GENERAL INTEREST Quick Takes
Southwestern Energy to acquire GEP Haynesville
Southwestern Energy Co. has agreed to acquire private Haynesville producer GEP Haynesville LLC for $1.85 billion, creating a large dual-basin natural gas producer with expanded access to Gulf Coast markets, the company said in a release Nov. 4. The company expects some 65% of its daily natural gas production will be marketed to demand centers along the Gulf Coast.
GEP Haynesville, a joint venture formed by GeoSouthern Haynesville LP and funds managed by GSO Capital Partners LP, acquired Haynesville natural gas assets in northern Louisiana from Encana Oil & Gas (now Ovintiv) in 2015 for $850 million (OGJ Online, Dec. 1, 2015).
Southwestern Energy currently holds over 789,000 net acres in Appalachia spread across Pennsylvania, West Virginia, and Ohio. A 2020 acquisition of Montage Resources Corp. added to the operator’s position in the northeastern US and Haynesville assets were added earlier this year with a $2.7-billion acquisition of Indigo Natural Resources LLC (OGJ Online, Aug. 20, 2020; June 2, 2021). Southwestern Energy’s Haynesville operations span 275,000 net effective acres and 149,000 net surface acres in Louisiana’s Haynesville and Bossier shale reservoirs.
The deal with GEP builds scale in the Haynesville with some 700 MMcfd of production. Once closed, the combine is expected to produce about 4.7 bcfed. In addition, inventory is expected to expand to 700 locations across stacked-pay Haynesville and Middle Bossier.
The deal adds 2.2 tcfe of estimated yearend 2021 proved reserves at projected SEC pricing with expected yearend 2021 total proved reserves of about 20.9 tcfe.
Annual synergies of $25 million from complementary assets are expected.
Total consideration will be comprised of $1.325 billion in cash and some $525 million in Southwestern common shares. As of Sept. 30, Southwestern had total debt of $4.2 billion. After financing the cash consideration of the deal, the company expects its yearend 2021 debt balance to be about $5.4 billion with a leverage ratio of some 2.0x.
The transaction is expected to close by yearend 2021, subject to customary closing conditions.
ExxonMobil plans to increase carbon capture at LaBarge
ExxonMobil initiated the process for engineering, procurement, and construction contracts as part of its plans to expand carbon capture and storage (CCS) at its LaBarge, Wyo. plant.
The proposed $400-million expansion project will capture up to 1 million metric tons of CO2, in addition to the 6-7 million metric tons already captured at LaBarge each year.
The LaBarge expansion project is in the design and permitting phase and a request for bids for engineering, procurement and construction contracts has been issued to third parties. A final investment decision is expected in 2022 and will be based on several factors, including regulatory approvals. Operations could start as early as 2025.
ExxonMobil Low Carbon Solutions is evaluating several other large-scale carbon capture and storage projects in the US Gulf Coast, Europe, and Asia. The company has an equity share in about one-fifth of global CO2 capture capacity and has captured some 40% of all the captured anthropogenic CO2 in the world.
In addition to producing natural gas, LaBarge is one of the world’s largest sources of helium and produces about 20% of global supply.
Range Resources lowers full year capex, production guidance
Range Resources Corp. lowered its full-year 2021 capital and production guidance to $415 million from $425 million, and 2.12-2.13 bcfed from 2.15 bcfed, respectively.
Annual spending is expected to come in lower because of continued efficiency gains realized year-to-date, and adjustments to 2021 production guidance are a result of temporary gathering and transportation outages and delays alongside weather-related force majeure events, the company said as part of its third-quarter results released Oct. 27.
Production for the third quarter was 2.14 bcfed (about 30% liquids), representing a 1.5% increase over the second quarter. Range expects a similar production increase in the fourth quarter and to exit the year near 2.2 bcfed.
GAAP revenues for third-quarter 2021 totaled $303 million, GAAP net cash provided from operating activities (including changes in working capital) was $192 million, and GAAP net earnings was a loss of $350 million. Third-quarter earnings results include a $652 million derivative fair value loss due to increases in commodity prices.
