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Suncor Energy Inc. has signed a memorandum of understanding (MoU) with Fort McKay First Nation (FMFN) regarding a prospective oil sands lease development opportunity on Fort McKay reserve lands in the Regional Municipality of Wood Buffalo.

Under the MoU, Suncor aims to progress early stage technical and commercial feasibility assessments to determine the quality and quantity of economically recoverable mineable ore on Lease 174C, which is FMFN Reserve Land, according to a joint news release Thursday.

“We are honored to be working with Fort McKay First Nation. Through this partnership, Fort McKay First Nation has the opportunity to govern oil sands activity on their land and fully participate and benefit from responsible resource development”, Suncor Executive Vice President for Oil Sands Peter Zebedee said. “This potential opportunity, which has synergies with Suncor’s existing operations, could provide Suncor with bitumen supply optionality post 2040”.

“With this agreement, we are creating the conditions for sustainable prosperity, growth and health for our Nation for generations to come, while leading the way on protecting our land and water”, FMFN Chief Raymond Powder said. “We will bring our values of stewardship and care to this opportunity. In doing so, we are charting a new path for economic development on our lands”.

“Our people of Fort McKay First Nation have diligently worked hard for years as a collaborative and reliable partner. This has resulted in building the Nation for opportunities while securing future growth in our community. This is the true meaning of reconciliation. It puts in our hands the tools we need to bring prosperity and a sustainable future for our people”, Powder added.

According to the release, FMFN and Suncor are “committed to facilitating economic self-determination for Indigenous communities based on mutual trust and respect” and share the goal of “maximizing mutual prosperity while minimizing environmental impacts, including supporting Suncor’s commitment to achieving net-zero emissions from its operations by 2050”.

Fort McKay First Nation has more than 900 band members of Dene and Cree heritage residing on the reserve and abroad. The community is located 31 miles (50 kilometers) north of Fort McMurray along the shores of the Athabasca River.

In addition to the Fort McKay community, FMFN has Reserves 174A at Gardiner (Moose) Lake and 174B at Namur (Buffalo) Lake, approximately 40.4 miles (65 kilometers) northwest of Fort McKay. Moose Lake is the traditional home of what is now the Fort McKay First Nation people.

The Nation also manages a business portfolio of 18 entities. Business revenues are invested in infrastructure, programs, and services, and directly benefit both the community of Fort McKay and individual band members, according to the release.

FMFN in December 2023 announced a co-investment with ATB Private Equity to acquire a combined 51 percent interest in Apex Geoscience Ltd., a global geological consulting firm, which it called “a strategic move to enhance economic opportunities and strengthen FMFN’s presence in the geoscience sector”.

FMFN and ATB PE each acquired a 25.5 percent stake in Apex Geoscience for a joint 51 percent majority ownership of the company.

“This partnership is a significant step for Fort McKay First Nation as we continue to actively diversify our economic ventures. Teaming up with ATB Private Equity to acquire a majority stake in Apex Geoscience Ltd positions us for sustainable growth and opportunities in the geoscience sector”, FMFN Councilor Bobby Shott said.

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Europe is set to end the heating season with so much gas that the idea of storing more fuel in Ukraine to avoid a price crash is becoming attractive, despite the security risks of such a move.

The region is heading into March with storage facilities over 62% full — a record for the time of the year — according to data from Gas Infrastructure Europe. The continent is nearing the end of what has been an exceptionally mild winter, which has weighed on fuel needs and will lead to less injection capacity over the summer months.

“European storage is at risk of hitting tank tops before the beginning of the heating season,” analysts at Energy Aspects Ltd. wrote in a note this week. “As such, European traders must make use of floating and Ukrainian storage. Lower summer prices relative to the winter contract will support the economics of the use of both.”

Floating storage — the practice of keeping liquefied natural gas on vessels for longer before unloading — is typically used when traders anticipate being able to sell it at higher prices later or when regular underground facilities are full.

