OGJ Newsletter

GENERAL INTEREST Quick Takes

EIA forecasts wider Brent-WTI spread next year

In its August issue Short-Term Energy Outlook (STEO), the US Energy Information Administration (EIA) changed its forecast for the Brent and WTI crude oil price spread. Changes to sources of Europe’s crude oil imports following Russia’s invasion of Ukraine and the EU’s subsequent petroleum import ban have contributed to redirections in oil trade flows.

European countries are importing more crude oil from the US and exporting less crude oil to countries in Asia, contributing to the development of a crude oil import price premium in Europe. As a result, EIA anticipates this trend will maintain a wider price spread between Brent and WTI crude oil of $6/bbl in 2023, which is $2/bbl wider than in the July STEO.

Although supply disruptions have kept crude oil prices around $100/bbl, crude oil prices came down slightly in July as concerns of slower economic growth or a recession become more prevalent. These concerns are reflected in the University of Michigan’s survey of consumer sentiment, which recorded its lowest reading on record in June, with data going back to November 1952. Likewise, consumer sentiment in the Euro Area has decreased, reaching record lows in July.

The price of WTI decreased by more than Brent. The price spread between Brent and WTI increased to a high of $13.26/bbl on July 29, the highest price spread since Jan. 14, 2014. This wide Brent-WTI spread, which reflects supply and demand dynamics in Northwest Europe, came down in the first few trading days of August but remains high.

EIA forecast the spot price of Brent crude oil will average $105/bbl in 2022 and $95/bbl in 2023. US crude oil production in the forecast averages 11.9 million b/d in 2022 and 12.7 million b/d in 2023, which would set a record for most US crude oil production in a year. The current record is 12.3 million b/d, set in 2019.

EIA estimates that 98.8 million b/d of petroleum and liquid fuels was consumed globally in July 2022, an increase of 0.9 million b/d from July 2021. Global consumption of petroleum and liquid fuels will average 99.4 million b/d for all of 2022, which is a 2.1 million b/d increase from 2021. Global consumption of petroleum and liquid fuels will increase by another 2.1 million b/d in 2023 to average 101.5 million b/d.

The US retail price for regular grade gasoline averaged $4.56/gal in July, and the average retail diesel price was $5.49/gal. EIA expect retail gasoline prices to average $4.29/gal in third-quarter 2022 and to fall to an average of $3.78/gal in fourth-quarter 2022.

US refineries average 93% utilization in third-quarter 2022 in EIA’s forecast, a result of high wholesale product margins. Elevated prices for gasoline and diesel reflect refining margins for those products that are at or near record highs amid low inventory levels.

ACCC recommends review, renegotiation of gas agreement

The Australian Competition and Consumer Commission (ACCC) has released its July 2022 interim report on the Australian east coast gas market which suggests the supply outlook has significantly worsened in the last 12 months.

The report forecasts a potential shortfall of 56 petajoules in 2023.

The Commission has recommended the Federal Government Minister for Resources initiate the first step of the Australian Domestic Gas Security Mechanism (ADGSM), said Gina Cass-Gottlieb, ACCC chair, while urging east coast LNG exporters at Queensland’s Curtis Island LNG plants to immediately increase supply into the domestic market.

The report said the LNG exporters had influence over nearly 90% of the proven and probable gas reserves in the east coast last year through direct interests, joint ventures, and exclusivity arrangements.

Forecast gas production for 2023 is around 1,981 petajoules, of which 1,299 petajoules (65.6%) is expected to be exported under long-term contracts. The LNG companies are expected to produce around 167 petajoules over what is required to meet contractual commitments.

Cass-Gottlieb said that LNG exporters have increasingly diverted up to 70% of their excess gas to overseas spot markets in recent years. If all the uncontracted gas went overseas, east coast domestic markets would face a supply shortfall, she said.

The ACCC report expressed concerns that some LNG exporters are not engaging with the domestic market in the spirit of the heads of agreement signed early in 2021 which commits exporters to offer uncontracted gas to the domestic market first on internationally competitive market terms.

The ACCC has also examined the upstream competition and timeliness of gas supply and found that the market is highly concentrated and dominated by three LNG exporters and their associates.

The LNG companies influence supply through numerous joint ventures and exclusivity agreements, contributing to the lack of effective upstream competition in the east coast, the Commission said.

