ANALYSIS: Increased scrutiny on coal-fired plant funding may not deter Asia Pacific demand

Highlights

Japan cancels coal plants funding in Indonesia, Bangladesh

China shelved 15 offshore coal-fired plants in April

Southeast Asian demand sustain in absence of cheaper substitute

A close check on international funding for new thermal coal power projects globally so that countries meet their carbon emission targets is unlikely to jeopardize demand from developing Asia Pacific countries, market sources told S&P Global Commodity Insights in the week to July 7.

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Japan said in June that it will not provide loans for the development of large thermal coal-based power plants in Indonesia and Bangladesh.

The impact, market sources said, can be seen across nations that have announced either cancellation of planned projects or have put them on hold.

Recently, Indonesia’s state-owned electricity company PLN said it has axed its 1 GW project to develop a coal-fired power plant. Bangladesh also put a 1.2 GW coal project on back burner.

The decision is seen as a follow up of a commitment made in 2021 by the UK, Canada, France, Germany, Italy, Japan, and the US along with the EU to end aid for coal-fired power plants that are not meeting requirements for reducing emissions.

However, this raised questions among market participants about reliance on coal as an energy source on a durable basis, with traders saying that unless a cheaper form of energy source is available, coal may continue to dominate in the energy mix for developing countries.

“What is being canceled is small compared to what is being built. We are seeing currently what is happening around the world after the Russia Ukraine. Unless there is an economically viable alternative to coal power, I don’t think any developing country will abandon it,” an Indonesia-based trader said.

India also plans to reduce power produced from its 81 coal-based plants by 2026, S&P Global reported in May. The plan includes replacing nearly 58 billion kWh power produced by coal fired power plants through renewable energy sources. However, the country plans to add coal-fired capacity of 7 GW in the fiscal year 2022-23 (April-March), according to a status report by the country’s federal power ministry in June.

In September 2021, China said it will shut overseas coal projects to cut greenhouse emissions. It shelved 15 overseas coal-fired power plants of cumulative capacity of 12.8 GW in April 2022, while other plants of 37 GW capacity were vulnerable to being shut down. These projects were concentrated in Vietnam, Bangladesh, and Turkey.

The development on coal-fired power plants also bears semblance to the investments into coal production capacity, with producers complaining of reduced financing available to increase capacity amid global scrutiny on coal production.

“I think it has more got to do with funding dry up and renewable is very competitive in term of tariff pricing. China has been funding most of those developing countries’ projects,” a Singapore-based trader said. “I guess the question is without cheap and reliable power output, how are these countries going to grow their manufacturing/economic growth.”

Sustaining demand

Nations in Southeast Asia, excluding India, are expected to sustain imports of over 150 million mt thermal coal in 2022-24, according to the Resources and Energy Quarterly report by the Australia’s Office of the Chief Economist.

“Plans for coal plant constructions across the region have been wound back, but a sizeable pipeline remains under construction,” the report noted. “There is little sign that the fallout from the Russian invasion of Ukraine will change supply chains across the region, with countries showing little interest in trade or sanction policies targeting Russia.”

India’s coal ministry projections on coal imports also show that India will import around 95 million mt non-coking coal in FY 2029-2030 as against its projection of 130 million mt in FY 2022-23.

While many funding countries have increased their probe over funding, market sources said some developing countries have themselves stopped borrowing funds for the project as part of their efforts to reach their carbon neutral goal.

Higher input costs

In 2022, Australia announced shutting down power plants in the state of West Australia as it believes that keeping coal-based power production was more expensive than greener alternatives.

The Newcastle 5,500 kcal/kg NAR coal with 23% ash was assessed at $183/mt FOB on July 6, sharply up from $103.5/mt at the start of 2022, according to S&P Global data.

Market participants in India have also complained about the cost of importing coal from Indonesia as many state-level electricity producers are not able to pass on the costs to consumers.

Indonesia is India’s largest supplier of thermal coal. The 5,000 kcal/kg GAR coal price was assessed at $154.3/mt CFR India West on July 6, compared with an average $60.40/mt in 2019, S&P Global data showed.

US Supreme Court ruling could fuel efforts to clip FERC gas project policies

Highlights

Christie says holding in EPA case supports his dissent

Policies already face headwinds from senators, industry

‘Major questions doctrine’ already raised in FERC docket

The Federal Energy Regulatory Commission’s efforts to bolster climate change considerations in its natural gas project decisions could be one of the next battlegrounds over administrative agency powers following a recent US Supreme Court decision.

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The high court on June 30 invoked a legal line of reasoning known as the “major questions doctrine” in finding that the Obama-era Clean Power Plan exceeded the EPA’s authority. It reasoned that courts should not defer to agencies on matters of “vast economic or political significance” unless Congress has explicitly granted the authority to act (West Virginia v. EPA, 20-1530).

Even before the latest high court ruling, some intervenors and a dissenting FERC commissioner had invoked the doctrine to argue FERC’s majority was overstepping its bounds in the proposed gas project policies.

Now Republican Commissioner Mark Christie and some other critics of the proposed policies argue the new ruling bolsters their position — even as environmental lawyers resist the notion that the doctrine should apply.

“The Supreme Court’s decision in West Virginia. v. EPA supports my dissent last February to the majority’s certificate policy,” FERC Commissioner Mark Christie said in an email July 5 to S&P Global Commodity Insights. In his view, FERC lacks authority to reject a pipeline based on an estimate of global greenhouse gas impacts or to require a pipeline to mitigate indirect GHG impacts from activities outside of its jurisdiction, such as from an end-user.

“Such actions implicate major questions of policy that fall under the Supreme Court’s major questions doctrine, as West Virginia v. EPA makes crystal clear,” he said. On the other hand, Christie offered his view that FERC does have authority to require “reasonable measures to mitigate direct GHG emissions from the pipeline itself.”