While front-month contracts rose on Friday, prices continue to hover near €25 per megawatt-hour, a level that many traders see as a floor after declining more than 20% since the start of the year. Contracts for delivery during summer have also fallen in recent weeks as the focus shifts to April, which marks the end of winter for the gas industry. 

Ukraine is offering traders outside of the country to book as much as 10 billion cubic meters of its natural gas storage capacity this year, according to state-run oil and gas firm NJSC Naftogaz Ukrainy. The volume that can be earmarked for foreign companies comprises about a third of the nation’s total capacity and is on par with last year’s level.

Long one of the key links in gas trade with Europe, Ukraine has more storage capacity than any other country on the continent, west of Russia. Stored fuel almost dropped to zero following Russia’s invasion, but has bounced back since last year, with companies including Shell Plc and DXT Commodities using its facilities, Bloomberg previously reported. 

Meanwhile, most of Europe is set to see a continuation of mild weather in early March, helping to keep a lid on energy prices. From the UK to France and Germany, the region’s biggest markets will be warmer than usual during the first two weeks of the month, according to meteorologists surveyed by Bloomberg. 

Dutch front-month futures, Europe’s gas benchmark, rose 1.8% to €25.31 a megawatt-hour at 10:04 a.m. in Amsterdam. The UK equivalent contract also rose. 

Chord Energy Corp. reported a slip in its net income for the fourth quarter of 2023, as well as the full year. In a media release, the company said its net income for the last three months of the year stood at $301 million versus $377.6 million for Q4 2022. Its full year net income stood at $1.02 billion, down from the $1.85 billion reported for 2022.

During the quarter, Chord recorded oil volumes of 106.2 million barrels of oil per day (MMbopd), with total volumes for the quarter reaching 183.8 million barrels of oil equivalents per day (MMboepd). Both oil volumes and total volumes exceeded the high-end guidance.

“Chord closed 2023 on sound footing by executing on its program and delivering strong volume growth in the second half of the year”, said Danny Brown, Chord Energy’s President and Chief Executive Officer.

“2023 was a pivotal year for the Company as three-mile wells were approximately 50 percent of the mix, and execution and well performance continue to meet or exceed expectations”, he said.

Going forward, the company made a major step toward creating a premier Williston-focused exploration and production company through a newly agreed $11 billion combination with Enerplus Corp. Under the terms of the transaction, each common share of Enerplus will be exchanged for 0.10125 shares of Chord common stock and $1.84 per share in cash, representing 90 percent stock and 10 percent cash consideration. Upon completion of the transaction, Chord shareholders will own approximately 67 percent of the combined company and Enerplus shareholders will own approximately 33 percent, the two companies said in a joint media release.

“This combination further strengthens our Williston Basin position and represents a compelling opportunity for both companies’ shareholders”, said Danny Brown, Chord’s President and Chief Executive Officer. “Enerplus’ Williston Basin position brings high-quality inventory, and we are excited to leverage best practices from both companies to create a stronger, more efficient entity”.

The combined company is expected to be a premier operator in the Williston Basin, with approximately 1.3 million net acres (98 percent Williston) and 4Q23 production of 287 MMoepd (over 90 percent Williston). Oil is expected to be approximately 56 percent of the combined company’s production, the two companies said.

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In a report sent to Rigzone late Tuesday, Macquarie strategists revealed that they are forecasting that U.S. crude inventories will be up 8.4 million barrels for the week ending February 16.

“This compares to a 12.0 million barrel build for the week ending February 9, with the total U.S. crude balance realizing modestly tighter than we had anticipated, despite the heavy build,” the strategists noted in the report.

“For this week, from refineries, we model a further reduction in crude runs (-0.2 million barrels per day). Among net imports, we anticipate a nominal week on week decrease, with exports higher on a nominal basis (+0.8 million barrels per day) and imports also up (+0.4 million barrels per day),” they added.

“Timing of cargoes remains a source of potential volatility in this week’s crude balance. From implied domestic supply (prod.+adj.+transfers), we look for a modest nominal decrease (-0.3 million barrels per day) relative to last week’s strong print,” they went on to state.