In response to the report, the government has committed to a review and renegotiation of the ADGSM and the heads of agreement with LNG exporters.

Shell earns record $11.5 billion profit

Shell reported a second-quarter profit of $11.5 billion, surpassing a record set 3 months earlier, helped by higher energy prices, strong natural gas trading, and a tripling of refining profit. Second quarter adjusted earnings were $11.47 billion, up from $5.5 billion a year earlier and up from $9.1 billion in first-quarter 2022. Adjusted EBITDA was $23.1 billion in second-quarter 2022 versus $19.0 billion in first-quarter 2022.

The company reported a $6-billion share buyback program for the quarter, which is expected to be completed by third-quarter 2022. With the current energy sector outlook and subject to board approval, shareholder distributions are expected to remain in excess of 30% of cash flow from operations (CFFO).

Shell’s CFFO increased by $3.8 billion versus first-quarter 2022 to $18.7 billion, driven by higher adjusted EBITDA and lower working capital outflows.

Shell also said it had received a $165 million dividend payment in April from the Russian Sakhalin-2 oil and gas joint venture that it intends to exit.

Refining margins tripled to $28/bbl in the quarter, despite recent weakness on signs of slowing gasoline demand in the US and Asia. Shell said its refinery utilization rate would improve to 90-98% in the third quarter, compared with 84% in the second quarter.

Shell’s oil and gas production in the second quarter fell 2% from the previous quarter to 2.9 MMboed. 

Its LNG liquefaction volume in the second quarter was 7.66 million tonnes, down from 8 million tonnes in the previous quarter. Volumes are expected to fall to 6.9-7.5 million tonnes in the third quarter due to strikes at its Australian Prelude site and planned maintenance.

Shell’s net debt was reduced by around $2.1 billion (4%) to $46.4 billion in second-quarter 2022.

 Exploration & Development Quick Takes

Aker BP makes discovery near Skarv

Aker BP ASA will consider production of an oil and gas discovery made 14 km northeast of Skarv field in the Norwegian Sea and 220 km west of Sandnessjøen.

Well 6507/3-15 was drilled in production license 941 by the Deepsea Nordkapp drilling rig to a vertical depth of 2,197 m subsea. It was terminated in the Åre formation in the Lower Jurassic. Water depth at the site is 348 m. The primary exploration target was to prove petroleum in reservoir rocks from the Middle Jurassic (Fangst group). The secondary target was to prove petroleum in reservoir rocks from the Lower Jurassic (Båt group). 

The well encountered an oil and gas column totaling about 115 m in the Fangst and Båt groups, 40 m of which was in sandstone layers with good reservoir quality in the Fangst group, and about 55 m in sandstone layers with moderate to good reservoir quality in the Båt group.

There was an additional 100 m of sandstone layers in the Båt group with moderate to good reservoir quality. The respective gas-oil and oil-water contacts were encountered at 1,980 m and 2,021 m subsea. Preliminary estimates place the size of the discovery at 1.7-5.7 million std cu m of recoverable oil equivalent.

The well was not formation-tested, but extensive data acquisition and sampling were carried out. The well will be plugged.

Aker BP is operator of the license with 80% interest. PGNiG Upstream Norway AS holds the remaining 20%.

Neptune Energy lets vessel services contract for Cygnus field work

Neptune Energy let a 3-year vessel services contract with two 1-year extensions to Sentinel Marine to provide offshore support for Cygnus gas field in the UK southern North Sea.

The contract, valued at £10 million, will see Sentinel Marine continue to deploy its Multi Role, Emergency Response & Rescue vessel, Cygnus Sentinel, on the field. The vessel also will support an upcoming drilling campaign on Cygnus field. Neptune, on its website, said two wells expected to be drilled this year will help to maintain production from the field and offset natural decline.

Cygnus is the largest single producing gas field in the UK, typically exporting over 250 MMscfd of gas. Two drilling centers target 10 wells. Cygnus Alpha consists of three bridge-linked platforms: a wellhead drilling center, a processing-utilities unit and living quarters-central control room. Cygnus Bravo, an unmanned satellite platform, is about 7 km northwest of Cygnus Alpha.

Gas is exported via a 55 km pipeline. Cygnus connects via the Esmond Transmission System pipeline to the gas-treatment terminal at Bacton, Norfolk.

Neptune Energy is operator at the field with 38.75% interest. Spirit Energy holds 61.25%.

