OGJ Newsletter

May 24, 2021


Pioneer Natural Resources posts first quarter net loss of $70 million

Pioneer Natural Resources Co. reported a first-quarter net loss attributable to common stockholders of $70 million. Excluding the effects of noncash mark-to-market adjustments and certain other unusual items, adjusted income for the quarter was $396 million. Cash flow from operating activities was $377 million.

During the first quarter, drilling, completion, and facilities capital expenditures totaled $591 million. Total capital expenditures, including water infrastructure, totaled $605 million.

First quarter oil production averaged 281,000 b/d. Total first quarter production averaged 474,000 boe/d. During the first quarter, Pioneer placed 106 horizontal wells on production.

The company closed the acquisition of DoublePoint Energy on May 4 (OGJ Online, Apr. 2, 2021).

Drilling, completions, and facilities capital for 2021 is budgeted at $2.95-3.25 billion, inclusive of an additional $530-570 million related to the DoublePoint acquisition. An additional $100 million and $50 million is budgeted for integration expenses related to the acquisition of Parsley and DoublePoint, respectively, resulting in a total 2021 capital budget of $3.1-3.4 billion. Its capital program is expected to be fully funded from forecasted 2021 cash flow of $5.9 billion.

During 2021, the company plans to operate an average of 22-24 horizontal drilling rigs in the Permian basin, including a one-rig average program in the Delaware basin and a three-rig average program in the southern Midland basin joint venture area.

Operated rigs on DoublePoint acreage are expected to be cut to 5 rigs by yearend from the current 7. The 2021 capital program is expected to place 470-510 wells on production, which includes the addition of 90 wells on the acreage acquired from DoublePoint.

Pioneer expects 2021 oil production of 351,000-366,000 b/d and total production of 605,000-631,000 boe/d, which includes current production from DoublePoint of 92,000 boe/d and 100,000 boe/d forecasted during second-half 2021.

Second-quarter 2021 oil production is forecasted to average 352,000-367,000 b/d and total production is expected to average 606,000-632,000 boe/d.

APA moves toward revamp of contracts in Egypt’s Western Desert

APA Corp., Houston, reached an agreement in principle with Egypt’s Ministry of Petroleum and Mineral Resources (MOP) and the Egyptian General Petroleum Corp. (EGPC) in support of the MOP’s efforts to modernize the country’s petroleum sector.

The new Production Sharing Contract (PSC) will consolidate most of the concessions in the Western Desert of Egypt operated by APA Corp. subsidiary Apache Egypt into a single new concession, which will account for more than 90% of the company’s gross production volumes in Egypt on a boe basis.

The changes simplify the contractual relationship with EGPC and include provisions to create a single cost recovery pool, adjust cost oil and gas and profit oil and gas participation, facilitate recovery of prior investment, update day-to-day operational governance, and refresh the term length of both exploration and development leases, according to a May 4 release from APA Corp.

The Apache entity that will become the sole contractor is owned two-thirds by Apache and one-third by Sinopec. The new PSC is subject to certain approvals within the Government of Egypt and ratification by Parliament.

Neptune acquires interest in North Sea Pegasus West discovery

Neptune Energy acquired a 38.75% equity interest from Spirit Energy in the Pegasus West discovery and surrounding acreage (P1724, P1727, P4257, and P2128) in the UK Southern North Sea.

Pegasus West was discovered in 2014 and is currently operated by Spirit Energy.

Entry into the Pegasus West Area “aligns interests in both the discovery and the Neptune-operated Cygnus gas facility (Neptune Energy 38.75%, Spirit Energy 61.25%) enabling acceleration of the development of Pegasus West as a subsea tieback to the existing Cygnus field,” the company said in a release May 4.

Neptune will work with Spirit Energy on front end engineering and design (FEED) studies in 2021 with the intention to reach a final investment decision by yearend. Once sanctioned, Neptune would become operator of the development through to first gas and into production.

Pegasus West holds an estimated 83 bcf of recoverable gas, “adding further volumes to the Greater Cygnus Area,” said Gerry Harrison, executive vice-president, HSES, subsurface and non-operated UK assets at Spirit Energy in a separate release May 4.

 Exploration & Development Quick Takes

NIOC lets contract for Farzad B gas field development

The National Iranian Oil Co. (NIOC) signed a $1.78-billion contract with Petropars Group to develop Farzad B gas field in the Persian Gulf.

The target of the buyback contract is to produce 28 million cu m/d of sour gas over 5 years. Gas will be transferred to the onshore facilities of Pars 2 Region in Kangan for processing. Gas condensate will be separated and transferred to South Pars refineries of Phases 12 and 19 for stabilization.

