Majors Ramp Up Spend. Markets Love Carbon Cutting. Japan Backs Oil & Gas.

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The Majors’ accelerating tilt to new energy
Simon Flowers, Wood Mackenzie, December 2, 2021

When will spend on low carbon catch up with oil and gas?

Big Oil is determined to show it’s part of the solution for climate change. That much is clear from the rapid acceleration of investment in new energy. I asked Tom Ellacott and Greig Aitken of our Corporate Research team how they see the Majors’ strategic positioning evolving.

How much has spend ramped up?

It’s doubled since 2019/20. Two years ago, the Euro Majors were planning to spend an average of US$2 billion a year on new energy, 10% of total investment. An intense period of business development has strengthened the opportunity set. Budgets for all of the Majors are now aimed at an average of US$4 billion a year, almost 25% of total investment – though timescales vary across the group. Repsol’s target of 35% out to 2025 is the most aggressive.

Another big change from two years ago is that the US Majors have entered the fray, as we predicted. We expect Chevron and ExxonMobil to follow the upward trend. Their plan to allocate 10% of spend to low-carbon opportunities is only an opening salvo.

What are the Majors investing in?

Mostly renewables, the immediate growth opportunity as the world electrifies. Solar, onshore wind and offshore wind are among the few low-carbon technologies that are commercial and scalable, and diversifying Majors can build the exposure they seek. TotalEnergies is aiming for a 10-fold increase in capacity to around 50 GW net by 2030, as is BP; both could be in the top five renewables players by then. Utilities’ renewables targets (Enel 120 GW and Iberdrola 95 GW) perhaps indicate where Big Oil will eventually go as it morphs into Big Energy.

Geographical diversification is an increasingly important theme for the Majors in renewables. We’re likely to see renewables portfolios expand to an international footprint much like E&P. Equinor’s 15 GW of projects are held across 14 countries (including holdings via affiliates), ditto BP (15 countries) and TotalEnergies (17 countries). Intensifying competition is forcing companies to look further afield to capture new opportunities. TotalEnergies has set up a network of 50 ‘renewables explorers’ across 50 legacy countries.

The other big focus for spend is developing the customer base. Shell and BP plan to spend more than 10% of their total five-year budget on marketing and retail. Customers will be a key part of their integrated, full value chain approach to low carbon: from producing electrons through to providing energy solutions for the industrial, commercial, and retail segments. Energy trading will play a critical part in boosting margins through the value chain. The customer proposition will embrace multiple services, including EV charging, energy efficiency and distributed energy resource management.

Where do CCS and hydrogen fit?

All of the Majors want a piece of these emerging technologies that will undoubtedly play a big role in the world achieving net zero. Investment is still modest, but budgets for both are going to get a lot bigger as they move towards commercialisation and are scaled up.

Project pipelines are already growing exponentially. The Majors’ CCS pipeline has doubled in six months, with ExxonMobil having more than twice the gross project capacity of the others.

Hydrogen project pipelines, too, are in their infancy but growing rapidly. The Majors’ existing production of hydrogen at refineries gives them an early advantage in the market. All see blue (linked to CCS) and green hydrogen as a huge growth opportunity. Equinor (5 mmtpa, gross capacity), Shell (3 mmtpa) and BP (2 mmtpa) are the early leaders.

The Majors’ CCS and hydrogen pipelines are growing as they see huge growth opportunity.

Do the returns in new energy justify the pivot?

It’s not clear cut. Renewables projects on their own deliver mid-single-digit returns and vie for capital with upstream projects, many of which deliver superior IRRs at current prices. Risk adjusted, though, the gap with upstream is narrower, and integration also boosts the overall returns from renewables.

The bigger picture is that the increase in capital allocation to renewables is strategic. The Majors are on a mission to reshape and futureproof the business. The commitment to new energy and low carbon is a long-term bet on an irreversible shift in the energy mix. And they need to do it now to stay investible.