In the report, the strategists revealed that they anticipate a 0.7 million barrel increase in Strategic Petroleum Reserve (SPR) inventory on the week.

“At Cushing, our refinery/pipeline model is calling for a build of 0.15 million barrels this week,” the Macquarie strategists added in the report.

“Among products, we look for meaningful draws in gasoline (-4.4 million barrels) and distillate (-2.4 million barrels), with jet stocks minimally lower. We model implied demand for these three products at ~13.6 million barrels per day for the week ending February 16,” they added.

In its latest weekly petroleum status report, which was released on Valentine’s Day, the U.S. Energy Information Administration (EIA) revealed that U.S. commercial crude oil inventories, excluding those in the SPR, rose by 12.0 million barrels from the week ending February 2 to the week ending February 9.

Crude oil stocks in the U.S., not including the SPR, stood at 439.5 million barrels on February 9, 427.4 million barrels on February 2, and 471.4 million barrels on February 10, 2023, that EIA report showed. Crude oil in the SPR totaled 358.8 million barrels on February 9, 358.0 million barrels on February 2, and 371.6 million barrels on February 10, 2023, the report revealed.

In a report sent to Rigzone prior to the release of the EIA’s latest weekly petroleum status report, Macquarie strategists said they were forecasting that U.S. crude inventories would be up by 13.9 million barrels for the week ending February 9. In that report, the Macquarie strategists highlighted that they were projecting a 0.8 million barrel SPR build on the week.

In a report sent to Rigzone following the release of the EIA’s weekly petroleum status report, SEB Commodities Analyst Ole Hvalbye highlighted that the latest commercial crude oil inventory figure represented a “2.8 percent rise from the previous week, but still a substantial 6.8 percent decrease from the same period last year”.

“The surge exceeds typical seasonal adjustments, indicating potential reduced crude demand, and a more well-balanced market,” Hvalbe said in the report.

The EIA’s next weekly petroleum status report is currently scheduled to be released on February 22. It will show data for the week ending February 16.

The EIA Weekly Petroleum Status Report provides timely information on supply and selected prices of crude oil and principal petroleum products, the report itself notes, adding that it provides the industry, press, planners, policymakers, consumers, analysts, and State and local governments with a ready, reliable source of current information.

The report is prepared by the EIA, which describes itself as the independent statistical and analytical agency within the U.S. Department of Energy.

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Var Energi’s drilling results for the wells 25/7-12 S and A, some 124 miles northwest of Stavanger in the North Sea, have shown both assets dry.

The Hubert and Magellan prospects were drilled in production license 917, awarded in 2017, the Norwegian Offshore Directorate (NOD) said in a news release announcing the development. The Deepsea Yantai rig was used for the drilling operation.

These were the third and fourth wells in this production license, according to the NOD. Multiple discoveries have been made in this area in recent years, where infrastructure is well developed, it said. Var Energi operates the Balder and Ringhorne East fields, while Equinor operates the Grane, Svalin and Breidablikk fields, the Directorate said.

According to the NOD, the primary and secondary exploration targets for wildcat well 25/7-12 S were proving petroleum in Paleocene reservoir rocks in the Hermod and Sele formations, respectively. The primary and secondary exploration targets for wildcat well 25/7-12 A were proving petroleum in Eocene reservoir rocks in the Balder and Horda formations, respectively, it said.

Well 25/7-12 S encountered the Hermod formation with a total thickness of 112 feet, of which 98 feet were sandstone rocks of good reservoir quality. The well was dry. Well 25/7-12 S was drilled to respective measured and vertical depths of 7352 feet and 6280 feet below sea level, and was terminated in the Sele formation in the Paleocene, according to the Directorate.

Well 25/7-12 A encountered the Horda formation with a total thickness of 160 feet, of which about 2.5 feet were sandstone rocks with good to very good reservoir quality and with traces of gas. The Directorate said that the Balder formation was encountered with a thickness of 279 feet in total, of which about 36 feet was a sandstone layer with very good reservoir quality. The Hermod formation was encountered with a total thickness of 118 feet, of which 46 feet were of very good reservoir quality and with traces of hydrocarbons.

