benefit from tax incentives is being assessed (OGJ Online, Sept. 25, 2018).
Additionally, Lundin Energy increases its working interests in licenses PL609C and PL851, raising the company’s working interest in the operated Polmak exploration well to 47.5% from 40%. Polmak is the first of three high impact exploration prospects to be drilled by the company in the Barents Sea during fourth-quarter 2020, which are targeting gross unrisked prospective resources of over 800 million bbl of oil. Polmak will be drilled by the West Bollsta semi-submersible drilling rig, with spud expected in early October 2020.
The deal, with an effective date of January 2020, adds estimated net contingent resources of 70 MMboe for a cash consideration of $125 million, and is subject to approval of the board of Idemitsu Kosan Co. Ltd. (the parent company of IPN) and Norwegian regulatory approvals.
Exploration & Development Quick Takes
ExxonMobil, Sonangol to explore Namibe basin potential
Angola’s National Oil, Gas and Biofuels Agency (ANPG), ExxonMobil, and Sonangol signed three agreements extending prospecting and exploration activities to Namibe basin, an unexplored area offshore Angola. The agreements increase the exploration area over 17,800 sq km in the previously unexplored maritime zone. Activity was previously limited to the Congo and Kwanza basins.
Deepwater blocks 30, 44, and 45 lie 50-100 km from the coast in water depths of 1,500-3,000 m.
ExxonMobil is operator of the blocks with 60% interest. Sonangol holds 40%.
Tyra redevelopment enters new phase following jacket installation
Redevelopment of Tyra field in the Danish North Sea moves to a new phase following installation of two new jackets, partner Norwegian Energy Co. ASA (Noreco) said Sept. 28.
The remainder of the Danish Continental Shelf project will focus on yard fabrication and offshore installations to rebuild the new Tyra. Wellhead and riser modules are currently being built in Singapore, the accommodation module in Italy, and the process module in Indonesia.
The jackets, confirmed safely installed according to plan, were fabricated by Dragados Offshore SA in Spain. The jackets form the foundation for the new Tyra process and accommodation platforms and are the first new jacket structures delivered and installed for the redevelopment project. The past year has mainly involved safeguarding of the wells and wellhead jackets, and the decommissioning and removal of the old Tyra modules.
Tyra field is the largest gas condensate field in the Danish sector of the North Sea. Its facilities process more than 90% of the gas produced in Denmark, as well as the entire gas production of the Danish Underground Consortium (DUC) comprised of operator Total 43.2%; Noreco 36.8%, and Nordsøfonden 20%.
Due to seabed subsidence, the field required redevelopment, and in September 2019 production was temporarily shut in. Redevelopment will replace gas processing and accommodation platforms on Tyra East and Tyra West with a new processing platform and a new accommodation platform.
Jackets will be extended by 13 m on four wellhead platforms and two riser platforms, and topsides will be replaced.
When back in operation, Tyra will reach peak production of 60,000 boe/d. With the use of new technology and modernized working processes Tyra’s operating efficiency is expected to increase, and at the same time reduce CO2 intensity by 30%.
Lukoil proceeds with Filanovsky field phase two development
Lukoil has launched Phase 2 of the development drilling campaign of the Offshore Ice-Resistant Fixed Complex 2 (OIRFC 2) at Vladimir Filanovsky field in Astrakhan, Russia, the company said Oct. 9. The second phase aims to keep oil production at the planned rate of 6 million tonnes/year.
Vladimir Filanovsky field is the largest offshore oil field in Russia’s sector of the Caspian Sea. Commissioned in 2016, the field reached annual planned production level in 2018.
Lukoil has invested more than $9 billion into development of the fields in the Russian sector of the Caspian Sea.
Both independently and as part of a joint venture, Lukoil has discovered 10 fields in the Caspian Sea with C1+C2 ultimate recoverable hydrocarbon reserves of 7 billion boe.
Drilling & Production Quick Takes
TPAO increases reserves at Black Sea Sakarya field
Türkiye Petrolleri Anonim Ortaklı˘gı (TPAO) raised estimated gas reserves in Sakarya field, Western Black Sea, based on data from the Tuna-1 ultra-deepwater exploration well.
Drilled with TPAO’s Fatih 6th generation drillship in 2,117 m of water in Block AR/TPO/KD/C26-C27-D26-D27, the well reached total depth of 4,775 m and encountered an additional 30 m gas-bearing reservoir in Early Pliocene-Late Miocene sands.
The additional sands raised estimated lean gas reserves from 320 billion cu m (11 tcf) in the original discovery announcement to 405 billion cu m (OGJ Online, Aug. 21, 2020). The field is the largest in the Black Sea and one of the largest 2020 gas finds in the world, the operator said.
TPAO plans to drill two back-to-back appraisals with Fatih. The Kanuni drillship will carry out well tests. A pre-FEED agreement has been signed for concept selection to produce first gas by early 2023.
TPAO has 100% equity in the block.
