OGJ Newsletter

GENERAL INTEREST Quick Takes

Aker BP hits production record in first-quarter 2023

Aker BP reached a new production record of 453,000 boe/d in first-quarter 2023, up from the 432,000 boe/d produced in fourth-quarter 2022, driven by continued ramp-up of Equinor-operated North Sea Johan Sverdrup Phase 2 (Aker BP, 31.5733%) to the full field design capacity of 720,000 b/d.

Field development projects are on track, with detailed engineering and procurement ongoing and major contracts placed, the company said in an earnings report Apr. 27.

Total income in the first quarter amounted to $3.310 billion, down from $3.826 billion in the previous quarter, mainly due to lower oil and gas prices, partly offset by an increase in volume sold.

The company reported operating profit of $1.961 million, down from $2.214 billion in fourth-quarter 2022. Net profit for the first quarter was $187 million, up from $112 million in fourth-quarter 2022. Free cash flow in first-quarter 2023 was $977 million, up from $98 million in fourth-quarter 2022.

Impairments amounted to $373 million mainly driven by the previously termination of the Troldhaugen project and by reduced short term forward prices leading to an impairment of technical goodwill allocated to the Edvard Grieg & Ivar Aasen CGU.

Exploration

Total exploration spend in the first quarter was $119 million, up from $60 million in fourth-quarter 2022.

The Gjegnalunden prospect in production license 867 (80% interest) was drilled in the quarter (OGJ Online, Jan. 11, 2023). Preliminary estimates place the size of the discovery at 3-9 MMboe. It is not considered to be commercial at the present time, the company said.

The Styggehøe prospect in production license 1141 (70% interest), the Angulata prospect in production license 554 (30% interest), and the P-Graben appraisal well in production license 265 (27% interest) were all drilled in the quarter and concluded as dry.

Drilling of the Ve prospect, in production license 919 in the North Sea, was started in the first quarter and completed early in the second quarter. The well resulted in a small oil discovery with preliminary estimates of 3-5 MMboe. The licensees will assess the discovery together with others in the area regarding possible development.

Range Resources brings nine wells to sales, 61 planned in 2023 maintenance program

Range Resources Corp., Fort Worth, Tex., plans a maintenance program for 2023, with flat production of 2.12-2.16 bcfed for the year and liquids comprising 30% of guided production, the company said in a first-quarter earnings report.

All-in capital expenditures of $570-615 million are expected for the year. Drilling and completions spending of $540-565 million is expected for the year.

First-quarter 2023 production averaged 2.14 bcfed, with about 70% natural gas. In the quarter, the company turned-in-line nine wells of 61 planned for the year (58 in southwest Pennsylvania, three in northeast Pennsylvania).

Overall capital spending for the quarter was $152 million, some 26% of the 2023 budget. First-quarter 2023 drilling and completion expenditures were $139 million. During the quarter, about $12 million was invested in acreage leasehold and gathering systems.

Cash flow from operating activities for the quarter was $475 million. Cash flow from operations, before working capital changes, was $400 million.

GAAP revenues for first-quarter 2023 totaled $1.2 billion and GAAP net income was $481 million. First quarter earnings results include a $368 million mark-to-market derivative gain due to decreases in commodity prices.

Non-GAAP revenues for first-quarter 2023 totaled $853 million, and cash flow from operations before changes in working capital, a non-GAAP measure, was $400 million. 

Newfoundland, Labrador prepare for deepwater exploration

Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) has issued calls for bids for exploration licenses in the eastern Newfoundland and southeastern Newfoundland regions.

NL23-CFB01 (exploration licenses, eastern Newfoundland region) consists of 28 parcels and a total of 7,222,551 hectares.

NL23-CFB02 (exploration licenses, southeastern Newfoundland region) consists of 19 parcels and a total of 4,982,275 hectares.

Winning bids will be selected based on the total investment committed by bidders for exploration work on the parcel during the first period of a 9-year license. The minimum bid is $10 million (Can.).

Based on an assessment of nominations and land tenure considerations, C-NLOPB has decided not to proceed with a call for bids in the Jeanne d’Arc Region this year. A decision on a future call for bids in the region will be assessed on an annual basis.

Sealed bids may be submitted until Nov. 1, 2023.

Exploration & Development Quick Takes

ExxonMobil sanctions fifth development offshore Guyana

ExxonMobil has made a final investment decision (FID) to proceed with Uaru, the fifth development on the Stabroek block, offshore Guyana, after receiving government and regulatory approvals.

Uaru will have a production capacity of about 250,000 gross b/d of oil with production targeted to startup in 2026, the company said in a release Apr. 27.