According to news service Shana, the contract entails drilling eight production wells; construction and installation of two main and secondary wellhead platforms; construction of liquid separation infrastructure on the main platform, construction of a 36-in., 230-km offshore pipeline; construction of a 10-in., 230-km offshore pipeline; construction of a 20-in., 3 km pipeline connecting the 3 platforms; construction of offshore infrastructure including receiving equipment for the produced sour fluid and condensate separation, along with ancillary infrastructure and onshore pipelines for the transfer and distribution of sour gas and condensate.

Pars Oil and Gas Co. estimates the field to contain 23,000 bcf of gas, with 5,000 bbl of condensate per bcf.

Farzad B lies in the Farsi block on the border between Iran and Saudi Arabia, about 20 km from Farsi Island.

Chrysaor drills dry hole south of Sleipner field

Chrysaor Norge AS drilled a dry hole in the North Sea south of Sleipner field. It is the second dry well drilled by the operator in PL973 following well 15/12-25 (OGJ Online, Mar. 23, 2021). Data acquisition was carried out. The well will be plugged. 

The latest well, 15/12-26, the second in PL 973, was drilled by the COSL Innovator drilling rig to a vertical depth of 2,762 m subsea 26 km south of the Sleipner Ost installation and 9 km south of the Grevling discovery. It was terminated in rocks from the Early Permian age in the Zechstein group about 240 km west of Stavanger. Water depth at the site is 86 m.

The objective was to prove petroleum in Late Jurassic (Ula formation) and potentially underlying Late Triassic reservoir rocks (Skagerrak formation).

The well encountered a sandstone layer of about 60 m in Ula, with good to very good reservoir quality. The Skagerrak formation was not encountered. 

The rig is now headed for Coast Center Base (CCB Ågotnes) west of Bergen for a temporary stay at the shipyard.

Chrysaor Norge is operator at PL973 (50%) with partners OKEA ASA (30%) and Petoro AS (20%).

OGDCL discovers gas in Balochistan province, Pakistan

Oil and Gas Development Co. Ltd. (OGDCL) discovered gas from the Jandran X-04 exploration well in District Barkhan, Balochistan Province, Pakistan.

The well was drilled to a depth of 1,200 m into Parh limestone. A drill stem test was carried out in the Mughal Kot formation. The well tested 7.08 MMscfd of gas and 0.55 b/d of condensate with well head flowing pressure of 1,300 psi on a 32/64-in. choke.

OGDCL is operator and has 100% ownership in the Jandran license.

 Drilling & Production Quick Takes

Cardinal Energy ups 2021 capital spend, plans eight-well program

Cardinal Energy Ltd., Calgary, increased its 2021 capital program to $46 million on the increase in oil prices and plans to drill two wells in each of its four operating areas in Alberta and Saskatchewan. The initial $27-million program did not contemplate drilling any wells for the year.

The company generated $16.1 million of adjusted funds flow, an 8% increase over the same period in 2020 and a 19% increase over the prior quarter. Excluding realized hedging losses, adjusted funds flow was $30 million.

Average production for the quarter was 18,385 boe/d. The company reduced net debt by $28.4 million, or 11% from yearend 2020.

The revised budget contemplates drilling eight wells across operating areas which includes two CO2 injection wells at Midale, Sask. for its enhanced oil recovery program.

The revised budget is forecasted to allow the company to increase production through the year with a fourth quarter average rate increasing by 10% over the initial 2021 budget.

Drilling of the company’s first Clearwater wells is expected in early 2022.

Total starts production at Zinia Phase 2 in Angola

Total SE started production from the Zinia Phase 2 short-cycle project on Block 17 in Angola, about 150 km from the coast in 600-1,200 m of water (OGJ Online, May 28, 2019).

The project includes drilling nine wells and is expected to reach production of 40,000 b/d of oil by mid-2022. Zinia Phase 2 is connected to Pazflor’s floating production, storage, and offloading unit (FPSO). Resources are estimated at 65 million bbl of oil.

Development was carried out on schedule and $150 million under budget.

Total is operator of Block 17 with 38% interest. Partners are Equinor (22.16%), ExxonMobil (19%), BP Exploration Angola Ltd. (15.84%), and Sonangol P&P (5%).

CNOOC starts Liuhua 29-2 gas field production

CNOOC Ltd. has started production from Liuhua 29-2 gas field in the eastern South China Sea about 300 km southeast of Hong Kong in water depth of about 750 m. Peak production of about 41 MMcfd is expected this year, the company said.

A new subsea wellhead has been built, with one development well planned, which will fully utilize the existing production infrastructure of Liwan 3-1 gas field and other deepwater gas fields.