Teeing up the potential for legal challenges to the policies, a coalition of attorneys general from states including Louisiana, also argued back in April that because “the rules implicate major questions and push the limits of executive and federal power, they must be clearly authorized by Congress,” adding, “They are not.”

Eyes on FERC response

Dena Wiggins, president and CEO of the Natural Gas Supply Association, said her group is waiting to see how FERC will respond. She noted the commission has already rescinded the two policies on gas project reviews first issued in February and reissued them in draft form.

“I think that the signal from the Supreme Court is that there are limitations on the extent to which an agency can act, and that it needs to make sure it’s acting within the four corners of statutory authority,” she said. “I would anticipate that they’ll have to take this recent Supreme Court case into consideration before they finalize these policy statements.”

NGSA previously has argued that FERC is an economic regulator and that some of what was being proposed was outside the scope of FERC’s authority, she said.

Environmentalist and public interest lawyers are holding to their view that FERC was regulating within its wheelhouse.

Jennifer Danis, an attorney for the Niskanen Center, said the major questions doctrine has been raised and advocated for “erroneously” in FERC’s GHG policy docket for gas projects.

“FERC and the Federal Power Commission before it understood that in evaluating whether or not any particular project would serve the public interest, it had to be concerned about all the adverse impacts and all the potential public benefits,” she said in an interview July 5. “So this is nothing new.”

In her view, as much as the industry is trying to distinguish climate change from other adverse impacts, “I really see no legal or principled basis to do so.”

Environmental litigants

Maya van Rossum of the Delaware Riverkeeper Network said that if FERC retreats on climate change, organizations like hers would be left to challenge the policies on the flipside because the National Environmental Policy Act is clear about the kinds of things agencies must consider.

“Ideally, we would see FERC be proactive and positive and swiftly acting on climate, the way [FERC Chairman Richard] Glick has said they should be all along,” she said. “I think the reality is they get cold feet fast, and this is likely to impact what they do from the get-go in terms of how proactive they’re going to be on climate.”

Other FERC commissioners did not comment on the matter.

ClearView Energy Partners, in a note to clients, said the decision “would appear to put FERC on thin legal grounds if it were to condition or deny a [Natural Gas Act]-jurisdictional project on the basis of its indirect (upstream/downstream) emissions.”

William Scherman, a partner at Gibson Dunn & Crutcher, said legal challenges invoking the Supreme Court’s major questions doctrine could arise in several ways. Among them: if FERC gets three votes to issue either or both policy statements in a manner close to the prior versions, or if FERC uses a similar analysis to deny a project or to impose onerous mitigation requirements such that an applicant will take them to court.

“There is no clear and express language in the Natural Gas Act that enables FERC as envisioned in the policy statements to dramatically and fundamentally change the way gas pipelines have been certified in this country since 1938,” he said.

US POWER TRACKER: June MISO power prices rise on higher fuel prices, power burn

Highlights

Gas, coal prices both saw big hikes year on year

Gas-fired share of generation mix rose above 37%

Freeport LNG closure impacted gas prices in June

Wholesale power prices in June more than doubled year on year across much of the Midcontinent Independent System Operator, amid higher natural gas and coal prices and an increased reliance on natural-gas fired generation.

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June average day-ahead on-peak locational marginal prices increased more than 150% year on year at the Indiana, Michigan, Louisiana and Texas Hubs.

The biggest percentage increase among these locations was at the Indiana Hub, which averaged $115.55/MWh in June, a 184% increase from June 2021 and a 23% increase from May 2022.

The wind-rich Minnesota Hub saw a much smaller increase, averaging $66.04/MWh in June, a 33% increase from June 2021 and an 8% increase from May 2022.

Fuel price impacts

Fuel prices were a key driver of power price increases year on year. Henry Hub spot gas averaged $7.694/MMBtu in June, a 141% increase from $3.187/MMBtu in June 2021, but 4% less than $7.999/MMBtu in May 2022. Chicago city-gates spot gas averaged $7.420/MMBtu in June, up 138% from June 2021 but down 5% from $7.793/MMBtu in May 2022.

Gas prices in June and beyond were impacted by the June 8 fire and subsequent closure of the Freeport LNG terminal in Texas, which had the effect of boosting domesti gas supplies and softening gas prices. The US Pipeline and Hazardous Materials Safety Administration has said it wants Freeport LNG to take corrective actions befcore resuming normal operations. Freeport LNG currently plans to return to partial service in October and full service by the end of the year.

As the country’s largest coal-burning region, MISO power prices were also boosted by historically high coal prices in June. Rising nearly 350% on the year, the Illinois Basin 11,500 Btu/lb barge coal price averaged $159.34/st in June, compared with $35.50/st in June 2021, according to the Platts assessment by S&P Global Commodity Insights.

US June over-the-counter coal prices were supported by tight supplies, limited domestic intermodal availability and unprecedented global demand amid Russia’s war in Ukraine. Pricing was particularly bullish for US OTC coals that more easily move into export markets, such as Central Appalachia and Illinois Basin. For example, Illinois Basin coal is barged down the Mississippi River to vessels along the Gulf Coast. Meanwhile, landlocked coals posted more modest year-on-year price movements. Prices in the Powder River Basin, which also supplies MISO, averaged $16.30/st in June, up 30.9% from $12.45/st in June 2021.

Power burn rises

Gas-fired generation was up in June. Average daily power burn for MISO’s gas-fired generation fleet was about 4.3 Bcf/d in June, up from 3.2 Bcf/d in May, and up from 4 Bcf/d burned in June 2021, according to data from S&P Global Commodity Insights. Daily power burn is projected to be 4 Bcf/d in August, assuming a heat rate similar to August 2021. Daily power burn was 4.1 Bcf/d in August 2021.

Natural gas-fired power was at the top of the generation mix, providing 37.5% of MISO’s average daily power in June, up from 33.4% in May, and up from 32.8% in June 2021. Coal came in second at 33.7% of the fuel mix in June, up from 32.1% in May but down from 40% in June 2021. Nuclear was next in line, supplying 13.7% of MISO’s generation in June, compared to 13.8% in May and 9.5% in June 2021. Wind provided 11.8% of MISO’s generation in June, down from 16.9% in May, but up from 9.5% in June 2021.