The $12.7-billion development will target an estimated resource base of more than 800 million bbl of oil and include up to 10 drill centers and 44 production and injection wells. MODEC is constructing the Errea Wittu floating production, storage, and offloading (FPSO) vessel under an engineering, procurement, and construction contract.

Elsewhere in the block, Liza Phase 1 and Liza Phase 2 developments produced an average of 375,000 gross b/d of oil in this year’s first quarter. The third sanctioned development on the block, Payara, is targeted for startup early in fourth-quarter 2023, with a gross production capacity of about 220,000 b/d of oil. The fourth sanctioned development, Yellowtail, is expected to come online in 2025 with a gross production capacity of about 250,000 b/d of oil. A sixth development, Whiptail, is expected to be submitted for government and regulatory approval later this year.

In total, six FPSOs with a gross production capacity of more than 1.2 million b/d of oil are expected to be online on the block by end-2027, with the potential for up to 10 FPSOs to develop the estimated gross discovered recoverable resources of more than 11 billion boe.

ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. is operator with 45% interest in the Stabroek block. Hess Guyana Exploration Ltd. holds 30%, and CNOOC Petroleum Guyana Ltd. holds 25%.

88 Energy awarded new Alaskan North Slope block

88 Energy Ltd., Perth, has been awarded a new exploration block (Project Leonis) on the North Slope of Alaska, about 15 km southwest of the town of Deadhorse and 25 km north of the operator’s Project Phoenix block.

The Trans Alaska Pipeline system skirts the new block’s eastern boundary.

The award is part of the 2022 Alaskan Department of Natural Resources Oil and Gas Division’s acreage round. 88 Energy was the highest bidder for the block, which comprises 10 leases covering about 25,430 contiguous acres.

The lease area is covered by the 2005 Storms 3D seismic data suite and contains exploration well Hemi Springs Unit-3 drilled by Arco in 1985. Another well (Hailstorm-1) was drilled in 2006.

Hemi Springs targeted the deep Kuparuk and Ivishak reservoirs—the main producing intervals in the giant fields around Prudhoe Bay.

88 Energy said a well data review of Hemi Springs indicated more than 200 ft of low resistivity bypassed log pay within the USB reservoir which contained good porosity and oil shows.

Nearby oil fields such as Orion, Polaris, West Sak, and Milne Point have demonstrated successful development of the USB reservoir, the company said.

An initial reprocessing and review of the 3D data shows a strong seismic-well tie and a clear amplitude at the prospective USB level. The prospect also appears to be bounded by faults on three sides which may serve as a trapping mechanism.

88 Energy will conduct further analysis to determine the future potential of Project Leonis acreage to define a possible exploration program and timeline.

Drilling & Production Quick Takes

Neptune starts additional production from Cygnus gas field

Neptune Energy began production from the 11th well at its operated Cygnus gas field in the southern North Sea.

The well is expected to produce about 4,000 boe/d, enough gas to heat about 200,000 UK homes, the operator said in a release Apr. 27.

Together with the 10th well started up earlier this year, Cygnus is expected to produce enough gas per day to meet the needs of around 1.9 million UK households.

Both wells were drilled by Borr Drilling’s Prospector 1 jack up rig.

Neptune Energy is operator at Cygnus with 38.75% working interest. Spirit Energy holds the remaining 61.25%.

Sage trades Barnett gas drilling program for Eagle Ford oil program

Sage Natural Resources LLC, Tulsa, Okla., plans to shift its drilling program to oil assets in the Eagle Ford shale for the remainder of the year, suspending its Barnett shale program due to the drop in natural gas commodity price through this year’s first quarter.

The privately held company recently completed its 30-well Barnett program, drilling 30 horizontal wells targeting the Barnett shale formation in North Texas.

The 30-well program totaled 96 miles with one rig. Average lateral length was about 8,200 ft per well, with average spud to rig release under 13 days. On average, each well came in at about $745 per drilled and completed lateral foot, the company said in a release Apr. 26. 

“Sage made an investment decision in October of 2020 during [the pandemic] at $2.50 natural gas pricing to drill our first eight-well pad. The investment decision made at that time, with respect to all-in capital service costs, were half of what they are today,” said Gavin D. McQueen, president and chief executive officer. Since then, the company has drilled 44 extended-reach horizontal wells in the Barnett.

Company executives remain bullish on natural gas over the long-term due to its growing global demand, he said, but the company will “save those reserves for a sunnier day,” saying the company is confident it can add oil to the company’s producing asset base.

SM Energy expects slight production increase in Q2

SM Energy Co. expects capital expenditure (net of the change in capital accruals), excluding acquisitions, of

$295-315 million in this year’s second quarter with plans to drill about 17 net wells (10 South Texas, 7 Midland basin) and to turn-in-line about 22 net wells (8 South Texas, 14 Midland basin).