Po Valley gains approval for Italy gas field development

Po Valley Energy Ltd. received approval by Italy’s Ministry of Ecological Transition for development at Podere Maiar gas field in Po Valley, onshore northern Italy, according to a release from Prospex Energy PLC.

Work to connect the suspended Podere Maiar-1 to the national gas grid will begin by awarding contracts for construction of automated gas plant infrastructure, and installation of a 1,000-m 4-in. pipeline. First gas is anticipated in first-half 2023.

Based on dynamic reservoir studies, the field, in the Selva Malvezzi production concession, will produce a maximum rate of up to 5.3 MMcfd from successfully tested C1 and C2 production levels in the Medium-Upper Pliocene sands of the Porto Garibaldi formation.

Po Valley Energy is operator of the Selva Malvezzi concession (63%). Prospex Energy holds the remaining 37%.

Shell confirms Colombian Caribbean gas province extension

A well drilled by Shell plc has confirmed the extension of a gas discovery made in 2017 in ultra-deep waters in the southern Colombian Caribbean, project partner Ecopetrol SA said.

The Gorgon-2 exploration and delineation well, 70 km off the coast in Col-5 block, verified the presence of gas and confirms the extension of the Gorgon-1 gas discovery with a water column of about 2,400 m, the largest carried out in Colombia, and a total depth greater than 4,000 m. Kronos (2015) and Purple Angel (2017) discoveries were also made in the gas province.

Shell is operator of the South Caribbean blocks (Col-5, Fuerte Sur, Purple Angel) in a 50-50 partnership with Ecopetrol.

North Sea Tyra redevelopment delayed

The North Sea Tyra redevelopment project has been delayed. First gas at Tyra II is now expected in winter 2023-2024, partner Norwegian Energy Co. ASA (Noreco) said in a release Aug. 3. First gas was previously expected in second-quarter 2023.

The revision has been driven by global supply chain challenges that have impacted the extent to which fabrication work on the process module (TEG) has been completed. With load-out beginning in early August, TEG will leave McDermott’s yard in Batam in an incomplete state. Seven of eight modules are already installed offshore.

Sail away of the module is expected in early September. The TEG will be transported to Tyra field by heavy lift vessel GPO Emerald followed by lift and installation by Heerema’s Sleipinir.

Tyra is the largest gas condensate field in the Danish sector of the North Sea. Its infrastructure processes over 90% of gas produced in Denmark, as well as the entire gas production of the Danish Underground Consortium comprised of TotalEnergies SE 43.2% (operator); Noreco 36.8%, and Nordsøfonden 20%.

 Drilling & Production Quick Takes

ADNOC lets drilling contracts worth $3.4 billion

Abu Dhabi National Oil Co. (ADNOC) has let two 15-year contracts totaling more than $3.4 billion to ADNOC Drilling to hire eight jack-up offshore rigs. The contracts, valued at $1.5 billion and $1.9 billion respectively, awarded by ADNOC Offshore, will support expansion of ADNOC’s crude oil production capacity to 5 million b/d by 2030 and enable gas self-sufficiency for the UAE, the company said in an early August release.

Eni acquires Tango FLNG for Congo production

Eni SPA will tie in the Tango floating liquefaction vessel to the Marine XII block natural gas development project, 20 km from the coast of the Republic of the Congo on the continental shelf in 20-90 m of water.

LNG production from Marine XII is expected to begin in 2023, and when fully operational it will provide volumes more than 4.5 billion cu m/year.

The Tango FLNG is owned by Export LNG Ltd., which Eni acquired from Exmar Group. It was built in 2017 and has a treatment capacity of about 3 million std cu m/d and an LNG production capacity of about 1 billion std cu m/year.

Five fields have been discovered in the Marine XII area, with 1.3 billion boe proven and probable reserves (2P).

Eni is operator with 65% interest. Partners are PJSC Lukoil (25%) and Societe Nationale des Petroles du Congo (10%).

Maha Energy lets drilling contract for 6-well campaign onshore Oman

Maha Energy AB let a contract to Gulf Drilling LLC, a subsidiary of MB Petroleum Services Worldwide, in Muscat, Oman, for the drilling of a minimum of six wells on Block 70 onshore Oman.

The Gulf Drilling 109 rig, currently in Adam, Oman, will be prepared with expected mobilization in October.