Power forwards

August average power forwards were also up sharply at key locations in June, compared to the price of August 2021 prices in June 2021.

Indiana Hub August on-peak power forwards averaged $148.96/MWh in June, up 256% from $41.86/MWh that August 2021 forwards averaged in June 2021, but down 4% from $154.51/MWh that August 2022 forwards averaged in May 2022.

Louisiana Hub August on-peak power forwards were also up, averaging $141.61/MWh in June, up 249% from $40.56/MWh that August 2021 forwards averaged in June 2021, but down 4% from $147.16/MWh that August 2022 forwards averaged in May 2022.

Gas forwards were also higher year on year. Chicago city-gates August gas averaged $7.349/MMBtu in June, up 130% from $3.196/MMBtu that August 2021 gas averaged in June 2021, but down 8% from $8.028/MMBtu that August 2022 gas averaged in May 2022.

Henry Hub August gas averaged $7.599/MMBtu in June, a 131% increase from $3.287/MMBtu that August 2021 gas averaged in June 2021, but down 8% from $3.287/MMBtu that August 2022 gas averaged in May 2022.

California fuel cell electric vehicle market needs to ensure supply: CFCP

Highlights

Supply needs to synchronize with demand

State’s FCEV sales have increased exponentially

California’s fuel cell electric vehicle economy is now ready to shift its focus from refueling infrastructure to clean hydrogen production capacity to advance the industry toward commercialization, the California Fuel Cell Partnership said during a July 6 webinar.

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“When we started to focus on commercialization, it was really to synchronize the rollout of vehicles with fueling infrastructure,” said the CFCP’s Keith Malone. “Over the last couple of years, it has become absolutely clear that we need to now synchronize all of that with hydrogen production.”

Speaking during a webinar that the global hydrogen advocacy group Mission: Hydrogen hosted, Malone highlighted the strides the state’s FCEV industry has made in recent years and the milestones that remain ahead.

Light-duty FCEV sales have skyrocketed over the last seven years, bringing the total number of vehicles sold in the state to 11,956 by the end of 2021 from 188 in 2015—a more than 6,000% increase, although total FCEVs make up just 0.025% of California’s total vehicle population.

Naturally, that increase has been synchronous with the proliferation of retail hydrogen refueling stations. In 2015, just six retail stations were in operation around the state. Today, there are around 56, with dozens more in development.

While the majority of these stations have been financed by government programs, the private sector is pursuing station development as well. Earlier this year, for instance, Chevron and the Japanese industrial gas company Iwatani Corp. entered into an agreement to build 30 fueling stations across California in a “vertically integrated supply infrastructure ecosystem” that the companies hope can be a replicable model.

And California lawmakers have created goals to ensure that the growth of refueling stations continues. In 2013, Assembly Bill 8 aimed to build 200 stations for light-duty vehicles by 2026. The Chevron-Iwatani announcement put the state on track to surpass that milestone. And the CFCP has outlined targets for 1,000 hydrogen refueling stations and 1 million FCEVs on the road by 2030. The backdrop behind these goals is Governor Gavin Newsom’s 2021 executive order calling to end all sales of internal combustion passenger vehicles by 2035.

But with all this new demand coming to the market, the industry must ensure that supply will be ready.

Some early projects are already addressing California’s future supply question. In March, Air Products announced a hydrogen production facility in Arizona that will include a liquified green hydrogen export terminal for California’s mobility market. The facility is slated to produce 10 mt/day using alkaline electrolyzers manufactured by Thyssenkrupp.

Air Liquide is also bringing online a 30 mt/day green hydrogen plant this year in Nevada, which the company says is a direct response to California’s growing demand.

The Department of Energy’s hydrogen hub initiative—which will distribute $8 billion to at least four regional hydrogen hubs—will ultimately help with supply needs. But Malone said that more policy will likely need to be in place for supply and demand to grow in tandem.

“If you look at the DOE’s hydrogen hub effort, it’s about how do we synchronize production with offtakers, the people who will use this hydrogen,” he said. “I don’t think it’s going to be pretty. I think we’re doing the best we can, but the big question that’s coming to the fore is, how do you do this, and are the right policies in place?”

According to S&P Global Commodity Insights, the assessed pump price of hydrogen in California was $15.97/kg July 1. By comparison, one gallon of diesel, which has roughly the same energy content as a kilogram of hydrogen, cost $6.87 as of mid-June, according to the US Energy Information Administration.

EU parliament votes in favor of gas, nuclear inclusion in sustainable finance taxonomy

Highlights

Motion to oppose voted down by MEPs

Transitional role for gas acknowledged

ClientEarth considers legal challenge

The European Parliament has rejected a motion to oppose inclusion of nuclear and natural gas as environmentally sustainable economic activities under the European Commission’s Taxonomy Delegated Act.

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The EC has proposed a transitional role for gas and nuclear in the green transition, with inclusion in the taxonomy regulation promoting access to private sustainable finance.

“If neither Parliament nor Council object to the proposal by July 11, 2022, the Taxonomy Delegated Act will enter into force and apply as of Jan. 1, 2023,” the EP said.

Voting in favor of the resolution were 278 MEPs, while 328 voted against and 33 abstained. An absolute majority of 353 MEPs was needed for Parliament to veto the Commission’s proposal.

The proposal states that inclusion requires new gas-fired power or heat assets must have life-cycle emissions of below 100g CO2/kWh, or meet a number of stringent conditions and obtain a construction permit by 2030.

Gas plants must have plans to switch to renewable or low-carbon gases by the end of 2035, in line with an overall CO2 emissions threshold of 270 g/kWh or annual emissions not exceeding an average of 550 kg/kW over 20 years.