How big can investment in new energy get?

Oil and gas will continue to dominate earnings and cash flow for years to come. We estimate that even for Equinor, which has the most aggressive growth strategy, new energy will contribute only 15% of operating cash flow in 2030 based on today’s commercial assets. Of course, as companies add to their portfolios, the contribution will get bigger.

The tilt of investment in favour of low-carbon energy technologies is only going one way, and now they are on board, the US Majors are going to catch up. We think investment for the group will double again in the next five years.

As the Majors push towards their net zero goals, we reckon the peer group leaders’ spend on new energy versus oil and gas will get close to 50:50 by 2030.


OPEC to proceed with plans to increase January oil output
Salma El Wardany, Grant Smith, Dina khrennikova, Javier Blas, World Oil, 12/2/2021

OPEC and its allies agreed to proceed with their next oil-production hike, while signaling they could revisit the decision at any moment as the risk to demand from the omicron variant of Covid-19 becomes clearer.

The group will add 400,000 barrels a day of crude to global markets in January, as previously scheduled. However, it also left the door open to adjusting the plan at short notice if the market changes, an unusual step that underscores the uncertain outlook due to a resurgent pandemic and a U.S.-led release of emergency stockpiles.

“The OPEC+ communique announcing that the meeting remains ongoing is very important — it signals they’re poised to pause or cut if conditions warrant,” said Bob McNally, president of consultant Rapidan Energy Group and a former White House official. “For now, the fog of uncertainty is too dense and they’ll wait for it to dissipate.”

With crude already in a bear market due in large part to the emergence of the new coronavirus strain, traders had been widely expecting the Organization of Petroleum Exporting Countries and its allies to defer the supply hike. Oil fell 2.5% to $63.96 a barrel as of 9:37 a.m. in New York.

Yet a pause would also have carried some political risk. Despite the recent sell-off, Saudi Arabia faces pressure from the U.S. and other key consumers to ensure supplies remain plentiful enough to stave off an inflationary price spike. Ignoring such considerations could strain the kingdom’s already-fraught relations with Washington.

Prior to Thursday’s meeting, ministers indicated that they were concerned about the impact of omicron on oil demand but were struggling to figure out exactly how serious the new strain would become. Giving themselves the ability to immediately change course is one way of managing this uncertainty.

“The meeting shall remain in session pending further developments of the pandemic and continue to monitor the market closely and make immediate adjustments if required,” according to the communique published on the OPEC website.


Jordan Cove project dies. What it means for FERC, gas
Niina H. Farah, Miranda Wilson, Carlos Anchondo, ENERGYWIRE, December 2, 2021

The developer of an Oregon liquefied natural gas export terminal told the Federal Energy Regulatory Commission for the first time yesterday it would not move forward with the embattled project, putting to rest years of uncertainty for landowners.

Citing challenges in obtaining necessary permits from state agencies as the reason for abandoning the Jordan Cove project, Pembina Pipeline Corp. asked FERC to cancel authorizations for the LNG terminal and associated Pacific Connector pipeline, which would have carried natural gas from Canada to the proposed facility in Coos Bay, Ore.

“Among other considerations, Applicants remain concerned regarding their ability to obtain the necessary state permits in the immediate future in addition to other external obstacles,” Pembina said in its brief to FERC.

The announcement adds to a debate about the role of natural gas at a time of high prices and as industry groups are pressuring the Biden administration to clarify exactly how LNG exports fit into its broader climate agenda (Energywire, July 8). It also may influence FERC’s ongoing review of how it approves gas projects.

Pembina’s move is a win for landowners who have been steadfastly opposing the project for years, said David Bookbinder, chief counsel for the Niskanen Center and attorney for some of the landowners affected by the pipeline. The Niskanen Center and others submitted a brief of their own yesterday, urging FERC to grant Pembina’s request to ax the certificate.

“I can say the landowners are utterly delighted that this chapter of their 15-year nightmare is over and hopefully that will truly be the end of Pembina’s hopes to build this project,” he said.