Petrosibir to drill two exploration wells in Baskkiria
Petrosibir entered into an agreement to drill two exploration wells on the Suyanovskoye license block adjacent to its Ayazovskoye oil field in the Russian republic of Bashkiria. Multiple exploration prospects exist on the 300-sq km license area, the company said.
The first well will be drilled on the Yanbayskaya structure in the southwestern part of the license and is expected to be completed by yearend. The second will be drilled on the Orlinskaya prospect in the eastern part of the block with completion expected in second-quarter 2021.
Each well will target multiple horizons including Bobrikovsky and Kyn-Pashyisky. Preparatory work has been completed and the drilling rig is set up.
The Suyanovskoye license is a combined exploration and production license. Oil company Bashneft currently produces oil from neighboring fields Shimskoye, Kungakskoye, and Islamovskoye. Some 15 wells were drilled in the license area during the Soviet era, and oil was encountered in layers from the Carboniferous period. None drilled as far down as the Devonian period, from which Petrosibir is producing oil on the neighboring Rustamovskoye block, indicating further potential, according to the company web site.
Petrosibir has collected seismic data at Suyanovskoye field and identified three structures. The oil resources are estimated at 47 million b/d. Previously conducted helium studies on the field indicate the presence of hydrocarbons and an active petroleum system, according to the company web site.
Geoservice LLC will finance drilling in exchange for 49% interest in the license. Petrosibir is financing all preparatory works such as pad and road construction, permitting documentation, and water supply. Future work, including wells testing, production infrastructure, seismic and new drilling, will be funded in accordance with the 51-49 equity split. Petrosibir retains an option to buy out Geoservice’s interest within 12 months after drilling is completed.
PROCESSING Quick Takes
Phillips 66 restarts Lake Charles refining complex
Phillips 66 has restarted operations at its 249,000-b/d Lake Charles refining complex in Westlake, La., as well as other area midstream installations, following preemptive shutdowns ahead of Hurricane Delta’s Oct. 9 landfall along the US Gulf Coast in southwestern Louisiana (OGJ Online, Oct. 12, 2020).
With reliable electricity supply restored to all of the company’s assets in the Lake Charles area as of Oct. 15, the Lake Charles refining complex and nearly all midstream assets have now resumed operations as planned, Phillips 66 said.
The operator previously said it was working with its local provider to reinstate necessary power supplies to enable operational restarts of all regional assets by the week ending Oct. 17 (OGJ Online, Oct. 14, 2020).
Restart of the Louisiana assets follows Phillips 66’s safe and controlled shutdown of process units at the Lake Charles complex, Gulf Coast Lubricants Plant, and Lake Charles-area terminals and pipelines on Oct. 7 in preparation for Hurricane Delta, which initial post-storm assessments indicated left only minimal damage at the sites.
Hurricane Delta also prompted Phillips 66 to temporarily delay its previously proposed early-October restart of the Lake Charles refining complex after completion of works to repair damages sustained at the site as a result Hurricane Laura’s Aug. 27 landfall in the region as a Category 4 storm (OGJ Online, Sept. 23, 2020).
Planned maintenance activities brought forward to mid-September from October remain under way at Phillips 66’s 255,000-b/d Alliance refinery on the Mississippi River in Belle Chasse, Plaquemines Parish, La., about 25 miles southeast of New Orleans, following the refinery’s shutdown ahead of Hurricane Sally, which made landfall near Gulf Shores, Ala., on Sept. 16 as a Category 2 storm (OGJ Online, Sept. 16, 2020).
Lytton refinery facing closure
Ampol’s Lytton oil refinery in Brisbane, Queensland, is facing permanent closure despite a recent federal government proposed $2.5 billion (Aus.) fuel security package for the refining industry.
The Lytton plant has recorded a $82 million (Aus.) loss for the September quarter bringing its total losses to $141 million (Aus.) so far this year.
Ampol chief executive Matt Halliday said the refinery operation will be subjected to a comprehensive review by the June quarter next year. The review will consider a number of options including a complete shutdown and a conversion of the site into a fuel import terminal. It will take account of the government package as well as the potential impact on employees and suppliers.
Halliday told news outlets that Ampol appreciated the intent of the proposed government support package, but the company needed to be realistic about the extreme structural challenges that are facing the Lytton operation.
The news comes as Viva Energy considers a shutdown of its Geelong refinery near Melbourne in Victoria while the other two refiners—BP at Kwinana in Western Australia and ExxonMobil at Altona in Melbourne—have reduced production.
The industry is reeling from the COVID-19 pandemic that has caused precipitous falls in demand for aviation fuel and petrol.
Three Australian refineries have closed in the last decade, increasing the country’s reliance on imported petrol and diesel supplies to meet demand.