For nuclear, inclusion covers investment in new Generation III+ projects approved for construction until 2045, R&D investment in advanced technologies promoting safety and minimal waste, and investment in existing nuclear installations to extend operational lifetimes approved until 2040.

Environmental group ClientEarth said it was “looking at options to challenge the inclusion of fossil gas in the Taxonomy in court – greenwashing cannot win.”

“Branding fossil gas as transitional and green in the Taxonomy is unlawful as it clashes with the EU’s key climate legislation, including the European Climate Law and the Taxonomy regulation itself,” said ClientEarth lawyer Marta Toporek.

Sector association nucleareurope welcomed the vote. “The science clearly states that nuclear is sustainable and essential in the fight against climate change,” said its director general Yves Desbazeille.

Hong Kong launches international carbon council, to support cross-border trading

Highlights

Council set up by HKEX, partnering with corporates, financial institutions

Principal focus is to develop an international carbon market

Laying the foundation for Hong Kong’s growth as premier carbon hub

Hong Kong Exchanges and Clearing Limited, or HKEX, has launched the Hong Kong International Carbon Market Council, the exchange said in a statement late July 5, with developing an international carbon market as its principal focus.

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HKEX said the Council consists of leading corporates and financial institutions and targets to facilitate the development of a sustainable finance ecosystem in Hong Kong, mainland China and beyond.

“The launch of the Council will lay the foundation for Hong Kong’s growth as a premier carbon hub in Asia and beyond as well as contribute to global efforts towards achieving a low-carbon economy,” HKEX said in the statement.

HKEX disclosed in the statement that the inaugural members of the Council includes: Australia and New Zealand Banking Group Limited Hong Kong Branch, Bank of China (Hong Kong) Limited, BNP Paribas Hong Kong Branch, Cathay Pacific Airways Limited, China Energy Conservation and Environmental Protection Group, China Forestry Group Corporation, Industrial and Commercial Bank of China (Asia) Limited, Standard Chartered Bank (Hong Kong) Limited, State Power Investment Corporation Limited, Tencent Holdings Limited and The Hongkong and Shanghai Banking Corporation Limited.

The newly established Council will gather insights from members on the development of an efficient and effective Hong Kong–based international carbon market, HKEX said.

HKEX has made several moves recently to explore carbon trading opportunities in the Asia Pacific region, leveraging Hong Kong’s position as a leading global financial center.

Last November, HKEX joined the Glasgow Financial Alliance for Net Zero, or GFANZ, and the Net Zero Financial Service Providers Alliance, or NZFSPA, as parts of its ongoing commitment to the long-term sustainable development of global financial markets, HKEX’s website showed.

In March 2022, HKEX signed a memorandum of understanding with Guangzhou-based China Emissions Exchange, or CEEX, to jointly explore the development of a voluntary carbon emission reduction program in the Guangdong-Hong Kong-Macao Greater Bay Area, HKEX’s website showed.

In March, HKEX also published a feasibility study with the Securities and Futures Commission of Hong Kong, highlighting that Hong Kong has the potential to act as a bridge to the world for mainland China’s domestically certified voluntary carbon credits, called China Certified Emission Reductions, or CCERs.

New Fortress to develop set of gas projects with Mexico's Pemex and CFE

Highlights

New Fortress to partner with Pemex to develop offshore gas field, Lakach

Company to expand its gas supply to CFE power plants in Baja California Sur

Company to develop an LNG hub in Altamira, Tamaulipas

US-based New Fortress Energy on July 5 announced a set of natural gas projects with Mexican state companies Pemex and CFE that could increase Mexico’s domestic production, reduce the country’s dependency on imports from the US and help it improve its finances.

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New Fortress will partner with Pemex to develop Lakach deepwater gas field off the coast of Veracruz in southeastern Mexico and will expand its gas supply to CFE power plants in Baja California Sur, the company said in statements on July 5.

The statements follow public announcements of the projects made by President Andres Manuel Lopez Obrador on July 1 during the inauguration of the country’s seventh refinery, Dos Bocas, in the state of Tabasco.

The Lakach project was suspended for over six years during the previous administration after an investment of roughly $1.4 billion, Pemex CEO Octavio Romero Oropeza said on July 1 during the inauguration of the refinery.

New Fortress will use its own technology, which is “a perfect match” for the characteristics of the site, to complete the seven exploratory wells installed by Pemex, Wes Edens, CEO and chairman of the board said July 5 during a conference call with investors.

As the company will put in place the gas treatment plants and split the production, Pemex can use its share to meet the domestic demand, while New Fortress can export its share, Edens said.

“We believe this model will be significant around the world,” he said, adding that he expects the project to be operational by the end of 2023.

New Fortress also announced that through its LNG regasification terminal in the port of Pichilingue in the state of Baja California Sur, which started operations in July 2021, it will expand and extend the company’s supply of gas to the two power plants owned by the state utility CFE in the region: CTG La Paz and CTG Baja California Sur. Additionally, New Fortress will sell its own 135 MW power plant in the city of La Paz to CFE.

The addition of the power plant to CFE’s generation fleet is expected to enhance system reliability, reduce cost and complement CFEs steps to lower emissions, the company said in the release.

New Fortress has also agreed to build an LNG export hub off the coast of Altamira, Edens said during the call.

Under the agreement, CFE will provide the gas, which it imports from Texas through a marine pipeline, while New Fortress will deploy floating LNG units, the company said. CFE would have a share in the production and will do marketing of a portion of the LNG volumes, it said.

“The impact of these three transactions is life-changing,” Edens said during the call.

In March, New Fortress said it had filed permit applications for two fast LNG units in the US state of Louisiana to provide more US LNG to Europe and help it reduce its dependence on Russian gas.

Edens said there are still questions about the deals, but signing the agreements signifies that the companies are advancing.

“Given the state of the world, we want to bring them to life as soon as possible,” he said.