Well 25/7-12 A was drilled to respective measured and vertical depths of 6637 feet and 6437 feet below sea level, and was terminated in the Sele formation in the Paleocene. The water depth at the site is 416 feet, according to the directorate.

The wells have been permanently plugged and abandoned, it said.

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Oil rose after a bullish demand outlook from OPEC helped crude surpass a key technical level that had served as the ceiling of this year’s narrow trading band.

West Texas Intermediate rose 1.2% to settle near $78 a barrel, pushing past its 200-day moving average of about $77.40. With bulls also finding support from OPEC’s projections that global oil demand will continue strong growth this year, the breach above the technical threshold raises the possibility of additional upward momentum.

Oil’s gain came against a backdrop of broader risk-off sentiment after US data showed inflation remains elevated, reducing the prospect of imminent interest rate cuts.

“A rare day to see crude decouple from equities” said Rebecca Babin, a senior energy trader at CIBC Private Wealth. “Positioning, which has become increasingly important for the direction in crude, was pared down last week,” and “builds in inventories are expected this week and may temper upside.”

Earlier today, the Organization of the Petroleum Exporting Countries’ monthly report showed that the group’s new production cuts were only partially delivered in the first month. The broader OPEC+ alliance plans to decide early next month whether to extend their curbs into the second quarter.

While oil has advanced this year, it’s yet to break decisively higher. The OPEC cuts, as well as nervousness over the conflict in the Middle East and attacks on shipping in the Red Sea, have largely been offset by an uncertain demand outlook and ample output from outside the group.

Prices:

• WTI for March delivery rose 1.2% to settle at $77.87 a barrel in New York.
• Brent for April settlement advanced 0.9% to settle at $82.77 a barrel.

Meanwhile, a chunk of the vast fleet of tankers that Russia uses to deliver its crude is grinding to a halt under the weight of US sanctions, according to ship-by-ship tracking. That’s another sign that tougher measures by Western regulators might be starting to have tangible effects on Moscow.

Traders are also parsing the International Energy Agency’s outlook for crude supply and demand. The agency estimates that global consumption will increase by 1.2 million to 1.3 million barrels a day in 2024, which will be easily matched by swelling production from the Americas.

The Colorado Department of Public Health and Environment (CDPHE) recently announced at least $10.5 million in penalty and facility improvement payments against Suncor Energy Inc. accusing it of breaching air pollution control rules.

The demand, the biggest enforcement package for air pollution on a single facility, targets the Canadian integrated energy company’s oil refinery in Commerce City, the agency said in a news release.

“Many of Suncor’s violations were associated with power disruptions”, the CDPHE said. “The enforcement package addresses air pollution violations between July 2019 and June 2021.

“The violations included exceeding sulfur dioxide, carbon monoxide, and nitrogen oxides emissions limits; exceeding hydrogen sulfide concentration limits; exceeding opacity and visible emissions standards; failing to meet certain operating parameters; violations due to causes other than power disruptions”.

Calgary, Alberta-based Suncor has not replied to a Rigzone request for comment emailed Thursday.

The refinery processes about 98,000 barrels a day of petroleum sourced from the Denver-Julesburg basin, according to Suncor. Ninety-five percent of the output is sold to the state, whose economy reaps $2.5 billion per year from the plant, Suncor says on its website.

“Suncor must pay at least $10.5 million toward penalties and projects as a result of air pollution violations from July 2019 through June 2021”, the CDPHE said. “This action holds Suncor accountable for past violations and requires the refinery to take steps to prevent future violations”.

Penalties accounted for $2.5 million. “Of this amount, about $1.3 million will fund projects to benefit disproportionately impacted communities through the state’s environmental justice grant program, and about 40 percent will go toward the state’s general fund”, it added referring to a grant created by the state’s 2021 Environmental Justice Act. “A small portion will go to the U.S. Environmental Protection Agency as required by a previous joint U.S. EPA/Colorado enforcement action”.