Plans for drilling Mafraq field include obtaining reservoir information to assist in developing a full field development plan, Maha said in a release Aug. 2. Information to be acquired from two appraisal wells includes the oil water contact, petrophysical and structural properties, and the identification of possible water disposal zones.

Four horizontal pilot production test wells will be drilled on the structure to ascertain oil productivity. These wells will be completed with progressive cavity pumps (PCP) from Canada and then placed on an extended flow test.

The Mafraq structure is a delineated heavy oil field that was tested by Petroleum Development Oman in 1988 and 1991. The field tested 15,700 bbl of 13° API oil over a period of 24 days using a PCP from a single well. Well MF-5 tested 100% oil for less than 1 day after which water encroachment stabilized at a 25-28% water cut.

Mafraq field may hold 35 million bbl of recoverable oil, according to Chapman Petroleum Engineering Ltd. The structure is an east-west fault bounded anticline with the productive interval about 430 m below ground.

Serinus Energy spuds first of two wells in Romania

Serinus Energy PLC spudded the Canar-1 exploration well on the northern flank of Carei basin, about 4 km west of the company’s Moftinu gas plant in Romania.

The well will be drilled to a depth of 1,600 m, targeting three prospective hydrocarbon zones. The company is looking for additional hydrocarbons on the migration path from the Carei basin source kitchen. If successful, production from the well will be connected to the gas plant, utilizing existing capacity.

Upon completion of Canar-1, Serinus expects to drill Moftinu Nord-1. Moftinu Nord is a distinct gas prospect 5.2 km northwest of the Moftinu gas plant.

 PROCESSING Quick Takes

Targa unveils plan for new Permian gas processing plant

Targa Resources Corp. is adding another cryogenic natural gas processing plant to its expanding operations in the Permian Midland as part of the operator’s broader strategy to further extend its Permian basin gathering and processing position amid heightened demand from producers.

In response to rising regional production and to meet infrastructure needs of producers, Targa plans to build and commission the new 275-MMcfd Greenwood plant in its Midland basin system by the end of fourth-quarter 2023, the operator told investors on its second-quarter 2022 earnings call.

Targa said the proposed Greenwood plant will follow startup of two additional Permian Midland plants currently under construction as part of the operator’s system in Upton County, Tex., including the 275-MMcfd Legacy I and 275 Legacy II plants, which are scheduled to enter service in late third-quarter 2022 and second-quarter 2023, respectively.

The operator also confirmed ongoing progress with expansion of its existing Permian Delaware system in West Texas and southeastern New Mexico, with construction of the 275-MMcfd Midway plant proceeding as planned for a targeted commissioning in third-quarter 2023. Elsewhere in the Delaware basin, in Lea County, NM, Targa said it also will startup the new 230-MMcfd Red Hills VI plant by the end of third-quarter 2022.

In its quarterly earnings presentation, Targa said the new Permian gas processing plants—all of which will be electric-drive to improve operational performance, as well as provide incremental capacity to enhance overall system flexibility—will support increased flows of NGLs along the operator’s Grand Prix pipeline that connects its Permian gathering and processing system to Targa’s existing eight fractionators and export dock in Mont Belvieu, Tex., on the Texas Gulf Coast.

To accommodate additional NGL volumes along the Grand Prix, Targa also revealed it will add a ninth fractionator at its Mont Belvieu complex. The 120,000-b/d Train 9 fractionator is scheduled for startup in second-quarter 2024.

Marathon on track for Martinez refinery-to-renewables conversion

Marathon Petroleum Corp. (MPC) is progressing with its project to strategically reposition its now-idled Martinez refinery in northern California’s San Francisco Bay area into a renewable fuels production site.

Following the Bay Area Air Quality Management District’s (BAAQMD) recent preliminary approval of the site’s air quality permit, the first phase of the Martinez Renewable Fuels (MRF) project—which, once operable, would bring nearly 50,000 b/d [260 million gal/year] of renewable diesel supply into the market—is currently targeted for mechanical completion by yearend 2022, Mike Hennigan, chief executive officer, told investors in the company’s Aug. 2 earnings call.

With proposed pretreatment unit capabilities at Martinez anticipated for startup during second-half 2023, MPC—which agreed to a 50-50 JV partnership on the $1.2-billion MRF with Neste in March 2022—said it currently expects the refinery to reach full nameplate production capacity of 730 million gal/year by yearend 2023.