Whiting, Oasis complete merger, renamed Chord Energy

Highlights

Has top-tier assets across 972,000 net acres

Focus: Williston Basin, primarily North Dakota

Q2 output eyed of 157,600 boe/d

Whiting Petroleum and Oasis Petroleum completed their $6 billion merger, creating a scaled unconventional US Rocky Mountains Williston Basin oil producer with top-tier assets across 972,000 net acres in the Williston Basin of North Dakota and Montana, the companies have said.

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The company had combined first-quarter production of 171,100 b/d of oil equivalent production, Chord said in a July 1 statement, making it one of the largest Williston producers.

Pro forma oil production for second quarter is expected at 88,600-90,400 boe/d, while pro forma total output is estimated at 156,400-158,800 boe/d.

Chord plans to concentrate on the Williston Basin, after each separately sold out of other basins in 2021. Whiting exited the DJ Basin, while Oasis divested its Permian basin properties after entering that basin in December 2017.

“Chord will execute a focused strategy to enhance value delivery to our shareholders and maintain a strong commitment to safety, gas capture and emissions reduction,” company CEO Danny Brown said. “Chord [has] “a premier Williston Basin position, a peer-leading balance sheet, significant scale and enhanced free cash flow generation, [and] is positioned to succeed.”

While the company’s acreage is spread over both North Dakota and Montana, it is mostly in North Dakota.

Trades on Nasdaq

Chord, headquartered in Houston, said its common shares began trading on the Nasdaq Global Select Market under the ticker symbol CHRD on July 5.

On July 5 in midmorning trading, the shares were trading at $101.25. Previous close on July 1 was $109.30.

The merger partner companies selected as the new name for their combined entity Chord to signify — as occurs in music — the joining of separate units with complementary strengths that create a harmonious blend stronger than would occur if they remained separate.

The transaction should be accretive to key per-share metrics that include E&P cash flow, E&P free cash flow, return of capital and net asset value.

Chord expects to realize cost savings of at least $65 million/year by second-half 2023.

The company expects to return 60% of its free cash flow to shareholders in H2 2022 through its base dividend, variable dividends and share buybacks and has a $150 million share repurchase program in place.

FEATURE: ADNOC's new Fujairah LNG project seeks to capitalize on global thirst for energy

Highlights

Japan’s INPEX will consider participating: CEO

Project includes two trains of 4.8 mil mt/year each

Gas prices have soared to record highs

The UAE Port of Fujairah’s growing profile as an energy hub is set for another boost, with Abu Dhabi National Oil Co.’s plans to build a 9.6 million mt/year LNG plant in the eastern emirate.

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The project, currently in the design phase, is expected to be complete between 2026 and 2028, sources told S&P Global Commodity Insights – not in time to ease the current gas crunch, as the world scours for new supplies to replace Russian volumes.

But analysts say it could be well-poised to capture growing demand for the fuel, if high prices do not set long-term consumption back and environmental regulations in Europe do not close off that market.

Fujairah, which is already the world’s third largest oil bunkering hub, is hoping to benefit from the project, with new stakeholders expected to be attracted.

The facility, which will include two 4.8 million mt/year trains, will raise ADNOC’s LNG production capacity to 15.6 million mt/year, giving neighboring Qatar – currently the world’s largest LNG exporter – a formidable regional rival.

ADNOC, which declined to comment on the project, owns a 70% stake in the ADNOC LNG joint venture, which has a current capacity to produce 6 million mt/year at Das Island in the Persian Gulf.

Other shareholders in ADNOC LNG are Mitsui & Co. with a 15% stake, BP with 10% and Total with 5%

ADNOC is in talks with those partners to take part in the Fujairah facility, sources said, and Japan’s INPEX intends to consider participating, its CEO told S&P Global.

ADNOC’s new project comes at a time when the world’s demand for LNG is high as Russia restricts piped gas supplies to Europe and countries around the globe seek gas as a transition fuel to replace dirtier crude.

Gas prices in Europe and Asia have soared to record highs in 2022 as Europe wrestles with Asia over LNG cargoes in a tight market.

The JKM spot LNG price for delivery into northeast Asia hit a record $84.76/MMBtu in March and was last assessed at $41.65/MMBtu July 4, according to Platts assessments from S&P Global.

Asia destinations

ADNOC has traditionally sent its LNG to Asia and up until 2018 supplied around 90% of its volumes to Japan under long-term agreements but has sought since to diversify its customer base by signing multi-year contracts.

Adding Europe as a potential new destination for ADNOC’s LNG will depend on several factors, including the ability to lock in long-term contracts.

The destination for LNG “will depend on which parties want to sign contracts for the LNG (most likely Asia), the state of the global LNG market and prices when the plant comes on stream,” said Jonathan Stern, a research fellow at the Oxford Institute for Energy Studies.

However, he added, “it will be difficult for European companies to make long-term commitments because of their emission targets.”

Since 2019, India has been the UAE’s top LNG customer, based on Kpler shipping data.

Platts Analytics, in a June 13 report, noted that none of ADNOC LNG’s term customers sent any cargoes to Europe, despite lucrative LNG spot prices. The last time ADNOC LNG sent any volumes to Europe was in June 2009, it said.

However, as demand destruction from high LNG prices seeps into Asia, Europe may become a more attractive destination.

“Europe’s need to replace 160+ Bcm of Russian gas will create huge need for additional LNG in the medium term,” said Robin Mills, CEO of Qamar Energy. “Sellers can name their terms at the moment and buyers are realizing the danger of exposure to volatile and potentially very high spot prices. The question is what ‘long term’ means for European buyers given their decarbonization targets, 10 years or longer?”

Platts Analytics has revised its Indian LNG demand forecast down an average of nearly 10 billion cu m/d from 2022 through 2025 on the back of higher prices expected during this period.

“South Asia, once thought to be one of the key drivers of global demand in the medium term, could disappoint to the downside amid lingering elevated spot prices and limited cover by long-term contracts,” Platts Analytics said in an April 29 report.