Non-GAAP revenues for third-quarter 2021 totaled $795 million, and cash flow from operations before changes in working capital, a non-GAAP measure, was $276 million. Adjusted net income comparable to analysts’ estimates, a non-GAAP measure, was $130 million in the quarter.
All-in third quarter capital spending was $96 million, about 23% of the annual budget. Third-quarter 2021 drilling and completion expenditures were $91.8 million. During the quarter, $4.6 million was invested on acreage leasehold, gathering systems, and other corporate items.
Total capital expenditures year-to-date reached $322 million at the end of the quarter.
As of Sept. 30, Range had total debt outstanding of $2.98 billion, consisting of $30 million in bank debt and $2.95 billion in senior notes. The company has about $750 million in senior notes that mature through 2023, which are expected to be retired with projected free cash flow at current strip pricing. Range had over $2.0 billion of borrowing capacity under the bank credit facility commitment amount at the end of the quarter.
Exploration & Development Quick Takes
ConocoPhillips submits development plans for Tommeliten A
ConocoPhillips Skandinavia AS and partners submitted a plan for development and operation of Tommeliten A field in the North Sea to the Norwegian Ministry of Petroleum and Energy and the UK Oil and Gas Authority. First production is expected in 2024.
Tommeliten A is a UK-Norway trans-boundary field extending from Norwegian Block 1/9 into UK Block 30/20. New greenfield facilities are about 25 km southwest of the Ekofisk complex in 75 m of water. It is being developed in accordance with the UK and Norwegian authorities’ guidelines for development of trans-boundary oil and gas fields.
The reservoir, at a depth of 3,000 m, contains gas and condensate in chalk in the Paleocene Ekofisk formation and Upper Cretaceous Tor formation (OGJ Online, Oct. 1, 2020). The development concept is a two-by-six slot subsea production system (SPS) with 10 production wells and an electrically heated flowline, tied into Ekofisk, including installation of a new processing module. Resource potential for the field is estimated to be 80-180 MMboe, mainly comprising gas condensate.
Estimated total capital investment associated with the project is $1.5 billion.
ConocoPhillips Skandinavia AS is operator of Tommeliten A Unit (28.1385%) with partners PGNiG Upstream Norway AS (42.1978 %), TotalEnergies EP Norge AS (20.1430 %), Vår Energi AS (9.0907 %), ConocoPhillips (UK) Holdings Ltd. (0.2109%), TotalEnergies UK Ltd. (0.1510%), and ENI UK Ltd. (0.0681%).
Wheatstone reserves estimate decreased
Estimated reserves for Wheatstone and Julimar-Brunello fields offshore Western Australia have decreased following completion of reservoir studies based on 4D seismic, well performance, and well drilling results.
The downgrade is mentioned in the third quarter 2021 report of Woodside Petroleum, one of the members of the Chevron-operated Wheatstone LNG project.
Woodside said proved (1P) developed reserves moved down to 11.5 MMboe from 54.5 MMboe.
Proved total (1P) reserves declined to 112.6 MMboe from 154.2 MMboe, while proved plus probable (2P) developed reserves dropped to 26MMboe from 86 MMboe and 2P total reserves to 168.4MMboe from 231.1 MMboe.
The updated reserve estimate includes 2021 production to date of 11.8 MMboe.
As part of the reserves update, future phases of Wheatstone compression have been reclassified as undeveloped reserves from developed.
Woodside also said reserves for the nearby Julimar-Brunello project—which it operates as a segment of the total Wheatstone project—also have changed. It is now expected that about 44 MMboe of 1P and 62 MMboe of 2P reserves will be reclassified as developed reserves from undeveloped.
Best estimate contingent resources (2C) for Julimar-Brunello, however, have increased to 7.3 MMboe from 3.9 MMboe.
Woodside has a 65% interest in Julimar-Brunello with KUFPC holding 35%.