The company had put the export project on an indefinite hold in April after failing to get key state and federal approvals.

But Pembina’s decision to cancel the project outright means affected landowners can now move forward with plans to improve or sell their property, Bookbinder added.

The commission did not respond to a request for comment on the brief since the issue remains pending.

Christine Tezak, managing director of research at ClearView Energy Parnters LLC, said she would expect FERC to grant the request.

“There is no mystery as to what Pembina is doing, and this will be the end of that, in my view,” Tezak said.

Scott Lauermann, a spokesperson for the American Petroleum Institute, called the cancellation of Jordan Cove “yet another unfortunate example of a much needed U.S. energy infrastructure project being terminated due to unnecessary regulatory delays.”

Canceling the project, which was slated to carry LNG to Asian markets, meant the U.S. had “lost an opportunity to export its success in reducing emissions,” said Western States and Tribal Nations President Andrew Browning in a statement.

He noted that the Asian countries purchasing U.S. LNG were seeking to replace coal consumption.

“It’s equally a loss for American energy producers and the economic development they create in sovereign tribal nations and rural Western communities,” Browning said.

Initially proposed in 2007, Jordan Cove has been contested for over a decade by nearby property owners, environmental groups, Indigenous communities, and Oregon state officials. Opponents raised concerns about the project’s climate change contributions, impacts on tribal territories and waterways, and consequences for tourism and fishing industries.

The proposal has also been a symbol of FERC’s alleged deference to industry in its assessments of natural gas projects. When the commission approved the latest iteration of the project in a 3-1 vote last year, critics — including then-Commissioner and current FERC Chair Richard Glick, who dissented — accused the majority on the commission of ignoring signs that the project benefits didn’t outweigh the costs.

“[The] Commission’s public interest analysis does not adequately wrestle with the Project’s adverse impacts,” Glick said in a statement at the time. “The Project will significantly and adversely affect several threatened and endangered species, historic properties, and the supply of short-term housing in the vicinity of the project.”

Now that it has been canceled, the Jordan Cove case provides additional evidence that FERC must scrutinize natural gas proposals and fully consider whether they are in the public interest, said Gillian Giannetti, an attorney at the Natural Resources Defense Council’s Sustainable FERC Project.

She noted that Jordan Cove’s cancellation comes at the same time as another project, the Spire STL pipeline in Missouri and Illinois, is facing an uncertain future in part because of FERC’s review of the plan. Earlier this year, the U.S. Court of Appeals for the District of Columbia Circuit revoked the federal agency’s 2018 authorization of the Spire pipeline, having found that FERC disregarded evidence showing the facility wasn’t needed.

The agency is considering whether to study a broader array of factors, including environmental justice impacts and climate change, when determining the need for a new natural gas pipeline in light of that and other court decisions.

“Aside from the Spire case, [Jordan Cove] is the single worst approval that FERC has ever done for a gas project,” Giannetti said. “It’s an example of the lack of scrutiny that FERC has applied to these kinds of projects historically.”

Pembina’s brief comes in response to a D.C. Circuit decision that directed FERC to take another look at the company’s certificate in light of the company’s decision to pause the project in April. Last month, the court gave the commission 90 days to decide whether to pause the certificate that had authorized Pembina to build Jordan Cove (Energywire, Nov. 2).

In response to the court, FERC ordered the project developer to clarify its intentions with the pipeline by Dec. 1. The commission asked parties to weigh in on whether it should issue a “stay” on the projects’ permits.

But by vacating the certificates altogether, the question of a stay “would be moot, since there would be no authorizations to stay,” Pembina said in its brief.

Once the independent agency responds to Pembina’s request, the Court of Appeals will need to approve FERC’s decisions as well, said Susan Jane Brown, wildlands program director and staff attorney at the Western Environmental Law Center. The organization has represented a coalition of groups who’ve been challenging the project.