The rest of the enforcement package is for improvements to the facility “to minimize excess air pollution from recurring due to power-related causes”, the CDPHE said.

It also ordered Suncor to double the number of air pollution monitoring devices around the refinery under Colorado’s so-called fenceline monitoring program, which is contained in the state’s 2021 Air Toxics Act. Suncor’s Commerce refinery is one of four facilities covered by the fenceline monitoring program, which involves running air measurement equipment covering the facilities’ perimeter.

“The final fenceline monitoring plan includes double the number of air monitors compared to what Suncor submitted”, the CDPHE said. “The final plan ensures the monitoring will meet the state law’s requirement for continuous air monitoring and data sharing in near real-time.

“Colorado has also required Suncor to monitor and report on more air toxics than required by state law. State statute requires monitoring for hydrogen cyanide, hydrogen sulfide, and benzene. Suncor must also monitor and report for toluene, ethylbenzene, and xylenes when it implements the new fenceline monitoring plan”.

CDPHE Executive Director Jill Hunsaker Ryan highlighted in a statement, “This historic enforcement package, which includes both a penalty and required facility improvement projects, is the largest our agency has ever reached for a single facility for air pollution”.

CDPHE Air Pollution Control Division Director Michael Ogletree commented, “There are real consequences for air pollution violations – whether they be from Suncor or any other air pollution source in Colorado”.

“Today’s actions demonstrate that compliance with clean air laws is not optional”, Ogletree added.

Last year the federal Environmental Protection Agency (EPA) also imposed against Suncor a nearly $800,000 package under the national Clean Air Act involving the Commerce refinery. The package was a result of a settlement with Suncor over noncompliant fuel produced at the refinery.

“Suncor will pay a $160,660 civil penalty and has agreed to implement a supplemental environmental project which requires the company to spend at least $600,000 purchasing or subsidizing the purchase of electric lawn and garden equipment that will be provided to residents, schools, and local governments in the Commerce City/Denver area”, the EPA said in a statement September 6, 2023.

“The settlement resolves claims relating to the benzene content and Reid vapor pressure (RVP) of gasoline that Suncor produced”, the EPA explained. “In 2021, Suncor produced over 32 million gallons of gasoline at its Commerce City East Refinery with an average benzene concentration of 1.77 volume percent, which was above the maximum 1.30 volume percent standard. In June 2022, Suncor produced over 1 million gallons of summer gasoline at its Commerce City West Refinery with an RVP of 7.9 pounds per square inch (psi), which was above the 7.8 psi standard”.

Suncor had notified the EPA about both violations, the agency said.

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Venezuelan President Nicolás Maduro is betting the US won’t revive all of its sanctions as he backslides on a promise of free elections. Inside the nation’s oil industry, local operators are worried he’s wrong.

Oil and gas firms and contractors fear their nascent deals for everything from imports of new construction equipment to their connections with US banks will break off if Maduro’s ban of opposition candidates in this year’s election prompts the US to allow a six-month suspension on sanctions to expire in April.

“This is a major setback for small firms, which live on a day-to-day basis for their cash flow,” said Rubén Pérez, director at Chemstrategy, an energy consultancy in Caracas. “Bigger companies have previewed this scenario and can better resist. Sentiment moves between cautious optimism and grim faces.”

Reimposed sanctions would cause Venezuela’s oil production to fall 30% to 600,000 barrels a day in a matter of months, according to Fernando Ferreira, director of geopolitical risk at Rapidan Energy Group. Data compiled by Bloomberg show the country’s production in January increased 22% from a year earlier after the US eased sanctions in October, allowing US companies to engage with state-owned Petróleos de Venezuela SA.

Repsol SA executive managing director Francisco Gea, left, and Venezuela’s oil minister Pedro Rafael Tellechea during a news conference in Caracas on Dec. 18.