CNOOC is operator of the field with 100% interest.

Petro Rio advances Polvo revitalization

PetroRio SA has begun production from well POL-K in the Polvo field Eocene reservoir, offshore Brazil, advancing revitalization efforts. Initial production of 2,500 b/d incrementally increases Polvo field production to 12,000 b/d, contributing to reduced lifting cost, the company said.

POL-K, following POL-L in 2020, confirms the potential of the reservoir, the volume of which is already accounted for in the latest reserves certification report. The well’s estimated recoverable production of about 4 million bbl of oil will be reclassified from proved undeveloped reserves to proved developed producing reserves.

Capital expenditure on the well was about $11 million. Estimated payback is under 3 months.

In the Campos basin 100 km from Cabo Frio, Rio de Janeiro, Polvo was PetroRio’s first production asset. In 2016, the company invested more than $11 million to increase oil extraction from the field. In 2018, PetroRio carried out the second phase of the revitalization plan, with the drilling of three wells. The project added 5,000 b/d to the field’s production, increasing the reserve by more than 6 million bbl.

In 2020, the third phase was carried out, with two more wells drilled, increasing production by around 3,000 b/d and 3 million added reserves (OGJ Online, Oct. 1, 2019). Useful life of the field has been extended until 2035 considering 1P reserves and the connection between Polvo field and Tubarão Martelo field.


Navitas Midstream expanding Permian gas processing operations

Navitas Midstream Partners LLC, The Woodlands, Tex., has let a contract to Honeywell UOP LLC to deliver a 200-MMcfd cryogenic natural gas processing plant the operator will use to extract NGLs from gas produced in several counties across the Permian basin.

Honeywell UOP’s scope of work under the contract will include design and supply of proprietary equipment for a UOP modular cryogenic plant, including refrigeration and dehydration units, that will be customized for high-rate recovery of NGLs from the Permian’s NGL-rich feed gas composition, the service provider said on May 18.

The new plant will use UOP-owned Ortloff recycle split vapor (RSV) technology to increase recovery of more ethane and propane, UOP said.

Further details regarding the project, including a timeframe for startup, were not disclosed.

Navitas currently owns and operates nearly 1,500 miles of gas-gathering pipelines, 660 MMcfd of gas processing capacity, and about 210,000 hp of field compression in the Midland basin of the West Texas Permian basin to serve producers in Midland, Martin, Howard, Glasscock, Upton, and Reagan Counties (OGJ Online, July 11, 2018; Dec. 2, 2015).

Located about 18 miles southeast of Midland, Tex., the 660-MMcfd Midland basin processing complex is made up of four processing trains at three separate plant sites. The Newberry plant includes Newberry Train 1, a 60-MMcfd RSV cryogenic plant commissioned in March 2017, as well as Newberry Train 2, a 200-MMcfd gas subcooled process (GSP) cryogenic processing plant commissioned in April 2018. Both trains include inlet carbon dioxide (CO2) and hydrogen sulfide (H2S) treating capabilities, with the combined Newberry plant also equipped with nitrogen rejection unit. The Taylor plant—commissioned in June 2019—houses a 200-MMcfd GSP cryogenic processing train. This plant also includes inlet CO2 and H2S treating capabilities, as well as a nitrogen rejection unit. The Trident plant features a 200-MMcfd RSV cryogenic processing plant commissioned in June 2020. Also equipped with inlet CO2 and H2S treating capabilities, this plant is scheduled to receive a nitrogen rejection unit sometime in 2021, according to the operator’s website.

Seaboard Energy lets contract for Kansas renewable diesel plant

Seaboard Corp. subsidiary Seaboard Energy LLC has let a contract to Haldor Topsoe AS to provide process technology and related services for a renewable diesel unit currently under construction at the operator’s existing site in Hugoton, Kan.

Topsoe will license its proprietary HydroFlex renewable fuel technology and H2bridge hydrogen technology—based on its modular Haldor Topsoe Convection Reformer (HTCR) technology—for the new plant, which will use a feedstock of tallow and soybean oil to produce 6,500 b/d of renewable diesel, the service provider said on May 14.

Topsoe’s scope of work under the contract also includes supply of basic engineering, proprietary equipment, catalyst, and technical services for the project.

The renewable diesel plant—which Topsoe will deliver as an integrated hydrogen unit and hydroprocessing unit—is scheduled for startup by yearend 2021.

A value of the contract was not disclosed.