Lukoil lets contract for Burgas refinery
PJSC Lukoil has let a contract to Lummus Technology LLC’s Lummus Novolen Technology GMBH to provide technology licensing for a grassroots petrochemical unit to be built at subsidiary Lukoil Neftochim Burgas AD’s 139,000-b/d integrated refining and petrochemical complex on the Balkan peninsula, about 15 km from Burgas, Bulgaria.
As part of the contract, Lummus will license its proprietary Novolen gas-phase polypropylene (PP) technology for a new 280,000-tonnes/year PP unit at the refinery, as well as deliver basic design engineering, training and services, and catalyst supply for the project, the service provider said on Oct. 8.
Lummus disclosed no details regarding a value of the contract or a timeframe for its work on the proposed project.
Award of the contract for the proposed PP unit follows Lukoil’s completion of feasibility studies in 2019 for PP production projects at both the Burgas refinery and subsidiary LLC Lukoil Nizhegorodnefteorgsintez’s (NNOS) 337,100-b/d Kstovo refinery in central Russia’s Nizhny Novgorod region, the company said in its latest annual report to investors.
In September, Lukoil also let a contract to Lummus Novolen Technology to license technology and deliver associated services for NNOS’s PP unit (OGJ Online, Sept. 10, 2020).
The PP units at Burgas and Kstovo will use a feedstock of propylene produced by the refineries’ existing catalytic cracking units, according to Lukoil.
Tatneft advances modernization of Minnebayevo gas plant
PJSC Tatneft’s Tatneftegazpererabotka (UTNGP) is adding a new unit as part of an ongoing modernization program at its Minnibayevo gas processing plant (MGPP) in Tatarstan’s Almetyevsk region.
Recently approved for its permit to build, the project includes construction of a normal butane (n-butane) processing unit and associated off-site installations within the boundaries of the existing MGPP complex, Tatneft said.
The new n-butane unit will be equipped with the capacity to process 50,000 tonnes/year of n-butane into solid maleic anhydride, which is used to produce polymers used in the food, textile, pharmaceutical, and cosmetic industries, according to the operator.
Scheduled for commissioning in 2023, the n-butane unit comes as part of a broader upgrading program at the MGPP complex, which also includes the proposed reconstruction of a cryogenic unit for deep processing of dry stripped gas (DSG).
Alongside enabling deep processing of DSG, the cryogenic unit revamp—due to be completed in December 2023—also will increase the site’s depth of ethane fraction recovery the calorific value of carbon dioxide, as well as reduce the volume of hydrocarbons in nitrogen-containing gas, allowing the complex to reduce the amount of hydrocarbon emissions into the atmosphere by about 42%, Tatneft said.
The MGPP modernization program is part of Tatneft’s renewed focus on its gas processing and petrochemical operations given the current situation in the petroleum market, according to Azat Bikmurzin, director of Tatneft’s petrochemicals business.
TRANSPORTATION Quick Takes
Mountain Valley receives FERC permit, extension
Mountain Valley Pipeline LLC has received US Federal Energy Regulatory Commission (FERC) permission to resume construction of its 303-mile, 2-bcfd natural gas pipeline through West Virginia and Virginia. FERC also granted a 2-year extension for completion of the pipeline, through Oct. 13, 2022.
The previous stop-work order, issued in October 2019, remains in place for 25 miles through Jefferson National Forest and adjacent land in Virginia. The US Forest Service still needs to approve construction through federal woodlands.
In the meantime, environmental groups, including The Sierra Club, have petitioned the 4th US Circuit Court of Appeals to review US Army Corps of Engineers permits issued last month for crossing of streams and wetlands along the pipeline’s route, saying that they were issued unlawfully and asking they be stayed until the court hears the case.
EQM Midstream Partners LP owns a 45.5% operating interest in Mountain Valley with affiliates of NextEra Energy Inc., Consolidated Edison Inc., AltaGas Ltd., and RGC Resources Inc. owning the balance.
Jemena plans Eastern Gas pipeline extension
Jemena plans to extend its Eastern Gas Pipeline (EGP) from Sydney, Australia, to the Hunter Valley region in northern New South Wales (NSW).
The existing EGP pipeline runs 797 km from Victoria’s Bass Strait gas field hub at Longford up the east coast to Sydney and Canberra and is capable of transporting about 360 terajoules/day. The proposed extension would add 185 km to the line.
The company expects to make a final investment decision on the $400 million (Aus.) extension project by end 2021 with first gas by early 2023.
Jemena also is proposing to modify the pipeline to transport more gas to NSW and move gas bi-directionally between NSW and Victoria.
The proposal will connect the Hunter Valley to existing domestic gas fields as well as emerging new gas sources, said Frank Tudor, managing director. The latter include a proposed LNG import terminal at Port Kembla and a second proposed import terminal at Newcastle.
Jemena recently noted a proposal to construct a 6 km pipeline to connect the proposed Port Kembla LNG import facility to the EGP.
Plans include a modification of the EGP so that it can deliver more than 200 terajoules/day of gas from NSW into the Victorian market, at the same time being able to supply up to 450 terajoules/day to NSW.