New gas

The expansion of ADNOC’s LNG capacity comes as new gas developments are set to increase alongside its expansion of oil production capacity to 5 million b/d by 2030 from about 4 million b/d currently, which will yield higher associated gas.

ADNOC had announced in December a rise in national gas reserves of 16 Tcf, bringing the UAE’s gas reserves base to 289 Tcf.

The location of Fujairah for the new LNG production will also be of added value to ADNOC, given the aging facilities at Das Island, located far offshore. The fact that Fujairah lies outside the problematic Strait of Hormuz in the Persian Gulf reduces its geopolitical risk profile.

“For the UAE this [project] is very important and may replace the Das Island plant in future, as that plant is now very old dating from the late 1970s,” said Stern.

Fujairah will also gain from the growing number of LNG tankers that will call on the port, which is considering adding LNG bunkering services, its managing director, Captain Mousa Murad, said.

“Fujairah can also benefit that available gas will attract industrial companies that will use gas instead of, for example, diesel to set up projects,” said Murad.

REFINERY NEWS ROUNDUP: Incidents, strikes at plants in Europe

There have been several incidents reported at European plants recently, which — along with industrial action in France — have affected operations.

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** A fire at Norway’s Mongstad on July 3 has been extinguished though some parts of the plant involved in production of some refined products are affected. The main plant however remains in operation. “A controlled combustion has been conducted from the leakage point,” the company said, adding that “further examinations and any repairs will be conducted before the affected part of the processing plant can be restarted.” The refinery completed scheduled maintenance, which started in late April, in the last week of June.

** Italy’s Sarroch refinery was operating normally after a fire late June 25 on equipment taking solid sulfur to silos at the complex, the company said June 27. The fire, which was quickly extinguished, was likely caused by moving mechanical parts on the line overheating, the company said.

** A unit at TotalEnergies’ Antwerp refinery has been halted following a crude oil leak, local media cited the company as saying. The leak followed a technical malfunction of the crude oil cooling system and was stopped after the unit was halted.

** ExxonMobil said its Fos-sur-Mer refinery in southern France had been restarting since July 2 after a strike — which began June 28 over pay — ended following a “constructive social dialogue”. The company, which had said last week it had started “preparations to gradually shut down” the plant, also said the plant did not completely halt operations, adding it will do everything to resume full operations and deliveries as soon as possible.

** There has been a growing level of industrial action in France over pay. On June 24, staff at TotalEnergies’ refineries in France carried out a 24-hour strike. Meanwhile, firm demand has boosted refining margins.

** Finnish refiner Neste said it expects its average refining margin to more than double in the second quarter of 2022 from the previous quarter as soaring global product cracks continue to lift refining sector earnings. The company had previously estimated its Q2 refining margin at a roughly similar level to the Q1 margin of $10.30/b.

** French road fuel deliveries in May rose 13% year on year to 4.246 billion liters, with a 9.3% year-on-year increase in diesel consumption and a 25% jump in gasoline consumption, industry group UFIP said. Compared with pre-COVID May 2019, ultra-low sulfur diesel deliveries were down 4.5% in May 2022, whereas gasoline consumption jumped 18%, once more confirming the rebalancing of car ownership toward a greater proportion of gasoline passenger cars and smaller sales of diesel passenger cars in France. Jet fuel demand climbed 122% year on year to 601 million liters in May. However, jet fuel deliveries in May 2022 were down 19% compared with May 2019. Those numbers reflect the fact that airline seat capacity has not yet fully recovered to pre-pandemic levels in France and Europe in general.

** Germany’s Schwedt refinery will continue processing crude oil after Jan. 1, 2023, local media cited a government official. “Crude oil will continue to be processed here from January 1, 2023,” Michael Kellner, a parliamentary state secretary in the economics ministry said. However the government is looking at providing alternative crude supplies as the plant currently processes Russian crude oil delivered by the Druzhba pipeline. The plant can receive seaborne crude from the Baltic ports of Rostock in Germany and Gdansk in Poland. Both ports are connected to the refinery via pipelines, though the pipeline from Rostock will need to be upgraded in order to increase its capacity, Kellner was quoted as saying. Currently it can supply 60% of Schwedt’s capacity and will be expanded to provide around 70%, though the expansion can not happen by the end of the year. However Kellner did not specify at what capacity the refinery would operate in the next few years.

** PKN Orlen, Poland’s largest refiner, expects to tie up its agreed acquisition of the country’s number two refiner, Grupa Lotos, by early August after the EU waved through an asset deal needed to secure Brussels’ backing for the takeover, PKN’s CEO Daniel Obajtek said. PKN Orlen first announced plans to take over its domestic rival Lotos in early 2018.

NEW AND ONGOING MAINTENANCE

Refinery

Capacity

Country

Owner

Unit

Duration

Sannazzaro

190,000

Italy

Eni

EST

2020

ISAB

321,000

Italy

Lukoil

Part

Mar

Izmir

220,000

Turkey

Tupras

part

2022

Izmit

227,000

Turkey

Tupras

part

2022

Batman

28,000

Turkey

Tupras

part

2022

Lietuva

204,000

Lithuania

PKN

full

Back

Thessaloniki

95,000

Greece

Hellenic

full

H2’22

Ingolstadt

110,000

Germany

Gunvor

part

2022/2023

Ashdod

110,000

Israel

Paz Group

full

May

Burghausen

76,000

Germany

OMV

full

Q3,2022

Tarragona

186,000

Spain

Repsol

part

2022

Duna

165,000

Hungary

MOL

part

H1’22

Bratislava

122,000

Slovakia

Slovnaft

part

May

Mongstad

190,000

Norway

Equinor

full

Back

Livorno

84,000

Italy

Eni

part

ongoing

Holborn

105,000

Germany

Oilinvest

full

2023

Litvinov

108,000

Czech

Unipetrol

full

2024

Lavera

210,000

France

PetroIneos

full

Back

Heide

90,000

Germany

Klesch

part

May

Lingen

96,000

Germany

BP

full

Apr’23

Lindsey

108,000

UK

Prax

full

June

Near-term maintenance

New and revised entries

** In the second half of 2022, Repsol is due to carry out a small turnaround at its Tarragona refinery, which will involve the isomax and hydrocracker units. The work was due to start Sept. 23 and continue to mid-November.