Timelines for achieving MRF’s proposed production capacities and closing the Neste JV, however, still depend on when MPC obtains a final air quality permit for the project, Hennigan said.

MPC’s announcement follows a July 22 public notice by BAAQMD—the local agency that regulates stationary sources of industrial air pollution—of its preliminary determination that the MRF will comply with all local, state, and federal air quality-related regulations, including health risks resulting from toxic air contaminant emissions, according to an official agency release.

BAAQMD’s preliminary recommendation to issue a final permit for the project remains subject to a public comment period on the draft air permit that runs through Aug. 23.

“[W]hen that public comment period ends, [BAAQMD], along with [MPC] providing input, will respond to any comments, and that should be the end [of the permitting process],” said Ray Brooks, MPC’s executive vice-president of refining.

“[G]etting the air permit will be a big deal that allows us to…start the unit up when it’s ready, and it also allows us to close our JV partnership with Neste,” Brooks said.

MPC also confirmed it continues to make progress on its ongoing South Texas Asset Repositioning (STAR) program at the 593,000-b/d Galveston Bay refinery in Texas City, Tex., which has included works to further integrate the operator’s former Texas City refinery into the adjacent Galveston Bay refinery to improve the site’s efficiency and reliability by increasing residual oil processing capabilities, upgrading the crude unit, and integrating logistics.

Currently scheduled for completion in early 2023, the STAR project is projected to increase crude capacity at Galveston Bay by 40,000 b/d.

 TRANSPORTATION Quick Takes

Santos buys pipeline to move Narrabri gas

Santos Ltd. has acquired Hunter Gas Pipeline Pty Ltd., owner of an approved route for a buried gas pipeline from Wallumbilla in southeast Queensland to Newcastle in coastal New South Wales.

The route passes near Santos’ proposed Narrabri coal seam gas project in New South Wales. Santos plans to work with infrastructure developers and owners to construct the pipeline, which will also be designed to transport hydrogen, to deliver Narrabri gas to Australia’s east coast markets in the shortest timeframe possible.

Appraisal drilling at Narrabri is planned for later this year pending native title and environmental management plan approvals. Once fully operational, Narrabri has the potential to deliver more than half New South Wales’ gas demand, Santos said.

The Hunter Gas Pipeline has planning approval and, when constructed, will connect the Wallumbilla gas supply hub to New South Wales, providing a second route from Queensland to southern Australian markets.

Pipeline construction is expected to begin early 2024.

Delfin, Centrica reach 1-million tpy LNG offtake agreement

Delfin Midstream Inc. and Centrica PLC have signed a heads of agreement for Centrica’s purchase of 1 million tonnes/year (tpy) of LNG for 15-years on a free-on-board basis from the planned 13-million tpy Delfin Deepwater Port, 40 nautical miles off the coast of Louisiana.

Delfin hopes to take final investment decision (FID) on the project’s first vessel by end-2022 to begin operations in 2026. The offshore port will be built in 3.5-million tpy increments using floating LNG (FLNG) plants, with FID also being approached incrementally.

The company last month finalized a binding 15-year sales agreement with Vitol Inc. for 0.5 million tpy.

The project will use 2-6 FLNG plants connected to onshore gas supplies via subsidiary-owned pipelines.

ONEOK second-quarter net income up 21% y-o-y

ONEOK Inc., Oklahoma City, Okla., increased net income 21% to $414.4 million in second-quarter 2022 from the same period last year. Adjusted earnings increased 11% for the same period when compared to a year ago.

In May, a 25,000 b/d expansion on a portion of ONEOK’s West Texas NGL pipeline was completed. In April, a 1.1-bcf expansion of Texas natural gas storage capacity was completed. The company is currently expanding Oklahoma storage capabilities by 4 bcf, expected to be complete in second-quarter 2023.

Construction of the 200-MMcfd Demicks Lake III natural gas processing plant in the Williston basin is expected to be complete in first-quarter 2023.

Construction of the 125,000-b/d MB-5 fractionator in Mont Belvieu, Tex., is expected to be complete early in second-quarter 2023.

The company’s 210,000-b/d Medford, Okla., NGL fractionation plant remains out of service following a fire July 9, 2022. The plant is expected to remain out of service for an extended period, but the company’s integrated NGL pipeline, fractionation and storage assets between the mid-continent and Gulf Coast, and fractionation and storage arrangements with industry peers have allowed ONEOK to provide midstream services, the company said.