Woodside has a 13% non-operated interest in the Wheatstone project which includes the production platform, pipeline to shore, and shore-based LNG plant, but excludes Wheatstone and Iago fields and subsea infrastructure.
Other Wheatstone interest holders are Chevron (operator) with 64.1%, KUFPC 13.4%, Kyushu Electric Power Co. 1.5%, and PE Wheatstone 8%.
Wheatstone-Iago fields contribute 80% to the overall project. Julimar-Brunello contributes 20%.
Neptune drills dry well near Snorre field
Neptune Energy Norge AS has plugged a North Sea well in production license 882. The well is dry.
Well 33/6-5 S, the fourth exploration well in the license, was drilled about 10 km northwest of Snorre field by the Deepsea Yantai drilling rig in the northern part of the North Sea to a vertical depth of 3,428 m and a measured depth of 3,488 m below sea level (OGJ Online, Aug. 19, 2021). It was terminated in the Drake formation in the Lower Jurassic. Water depth at the site is 315 m.
The primary exploration target was to prove petroleum in Middle Jurassic reservoir rocks (Rannoch formation). The secondary exploration target was to prove petroleum in the Statfjord group in the Lower Jurassic, depending on oil in the Rannoch formation.
The well encountered around 90 m of Rannoch formation with sandstone of moderate to good reservoir quality.
In the Upper Jurassic, the well encountered around 30 m of Draupne formation, with 5 m of intra-Draupne sandstone of poor to moderate reservoir quality.
Well 33/6-5 S was terminated at a shallower level than the planned secondary exploration target in the Statfjord group.
Data acquisition has been carried out.
The rig will now drill development wells in production license 586 in the Norwegian Sea for operator Neptune.
Drilling & Production Quick Takes
Shell restores Gulf of Mexico production disrupted by Hurricane Ida
Shell Offshore Inc. has restored Gulf of Mexico production previously offline due to facilities damage caused by Hurricane Ida in August.
The Royal Dutch Shell PLC subsidiary restarted production at Mars and Ursa platforms and began exporting oil and gas through the West Delta-143 (WD-143) A facility.
With WD-143 A now operational, the Mars Oil Pipeline Co. has resumed normal operations.
On Oct. 1, Shell restarted production at the Olympus platform and began exporting oil and gas through the West Delta-143 (WD-143) C facility.
When Mars and Ursa are fully ramped up, the company will have 100% of Shell-operated production in the Gulf of Mexico back online, ahead of schedule from initial estimates (OGJ Online, Sept. 20, 2021).
The WD-143 facilities serve as the transfer station for all production from Shell’s assets in the Mars corridor in the Mississippi Canyon area of the Gulf of Mexico to onshore crude terminals. Production from Olympus flows across WD-143 C while production from Mars and Ursa facilities flow across WD-143 A.
The WD-143 platform, owned by Shell Offshore Inc. (71.5%) and BP Exploration & Production Inc. (28.5%), is operated by Shell Pipeline Co. LP.
The Mars corridor consists of Shell-operated tension leg platforms Mars, Olympus, and Ursa. Shell is operator at Mars and Olympus (71.5%) with partner BP Exploration & Production Inc. (28.5%). Shell is operator at Ursa (45.3884%) with partners BP Exploration & Production Inc. (22.6916%), ExxonMobil Corp. (15.9600%), and ConocoPhillips Co. (15.9600%).
SDX spuds first well in West Gharib drilling campaign
SDX Energy PLC spudded the MSD-21 infill development well on Meseda field in the West Gharib concession in the Egyptian Eastern Desert adjacent to the Gulf of Suez.
The well is targeting the Asl formation reservoir at about 3,200 ft TVDSS and will take around 4 weeks to drill, complete, and tie-in to existing infrastructure. It is anticipated to produce about 300 b/d gross. Costs to drill and tie in are expected to be about $1 million, with estimated payback period of less than 1 year at current oil prices.