Production of 13.3-13.5 MMboe (146,000-148,000 boe/d), at 42-43% oil and 59-60% liquids is expected for second-quarter 2023.  

Second-quarter 2023 guidance was provided with the company’s first-quarter earnings report released Apr. 27.

For first-quarter 2023, SM Energy had net income of $198.6 million, up more than 300% compared with $48.8 million in the prior year period. First-quarter 2023 adjusted net income was $162.2 million, down from adjusted net income of $245.9 million for the same period in 2022.

Net cash provided by operating activities was $331.6 million.

Production for first-quarter 2023 was 13.2 MMboe, or 146,400 boe/d. Volumes were about 51% from the Midland basin and 49% from South Texas and were 43% oil.

Production was about 178,000 boe above the mid-point of guidance, primarily due to outperformance from all 16 new South Texas wells, including outperformance from a seven-well pad that turned-in-line 1 week earlier than initially planned.

First quarter capital expenditures of $240.7 million, adjusted for an increase in capital accruals of $66.9 million, totaled $307.6 million. Capital expenditures included $9.9 million for leasehold acquisitions in the Midland basin of about 6,300 net acres in the Rockstar area for $10 million that were not considered in guidance.

PROCESSING Quick Takes

Valero commissions Port Arthur refinery’s delayed coking project

Valero Energy Corp., San Antonio, Tex., has started up a new 55,000-b/d delayed coker and sulfur recovery unit at the operator’s 395,000-b/d refinery in Port Arthur, Tex. (OGJ Online, Apr. 14, 2020).

Completed in March and officially beginning operations on Apr. 5, the $975-million delayed coking project enhances the Port Arthur refinery’s ability to process incremental volumes of sour crude oils and residual feedstocks, as well as improve turnaround efficiency at the site, Valero said in its first-quarter 2023 earnings report.

Alongside an anticipated increase in the refinery’s throughput capacity, the new unit also will slash the operator’s imports of vacuum gas oil.

“[Startup] of the Port Arthur coker goes a long way to shoring up our VGO position [by] taking resid and heavier crudes and cracking [them] into sort of [a] distillate and essentially a VGO-boiling range material,” Lane Riggs, Valero’s president and chief operating officer, said in an Apr. 27 quarterly earnings call with investors.

“Our requirement for importing VGO has [already] fallen post the new coker startup,” Riggs said, adding that unit—as of the week beginning Apr. 24—had ramped up to projected rates.

Project details

In its latest investor presentation dated September 2022, Valero said Port Arthur’s new delayed coker project would create two independent combined crude distillation unit (CDU)-vacuum distillation unit (VDU) coker trains at the refinery that, in addition to improving turnaround efficiency, also aimed to reduce maintenance-related lost margin opportunity.

Rather than adding new crude processing capacity to Port Arthur’s nameplate capacity, the delayed coking project instead was designed to enable full utilization of the refinery’s existing CDU capacity, as well as the site’s yield of light products, according to the operator.

As of September 2022, Valero estimated the new delayed coker would enhance the refinery’s capability to process incremental volumes of sour crude and resid feedstocks by 102,000 b/d and 21,000 b/d, while reducing its demand for VGO by 47,000 b/d.

Incremental increases to production volumes to be enabled by startup of the unit were estimated as of September 2022 as follows:

• Diesel; 43,000 b/d.
• Gasoline; 15,000 b/d.
• LPG; 4,000 b/d.
• Naphtha; 3,000 b/d.

Petrobras lets contract for Route 3 lubricants plant

Petrobras has let a contract to Chevron Lummus Global LLC (CLG)—a partnership of Chevron USA Inc. and Lummus Technology LLC—to deliver technology licensing for a new unit at the lubricants plant of the operator’s Polo GasLub Itaboraí hub under construction in Itaborai, Rio de Janeiro, Brazil, as part of the operator’s Route 3 integrated project to expand transportation and processing of associated gas from the country’s offshore Santos basin presalt.

Under the contract, CLG will license its proprietary Isodewaxing and Isofinishing technologies for a new 12,580-b/d hydroisodewaxing (HIDW) unit that—once completed— will produce a wide-viscosity range of premium API Group II/II+ lubricating base oil grades for the first time in both Brazil and South America, the service provider said on Apr. 3.

Alongside technology licensing, CLG said its scope of delivery on the project also includes basic design engineering and research unit testing services.

Addition of the HIDW unit at GasLub Itaboraí will help to minimize Brazil’s existing dependence on imported base oils as part of Petrobras’ broader strategy to domestically produce higher-quality products to better serve the regional market.