Venezuela’s top court ruled last month that opposition presidential candidate María Corina Machado was ineligible to hold office, flouting pressure from the US to allow her to run against Maduro. The US responded by reimposing sanctions on gold exports and saying it could reinstate oil sanctions in April if Venezuela doesn’t correct course.

Venezuela Oil Minister and PDVSA head Pedro Tellechea said last week that the country is “prepared” if oil sanctions are renewed and “open to dialog” on the issue.

But US President Joe Biden’s administration has its own reasons for not ending the sanctions. A steadier supply of the South American nation’s crude may help keep global oil prices — and more importantly, US gasoline prices — in check. Biden, potentially facing a tough reelection campaign against Donald Trump, also needs to find ways to stem the tide of migration to the US. A healthier Venezuelan economy may slow the outflows.

Still, four oil industry executives who spoke to Bloomberg on condition of anonymity said the renewed tensions are making them wonder whether their recent investments will be squandered. They asked not to be identified for fear of retaliation from the government.

Some local firms had sent representatives to the US to reinstate financial and commercial relations with US-based suppliers. Slowly, small and mid-sized oil-service companies were making progress, including on possible imports of construction equipment. 

PDVSA had also engaged in purchases for its facilities via third parties, according to a person familiar with the matter who asked not to be identified discussing private deliberations. PDVSA didn’t immediately respond to a request for comment.

License 44, as the US sanctions relief is known, was seen by local companies as a “positive boost for work demand starting first quarter 2024, but this hasn’t been fulfilled yet,” said César Parra, head of engineering and construction firm DICCA. Maintenance work and investment are needed in Zulia state, Venezuela’s oil cradle, where his company operates, he said.

Since October, when the sanctions were eased, Trinidad’s state-owned National Gas Co. and Shell Plc were granted exporting licenses, while Repsol SA and Maurel et Prom signed new deals to ramp up production. Delegations from Mexico’s Pemex, Bolivia’s YPFB and Indonesia’s Pertamina visited the country to review oil and gas partnerships, although no major deals were signed. 

It’s not clear if these deals would survive a re-imposition of sanctions. Trinidad received assurances from the US government in late January that a license on a key gas-import project involving Shell and Venezuela will stand, according to a report. 

“We’re not directly affected,” Trinidad and Tobago Prime Minister Keith Rowley said in a report in the Trinidad Guardian. 

Exxon Mobil Corp. and Chevron Corp. surpassed earnings forecasts as bigger-than-expected oil output from shale fields helped cushion the blow from weakening crude prices. 

Exxon rose more than 2% and Chevron climbed 1.9% in pre-market stock trading. Exxon’s outsized result also was aided by a $1.14 billion boost from unsettled derivatives and record fuel production at its refineries.

Chevron, meanwhile, posted adjusted earnings of $3.45 a share that exceeded the Bloomberg Consensus estimate by 23 cents. The oil explorer also raised its dividend by a higher-than-forecast 8%. 

The upbeat reports by North America’s biggest crude drillers follow similar results at Shell Plc, which kicked off Big Oil earnings season on Thursday with adjusted net income that was more than $1 billion higher than the average forecast. BP Plc and TotalEnergies SE are scheduled to disclose results next week.

Exxon’s trading unit delivered handsomely, reaping more than $1 billion in gains that more than offset the $410 million hit inflicted by lower crude prices. That strategy is a departure for a company that historically shunned trading as too risky and outside its traditional areas of expertise.

“We’re continuing to grow our trading footprint, and we saw strong trading results this year that flowed through” to the bottom line, Chief Financial Officer Kathy Mikells said during an interview.   

Both Exxon and Chevron are under pressure from investors to bolster cash flow by pumping more oil while simultaneously avoiding a price-killing supply glut. 

Exxon is attempting to thread the needle with a $60 billion takeover of Pioneer Natural Resources Co., which it expects to close around the middle of the year. The all-stock deal preserves cash for shareholders and widens Exxon’s portfolio of prime drilling targets in the Permian. Meanwhile, Chevron is taking a page from the same playbook with a $53 billion deal for Hess Corp. 