The well is the first in a 12-well development campaign on Meseda and Rabul oil fields (OGJ Online, Mar. 8, 2021). The development drilling campaign is aimed at growing production to about 3,500-4,000 b/d by early 2023 from current rates of about 2,400 b/d.
SDX holds a 50% working interest in the license. Partners are The General Petroleum Co., a wholly owned subsidiary of the Egyptian General Petroleum Corp., and Dublin Petroleum Ltd.
VAALCO increases production in Etame, offshore Gabon
VAALCO Energy Inc. completed two workovers at Etame field, offshore Gabon, adding about 1,050 gross b/d.
Well EEBOM-2H had its electrical submersible pump (ESP) replaced and upgraded. The workover increased production in mid-October to about 1,400 gross b/d (715 b/d net to VAALCO) from about 500 gross b/d prior to workover.
Well ET-12H has both upper and lower ESP units replaced and reconfigured. The workover increased production by 150 b/d to about 1,800 gross b/d (920 b/d net) in late-October.
VAALCO used its mobile hydraulic workover unit to rapidly mobilize and replace the ESPs cheaper and more efficiently compared to a drilling rig, the operator said.
VAALCO is operator in the Etame Marin block (63.6%). To date the block has produced over 123 million bbl of crude oil.
PROCESSING Quick Takes
Phillips 66 converting Alliance refinery into terminal
Phillips 66 has decided to move forward with a plan to transform its 255,000-b/d Alliance refinery on the Mississippi River in Belle Chasse, Plaquemines Parish, La., about 25 miles southeast of New Orleans, into a terminal that the company will continue to operate as part of its midstream portfolio.
Phillips 66 said in a release Nov. 8 its decision to advance the proposed refinery-to-terminal conversion project follows the company’s evaluation of several options to save the site in consideration of the investment that otherwise would be required to repair refinery infrastructure in the wake of damages caused by Hurricane Ida, the eye of which made landfall as a Category 4 storm along the southeastern coast of Louisiana in late-August 2021 (OGJ Online, Sept. 1, 2021; Aug. 30, 2021).
“Alliance’s existing infrastructure and [US] Gulf Coast location make it an attractive midstream asset, [and] Phillips 66 will continue to be a major refiner with [its remaining] 12 [refineries] in the US and Europe,” said Greg Garland, Phillips 66’s chairman and chief executive officer.
Acknowledging potential impacts of the decision ultimately cease refining operations at Belle Chasse, Garland reiterated the company’s ongoing commitment to maintain ongoing activities at the site and offer support to Alliance’s 500 employees and 400 contractors during the transitional period.
“Our decision was a difficult one, and we understand it has a profound impact on our employees, contractors, and the broader Belle Chasse community,” Garland said. “We will work to help them through this transition and support them as Alliance takes on a new role in our portfolio.”
In a separate filing to the US Securities and Exchange Commission on Nov. 8, Phillips 66 said that while it is currently in the process of determining costs that will be associated with Alliance’s permanent shutdown of refining operations and conversion to terminaling operations, the company does not expect those costs to likely be material to its consolidated financial position, operational results, or cash flows.
HollyFrontier trims some capex targets
The leaders of HollyFrontier Corp. have reduced some of their capital spending forecasts for the remainder of 2021 and pushed some renewables investment dollars into 2022.
Speaking to analysts and investors Nov. 3 after reporting their third-quarter results, President and Chief Executive Officer Mike Jennings and Chief Financial Officer Rich Voliva said HollyFrontier’s work on a recent turnaround of its Tulsa refinery and the shrinking of the scope of work at a turnaround now under way at its 100,000 b/d Navajo refinery in New Mexico has enabled them to cut 2021 capex plans on turnarounds and catalysts by $30 million to $290-320 million.