This latest contract for GasLub Itaboraí project follows Petrobras’ recent award to TS Participações e Investimentos SA subsidiary Toyo Setal Empreendimentos Ltda. for completion of the Route 3 natural gas processing unit (UPGN).

Petrobras said it expects start of gas processing operations in the GasLub Itaboraí to begin in 2024.

Part of Petrobras’ repositioning plan for its cancelled Comperj integrated refining project—renamed GasLub Itaboraí in 2020—the Route 3 combined gas pipeline-UPGN project’s integration with the previously completed Route 1 and Route 2 pipeline projects aims to increase the operator’s presalt gas offloading and processing capacity to 44 million cu m/day from 23 million cu m/day.

Alongside the new Route 3 UPGN—which will consist of two 10.5-million cu m/day processing trains—the Route 3 project includes a 355-km gas pipeline (307 km offshore, 48 km onshore) that will deliver about 18 million cu m/day of natural gas from the Santos basin presalt cluster to the UPGN at GasLub Itaboraí.

Petrobras previously confirmed it was evaluating integration of some units at GasLub Itaboraí with its 239,000-b/d Duque de Caxias (REDUC) refinery in the Baixada Fluminense area of Brazil’s Rio de Janeiro state for production of basic lubricants and fuels from intermediate products delivered via pipeline from the refinery to the Itaboraí gas hub.

TRANSPORTATION Quick Takes

Texas LNG gets renewed FERC approval following remand

Glenfarne Energy Transition LLC received an order on remand from the US Federal Energy Regulatory Commission (FERC) approving its planned 4-million tonne/year (tpy) Texas LNG plant in Brownsville, Tex., following completion of an additional social cost of carbon and environmental justice analysis related to the project. The order includes two modified mitigation requirements regarding air monitoring and emergency response communications that Texas LNG will incorporate into its execution plan.

Texas LNG expects to take final investment decision by end-2023 and begin commercial operations in 2027. Samsung Engineering Co. Ltd. owns a minority equity interest in the plant and is leading its delivery along with Technip Energies USA.

Glenfarne says the project’s “Green by Design” approach is meant to avoid emissions rather than minimize or mitigate them. By using renewable energy to drive Texas LNG’s electric motors, the project’s CO2 emissions will be less than half of a typical LNG plant, according to the company.

Texas LNG and Enbridge Inc. last year agreed to expand the Valley Crossing pipeline to deliver 720 MMcfd of natural gas to Texas LNG for a term of at least 20 years (OGJ Online, Jan. 19, 2022).

Glenfarne is also the sole owner and developer of the 8.8-million tpy Magnolia LNG plant in Lake Charles, La., with an Apr. 15, 2026, FERC deadline to put it in service. The same deadline applies to the 1.4-bcfd Lake Charles Expansion of the Kinder Morgan Louisiana Pipeline, which will supply the plant (OGJ Online, Aug. 1, 2022).

FERC also issued a letter of remand for NextDecade Corp.’s 27-million tpy Brownsville LNG plant, likewise sited in Brownsville, Tex.

TotalEnergies delivers first cargo to India’s Dhamra LNG terminal

TotalEnergies has delivered a first LNG cargo to the Dhamra LNG terminal in Odisha on the east coast of India, enabling the gradual commissioning of the terminal, which is expected to begin commercial operations at the end of May. The cargo originated in Qatar.

With regasification capacity of 5 million metric tons/year (tpy) of LNG, the Dhamra LNG terminal adds more than 10% to India’s regasification capacity, allowing it to increase the share of natural gas in its energy mix to 15% from 8%, TotalEnergies said in a release Apr. 17.

The terminal is owned and operated by Adani Total Private Ltd. (ATPL), a 50-50 joint venture between TotalEnergies and Adani (OGJ Online, Oct. 14, 2019).

QatarEnergy selects Sinopec as NFE expansion partner

QatarEnergy has farmed out a stake in the North Field East (NFE) expansion project to China Petrochemical Corp. (Sinopec), the first Asian shareholder in the project.

The agreement marks the entry of Sinopec as a shareholder in one of the NFE joint venture companies that own the NFE project, the operator said in a release Apr. 12. In the deal, QatarEnergy will transfer to Sinopec a 5% interest in the equivalent of one NFE train with a capacity of 8 million tonnes/year (tpy).

In November 2022, the two companies signed the first and longest LNG supply agreement with a deal for 4 million tpy from the project.

The farmout is the first of its kind after last year’s series of partnership announcements in the $28.75 billion NFE project, QatarEnergy said. The project aims to raise Qatar’s LNG export capacity to 110 million tpy from the current 77 million tpy. The agreement, the operator noted, does not affect the participating interests of any of the other shareholders.