** An unspecified unit has been halted at France’s Donges refinery June 22 which could cause flaring. Another unit, which was halted June 15, restarted on the following day. Separately, a hydrodesulfurization unit HD2 remained offline following a fire May 28. TotalEnergies halted operations at Donges on Nov. 30, 2020, due to weak margins, and restarted in early May.

** Norway’s Mongstad planned maintenance had now been completed, the company said June 24. “The Mongstad Refinery maintenance is now completed and operation is resumed,” it said. The refinery had previously postponed works that were planned for 2020. However, there was a fire at the refinery on July 3 which affected some parts of the plant involved in production of some refined products. The main plant however remains in operation. “A controlled combustion has been conducted from the leakage point,” the company said, adding that “further examinations and any repairs will be conducted before the affected part of the processing plant can be restarted.”

** There is currently “a period of maintenance” underway at UK’s Lindsey refinery, the company said June 20. Prax Group completed an acquisition of the Lindsey refinery and its associated logistic assets in the UK from TotalEnergies in March 2021.

** Germany’s Heide has completed partial maintenance on some units on schedule, the refinery said June 14. It planned works between May 4 and June 11. Production facilities not involved in the maintenance continued operations so that supply of products during the turnaround was guaranteed.

** Austria’s Schwechat refinery is expected to be fully operational and fully utilized in the second half of Q3 2022, OMV said. “Repair work began immediately after the incident and includes dismantling, ordering materials, and prefabrication,” OMV said. “As the damage occurred in the lower section of the distillation column, the damage site is difficult to access,” OMV also said. The refinery had some damage to its main CDU before restarting after maintenance. “During the legally required water pressure test, damage occurred to the outer shell of one of the columns of the crude oil distillation unit,” the company said. The damage occurred on June 3. Schwechat has been undergoing a turnaround since April 19. OMV also said that for the duration of the repairs it has established a new supply system to supply the markets served by Schwechat and would also use the refinery’s smaller CDU. The measures taken allow the refinery to operate at around 20% of capacity

** Planned maintenance at France’s Lavera has been completed and the refinery is back with products in the market, according to market sources July 4. Separately, local media reported that the refinery has been restarting units since late June following the maintenance which could result in flaring. The refinery started maintenance May 8, with the process set to last around two months, S&P Global Commodity Insights has reported.

** Most of the maintenance at Lithuania’s Orlen Lietuva refinery has been completed, a PKN spokesperson said June 15. The turnaround was scheduled to finish at the end of June. Planned maintenance started in early May. The maintenance was due to last two months and include the modernization of the catalytic cracker unit. General refinery maintenance takes place every four years, with the last round carried out in 2018.

** Israel’s Ashdod is currently carrying out works that started in early June, the company said June 14. The maintenance, which was originally planned to start in May, has been slightly delayed.

** OMV has started the shutdown of units at the Burghausen refinery for planned general maintenance. The units were due to be halted between June 17-27. It has previously said the maintenance would last between June 22 and Aug. 7. The turnaround will include also the Borealis polyolefin production site. The last turnaround took place in 2014, followed by a partial shutdown of the refinery in May 2018. In addition, expansion work will be carried out to increase ethylene and propylene production. The expansion is expected to increase ethylene and propylene production by around 50,000 mt/year.

Existing entries

** Germany’s Lingen refinery will carry out a major maintenance in April 2023. Preparations for the turnaround, which takes place usually once every five years, are underway. During the maintenance, a vacuum column will be replaced.

** Slovakia’s Bratislava refinery started maintenance May 19 to last until July 20. The turnaround will involve 21 units and will take place in two time blocks. “During two months of intensive maintenance work, Slovnaft will shut down, clean, modernize and restart 21 production units in both the refining and petrochemical sections,” it said in the statement. The start-up of the last group of production units is scheduled for the second half of July. Among the units involved are distillation, hydrocracker and key petrochemical units such as the LDPE4 plastics production unit, “which is one of the most advanced in Europe,” the company said. During the maintenance work the refinery will replace the distillation furnace and pumps at the circulation centers and will also replace the distillation column with a new extension, “enabling a more efficient distillation process.”

** Eni’s Livorno refinery will restart its lubricants activities in the third quarter of 2022 after completing maintenance, restoration and upgrade works at the unit following the November fire that damaged it, a company spokesperson said. Livorno restarted its gasoline and diesel refining units in the first week of April after wide-scale maintenance and upgrade works that had started in January were completed.

** Turkey’s Tupras plans maintenance work at Batman’s crude oil and vacuum unit lasting four weeks during Q4; at Izmir — revamping the crude, CCR & isomerization, and desulfurizer units, lasting nine weeks during Q4 and of the HYC unit lasting four weeks, also during Q4; at Izmit — periodic maintenance of the crude oil and vacuum and HYC units lasting six weeks at the end of Q3.

** Italy’s ISAB refinery in Sicily is running a series of routine maintenance and upgrade works on pumps, compressors, pipelines, jetties, desulfurization units and conversion units both at its north and south refinery plants. ISAB is made up of two refineries connected by a pipeline.

** Eni’s Sannazzaro de Burgondi refinery will delay its maintenance cycle, originally planned for May, until after the summer. Eni’s EST plant had originally been scheduled to restart in past years but has been kept offline so far amid the nationwide slump in demand due to the COVID-19 pandemic.

** Greece’s Hellenic Petroleum plans full turnaround at Thessaloniki in the second half of the year. The maintenance at Thessaloniki will last between six and eight weeks.