On the renewables side, Jennings and Voliva trimmed their 2021 spending plans by $75 million to $550-600 million, pushing more investments into next year. Dallas-based HollyFrontier is working on three projects—renewable diesel units in Wyoming and New Mexico and a feedstock pretreatment unit in New Mexico—into which it will invest a combined $800-900 million (OGJ Online, June 2, 2020). Jennings said the Wyoming work is running ahead of schedule and should be able to run its first batch of feed late this year.
The timeline of work on the New Mexico pretreatment unit has been moved up “given current economics between refined soybean oil and other feedstocks,” Jennings said, and that facility is now expected to be up and running in the first quarter, about 3 months ahead of its previous schedule—hence the shift in spending. The HollyFrontier team is now looking for the New Mexico renewable diesel unit to be completed in the second quarter.
In all, HollyFrontier plans to spend $175-225 million on renewables projects in 2022. Voliva said he expects to provide companywide capex estimates in December.
During the third quarter, HollyFrontier produced a net profit of $303 million on sales of nearly $4.7 billion. The company’s consolidated refinery gross margin was $14.87 per produced bbl, a 140% jump from the same period of 2020, and crude throughput was about 416,000 b/d, comfortably above executives’ guidance of 380,000-400,000 b/d.
The company also noted completion of its $614 million purchase of the Puget Sound refinery from Shell (OGJ Online, May 24, 2021). That refinery north of Seattle has a capacity of 149,000 b/d and gives Holly Frontier its first refining outpost on the West Coast.
TRANSPORTATION Quick Takes
Mountain Valley gas pipeline on schedule for third-quarter 2022 startup
Equitrans Midstream Corp. still expects its 2-bcfd, 303-mile Mountain Valley natural gas pipeline (MVP) to enter service third-quarter 2022. The company initially announced this in-service timing earlier this year (OGJ Online, May 5, 2021).
Equitrans began work on MVP in February 2018 and planned to put it in service late that year. In February 2021, MVP began a permitting process with the US Army Corps of Engineers (ACE) and Federal Energy Regulatory Commission (FERC) related to its remaining waterbody and wetland crossings. In August, FERC issued an environmental assessment for the pipeline’s certificate amendment application, which requests a change to utilize boring methodology for about 120 water crossings. The West Virginia Department of Environmental Protection and Virginia Department of Environmental Quality continue to work to complete their respective Section 401 reviews, addressing the ACE permitting process for roughly 300 water crossings, by Nov. 29, 2021, and Dec. 31, 2021, respectively.
Expected permitting timelines for both FERC and ACE remain in line with Equitrans’ expectations and the company continues to target a full in-service date of summer 2022 at a total project cost of about $6.2 billion. Equitrans initially expected the project to cost $3.5 billion.
MVP plans to begin construction of its 900-MMcfd Southgate extension during 2022 and place the project in-service during second-quarter 2023. The 75-mile pipeline is designed to receive gas from MVP in Virginia for transport to new delivery points in Rockingham and Alamance Counties, NC, backed by a 300-MMcfd firm capacity commitment from Dominion Energy North Carolina.
Venture Global LNG signs 7.5-mpty supply contracts with Sinopec companies
Venture Global LNG and China Petroleum & Chemical Corp. (Sinopec) have signed two 20-year contracts for the supply of a total of 4 million tonnes/year (mtpy) of LNG from Venture Global’s 20-million tpy Plaquemines LNG liquefaction plant, in Plaquemines Parish, La. China International United Petroleum & Chemical Co. (UNIPEC), a Sinopec subsidiary, has also agreed to purchase 3.5 mtpy from Venture Global’s 10-million tpy Calcasieu Pass LNG plant for a shorter duration.
Venture Global described the contracts as the largest single LNG supply deal ever signed by a US company and said it will double imports of US LNG to China.
The company received US Federal Energy Regulatory Commission (FERC) permission to start site clearing for Plaquemines LNG earlier this month (OGJ Online, Nov. 1, 2021) and earlier this year got FERC permission to start service on its 23.4 mile TransCameron pipeline, delivering gas to Calcasieu Pass LNG (OGJ Online, Apr. 9, 2021).