Pivoting to more profitable oil production is a key part of Exxon Chief Executive Officer Darren Woods’ plan to double earnings from 2019 to 2027. The Texas oil giant paid out the S&P 500’s fourth-largest combination of dividends and buybacks during the past 12 months. Its stock declined more than 9% last year despite a 24% gain in the broader market. 

Exxon ended the quarter with $31.6 billion of cash, about 4% lower than the previous period, mainly due to shareholder payouts. The company recorded a $2.3 billion one-off loss, which it previously flagged was related to the declining value of oil wells and other assets in California. 

As for Chevron, the No. 2 US oil explorer incurred $3.7 billion of charges stemming mostly from assets in its home state of California and the dismantling of decades-old infrastructure in the Gulf of Mexico. Annual production climbed 4%, primarily boosted by rising output in the Permian Basin and other US fields. 

Chevron is ramping up Permian production with a target of 10% growth this year that sets the company on course to pump 1 million barrels a day from the region in 2025. 

“We are in the best parts of the Permian,” Chief Financial Officer Pierre Breber said during an interview. “Our growth is higher likely than the basin average but it is representative of our activity level and the activity level of our partners.”

Europa Oil & Gas (Holdings) plc has received regulatory approval for the extension of the FEL 4/19 license offshore Ireland.

Ireland’s Department of the Environment, Climate and Communications (DECC) gave consent to extend the phase one license to January 31, 2026, Europa said in a news release Monday.

Europa said it intends to use the extension to carry out further technical studies and allow more time to secure a partner to advance development of the license.

“I am delighted that our application has been granted and that we can continue with further technical studies of the license and seeking a project partner”, Europa CEO Will Holland said. “FEL 4/19 contains the large 1.5 Tcf [trillion cubic feet], low risk Inishkea West gas prospect which is a strategic asset that can potentially provide a reliable source of low emission energy for Ireland and play a key role in the transition to renewable green power”.

“Given the proximity to existing infrastructure, a discovery at Inishkea West could be brought online quickly and would reduce Ireland’s reliance on imported gas. Domestic gas from Inishkea West would have significantly lower carbon emissions than imported gas from the UK, Norway or further afield”, Holland noted.

“We look forward to working constructively with DECC as we seek to progress FEL 4/19 to drilling, and to attract additional partners to this prospective license”, he concluded.

In October 2023, Europa announced that the Pmean prospective resource estimate for Inishkea West increased by 92 percent to 1.55 Tcf, based on the latest reprocessing of seismic data.

“The seismic data has been reprocessed using full waveform inversion and reverse time migration (RTM) to 20Hz, which are cutting edge techniques”, Europa noted in an earlier news release. The reprocessing resulted in “a marked improvement in the imaging of both the Inishkea West and Inishkea prospects, with the Inishkea West structure now being mapped as a large four-way closure”, it said, adding that the new analysis increased the chance of success of the prospect.

Inishkea West is within easy tie-back range of the Corrib gas field situated about 11.2 miles (18 kilometers) to the southeast, Europa noted. The proximity to the Corrib infrastructure, the mapped four-way closure, the large prospective resource and the reduced seal risk mean that the Inishkea West prospect has become “the primary target on the FEL 4/19 license”, the company said.

“This is a very exciting development for the FEL 4/19 licence as the seismic reprocessing has significantly enhanced the sub-surface imaging which has improved our understanding of the size of the prospects and the seal risk”, Holland said. “These results have more than justified the additional time and expenditure on what is a key asset for not only Europa, but also Ireland in terms of potential indigenous energy security and as part of the country’s energy transition”.

“The seal uncertainty, which the reprocessing has addressed, was a matter that some of the potential [partners] had highlighted during the farm-out process and potential partners wanted to see the results of the reprocessing before making an offer. However, we now believe that the sub-surface imaging can be further improved by reprocessing at 30Hz and we will therefore be applying for a phase one license extension to allow us to complete this work before continuing the farm-out process”, he outlined.

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