The Kansas renewable fuels complex—which will be Seaboard Energy’s first expansion into renewable diesel production—follows the operator’s purchase of Synata Hugoton LLC’s idled Hugoton cellulosic ethanol plant in February 2019, at which the new owner was considering proposed modifications to enable renewable diesel production, according to Seaboard Energy’s website.

Seaboard Energy currently owns and operates two biodiesel plants—one in Guymon, Okla., the other in St. Joseph, Mo.—with a combined production capacity of 75 million gal/year.


Woodside leaves Kitimat LNG

Woodside Energy has decided to exit its 50% non-operated participating interest in the proposed Kitimat LNG liquefaction plant in British Columbia, Canada, effectively killing the project pending a buyer or outside financing. The exit will include the divestment or wind-up and restoration of assets, leases, and agreements covering the 471-km Pacific Trail pipeline route and the site of the proposed plant at Bish Cove.

The company said it will work with Kitimat joint-venture partner and operator Chevron Canada to protect value during the exit. Chevron announced plans to divest its 50% interest in Kitimat LNG in December 2019 and earlier this year ceased funding feasibility work (OGJ Online, Mar. 25, 2021).

Woodside expects to incur a $40-60 million charge against 2021 net earnings because of the exit. It will retain a position in Liard basin in northeast British Columbia.

The company said exiting Kitimat LNG will allow it to focus on working towards second-half 2021 final investment decision (FID) for its Scarborough LNG development in Western Australia and the continued execution of its Sangomar oil project offshore Senegal. Woodside earlier this year doubled its LNG supply agreement with Uniper Global Commodities SE, much of which would be supplied from Scarborough starting in 2025 pending FID (OGJ Online, Jan. 19, 2021).

Woodside last year pre-empted a sale by FAR Ltd., Melbourne, of its Sangomar interests and oil discoveries to ONGC Videsh Vankorneft Pte Ltd., seeking to instead acquire the interests itself (OGJ Online, Dec. 4, 2020; Apr. 29, 2021). FAR held a 13.67% interest in the Sangomar oil exploitation area and 15% interest in the remaining evaluation area of the Woodside-operated Rufisque, Sangomar, and Sangomar Deep joint venture.

Equitrans pushes Mountain Valley in-service to 2022

Equitrans Midstream Corp. no longer expects its Mountain Valley natural gas pipeline joint venture to have necessary waterbody and wetland crossing approvals by third-quarter 2021, pushing the project’s planned in-service date to third-quarter 2022 from end-2021.

In March and April 2021, respectively, the Virginia Department of Environmental Quality and the West Virginia Department of Environmental Protection submitted requests to the US Army Corps of Engineers seeking to extend the 120-day review period to evaluate Mountain Valley’s Clean Water Act Section 401 water quality certification applications.

Equitrans earlier this year received Federal Energy Regulatory Commission affirmation that it could resume work on a 17-mile stretch of the pipeline near Jefferson National Forest in Virginia (OGJ Online, Mar. 26, 2021). The project is 92% complete.

The company estimates Mountain Valley’s cost at $6.2 billion.

Based on the adjustment to Mountain Valley’s targeted full in-service date and current expectations regarding timing of permit approvals for the project’s Southgate extension, Equitrans is targeting a 2022 start for Southgate construction to place the project in-service during second-quarter 2023. The 75-mile pipeline would move gas from Mountain Valley in Virginia to new delivery points in Rockingham and Alamance Counties, NC.

With a total project cost estimate of $450-500 million, Southgate is backed by a 300-MMcfd firm capacity commitment from Dominion Energy North Carolina. Southgate can be expanded to as much as 900 MMcfd, according to Equitrans.

APA Group begins Australian east coast gas grid expansion

APA Group, Sydney, reached final investment decision (FID) for its Australian east coast gas grid expansion project (OGJ Online, June 20, 2017) . The project will meet forecast winter gas supply shortfalls from 2023, the company said.

The $270 million (Aus.) expansion will take place in two stages and will increase winter peak capacity of the east coast grid by 25% through additional compression and associated works on both the southwest Queensland and Moomba-Sydney pipelines.

The first stage will increase capacity of the Wallumbilla-Wilton sector by 12%. It is expected to be commissioned in first-quarter 2023.

The second stage will add a further 13% capacity. It is scheduled for commissioning near end-2023.

Engineering and design work for a contemplated third stage to add another 25% transportation capacity is currently under way.

APA signed a new gas transportation agreement with Origin Energy Ltd., Sydney, to support Origin’s energy supply needs in southern Australian markets, including winter peak gas demand, ahead of the projected 2023 supply risks.

The agreement is for an initial 3 years with the option of a further 2-year extension. APA will deliver a portfolio of services to supply northern Australian gas to southern markets through the east coast grid.