** MOL will schedule the bulk of its 2022 maintenance activities in the first half of the year, including works at MOL Petrochemicals, as well as at the distillation and conversion units of its Danube and Slovnaft refineries.

** Shell plans to end crude processing at the Wesseling site within the Rhineland refining complex in 2025 as the facilities are repurposed for non-fossil fuel feedstocks and renewable hydrogen production. Shell outlined plans for the facility to take a variety of new biogenic and waste feedstocks, underlining that no final investment decision had yet been taken, and crude processing would still take place at the adjoining Godorf site. The Wesseling portion of the Rhineland refinery accounts for half the overall refining capacity, or 8 million mt/year.

** The Gunvor Group said that its Ingolstadt refinery in Germany will undertake projects focused on heating systems and exchangers “to continue improving its energy efficiency and reduce its emissions.” A planned turnaround in 2023 will allow additional reductions, by carrying out projects on the FCC.

** Czech Unipetrol said that following the turnaround at its Litvinov plant in Q2 2020, the refinery has prepared production for a new four-year cycle. Thus, the next turnaround is due in 2024.

** The Holborn refinery near Hamburg, northern Germany, plans its next turnaround in 2023. Its previous maintenance was in the autumn of 2018. The refinery carries out major works every five years.

Shell wins stake in Qatar's LNG expansion for 'much needed' supplies

Highlights

ExxonMobil, TotalEnergies, ConocoPhillips, Eni also in expansion

North Field East expansion will add 32 mil mt/year

Carbon capture, sequestration also part of plan

Shell will participate in Qatar’s under-construction 32 million mt/year LNG expansion at the giant North Field in the Persian Gulf, becoming the fifth partner in the first phase of a 48 million mt/year project as buyers look to replace fuels from Russia.

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Shell will hold a 25% share in a joint venture company which will own 25% of the North Field East expansion project, QatarEnergy and Shell said in separate statements July 5. That equates to a 6.25% equity stake in the expansion by QatarEnergy, equal to shares won by TotalEnergies and ExxonMobil.

The Shell stake concludes the international energy partner selection for the expansion, QatarEnergy said. Italy’s Eni and ConocoPhillips also previously won stakes in the $28.75 billion expansion.

Shell said its investment will support delivery of “much-needed supplies” of natural gas to markets around the world. The project will also be integrated with carbon capture and sequestration to reduce emissions.

“Through its pioneering integration with carbon capture and storage, this landmark project will help provide LNG the world urgently needs with a lower carbon footprint,” Shell CEO Ben van Beurden said in a statement.

“Lower carbon natural gas is a key pillar of our powering progress strategy and will also help us achieve our target of becoming a net-zero emissions business by 2050.”

Equity stakes now awarded represent a collective 25% in North Field East, which will increase Qatar’s LNG production capacity to 110 million mt/year by 2026 from 77.4 million mt/year currently.

A smaller planned North Field South project is intended to boost capacity to 126 million mt/year by 2027. QatarEnergy retains the controlling share.

UAE's TAQA to sell Dutch upstream assets amid strategic review

Highlights

TAQA owns Bergen II production area in Netherlands

TAQA also owns P15 and P18 oil and gas production infrastructure

TAQA operates two Dutch gas storage facilities

UAE’s energy and utilities company TAQA plans to sell its Dutch upstream assets as part of a strategic review of its oil and gas portfolio amid a focus on developing its renewables business.

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“As part of the review, the company had been exploring the potential sale of certain of its oil and gas assets,” TAQA said in a July 5 statement. “It has been concluded that TAQA’s oil and gas portfolio will be retained, except for the upstream assets in the Netherlands where discussions are ongoing.”

TAQA didn’t disclose which upstream assets it plans to sell or a timeline for the sale.

“The timing and details of the sale of our upstream assets in the Netherlands will be communicated as and when necessary, in compliance with our disclosure obligations,” a company spokesperson told S&P Global Commodity Insights.

TAQA has Bergen II production area in the Dutch province of North-Holland, which consists of production locations in Bergen, Groet and Schermer, according to its website.

The Bergen Drying Facility is the central gas processing and compressing facility.

It also has P15 and P18 infrastructure, located 35 km northwest off the coast of Hoek van Holland. The infrastructure consists of oil and gas production facilities, including central P15-ACD complex and other production platforms where condensate, oil and gas are transported to shore by pipelines.

The P15-ACD complex is a hub for treating and processing of third party oil and gas, where around 15 oil and gas fields have tie-ins to P15, according to the website.

Dutch gas storage

“Our decision to seek a buyer for the upstream assets in the Netherlands is based on the nature of the assets and the relatively small contribution the assets make to TAQA group earnings,” CEO Jasim Thabet said in the statement.

TAQA also operates Gas Storage Bergermeer, one of two gas storage facilities operated by the company in the Netherlands. The facility provides 46 TWh of seasonal storage capacity.

TAQA also has a 36% stake in Peak Gas Installation, or PGI, an underground natural gas reservoir used to store and deliver natural gas to meet peak demand from the Dutch national grid. PGI uses the Alkmaar gas reservoir located near the city of Alkmaar and is situated approximately 2,200 meters underground.

Other shareholders in PGI are Dutch state-owned energy company, EBN (40%), Dana Petroleum Netherlands BV (12%) and RockRose Energy (12%).

“Our midstream assets, including our two gas storage facilities, will be retained,” the spokesperson said.

Under its 2030 strategy, TAQA plans to expand its UAE power generation capacity from 18GW to 30GW in addition to adding 15GW internationally. By 2030 the company’s power generation portfolio will be at least 30% renewables, up from the current 5%.

TAQA also has signed contracts to take a controlling stake in the renewable business of Masdar, which is owned by sovereign wealth fund Mubadala Investment Co. TAQA will own Masdar’s renewables business alongside Mubadala and state-owned Abu Dhabi National Oil Co. Masdar is targeting to have over 50GW in power capacity by 2030.

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