“At long last, landowners, tribes, the State of Oregon, and conservationists might, finally, have some clarity that this project is actually dead and buried,” Brown said in an email. “Now, we wait for FERC to act.”

The project’s cancellation will also mean the D.C. Circuit will not yet address whether the Natural Gas Act allows companies to use eminent domain to seize land to build pipelines specifically for export projects. That question was at the heart of the litigation over the FERC certificate.

Following the filings with FERC, landowners will ask the D.C. Circuit to remand the certificate so FERC can vacate it, said Bookbinder.

‘Nail in the coffin’

Jordan Cove first received a certificate from FERC to operate as an import facility in December 2009, before reapplying in 2013 to export LNG instead.

That same year, the developer of the Pacific Connector pipeline applied to the commission to allow it to carry 1 billion cubic feet of natural gas per day to the export facility (Energywire, June 10, 2013). Pacific Connector and Jordan Cove are affiliate companies of Canadian energy corporation Pembina.

The project appeared on course for approval when in 2014, commissioners deemed the pipeline would have minimal environmental impact. Environmental groups at the time called the Obama administration’s analysis “a soft denial of climate change” (E&E News PM, Nov. 7, 2014).

But in 2016, FERC issued a surprise decision declining to authorize the project, saying the project’s developers had failed to show adequate demand for the project that would outweigh its harms to property owners.

The project’s fortune’s changed again under former President Trump. Jordan Cove and Pacific Connector reapplied for the project, and FERC’s Republican-controlled commission approved it in March 2020. The majority of commissioners said at the time that the pipeline was “required” for the public good and that the LNG terminal was “not inconsistent with the public interest.”

“The proposal would have economic and public benefits, including benefits to the local and regional economy and the provision of new market access for natural gas producers,” FERC said in its order.

But the project also faced other troubles that eventually pushed the company to suspend the project.

In January, FERC declined to overrule Oregon’s Department of Environmental Quality determination in 2019 that the project didn’t comply with state water quality standards and denied its Section 401 certification. The Commerce Department had also ruled the harms of the project to the Pacific coast and Indigenous communities outweighed the project’s benefits. NOAA also had deemed the project “inconsistent” with the Coastal Zone Management Act (Greenwire, April 23).

In response to the Jordan Cove cancellation, Sen. Jeff Merkley (D-Ore.) said in a statement the country needs “to be investing in infrastructure and creating good jobs that speed the transition away from fossil fuels and toward renewable energy as quickly as possible.”

Bookbinder predicted the cancellation would have limited impact on planned LNG terminals elsewhere in the U.S. There is still a significant market for LNG, and Gulf Coast states have been “more than happy” to build export terminals, Bookbinder said.

For the Oregon project, 30 percent of landowners affected by the pipeline had held out on signing away their land, an unusually large amount of opposition that continued over 15 years, according to Bookbinder.

“I would like to say this is a nail in the coffin, but that’s not realistic,” he said.

Since Jordan Cove was first proposed, the odds of it getting built have been low, said Erin Blanton, a senior research scholar at the Center on Global Energy Policy at Columbia University’s School of International and Public Affairs. Local opposition has been strong from the start, and its “unique location” also put it at a disadvantage, Blanton said.

“I’m not surprised by this,” Blanton said. “I don’t think it’s reflective of a general trend in the industry.”


As Freeport converts mining trucks to green power, costs unclear
Ernest Scheyder, Mining.Com, December 2, 2021

Copper mining giant Freeport-McMoRan Inc is converting its fleet of diesel trucks and other machinery to electric or hydrogen power, a transition required to fight climate change even though the costs are not yet known, Chief Executive Richard Adkerson said in an interview at the Reuters Next conference.

The mining industry is grappling with its paradoxical role as supplier of copper, lithium, and other building blocks for renewable technologies even as operations contribute to global warming.

Freeport, which operates mines in the Americas and Indonesia, has roughly 600 haul trucks – some of which move more than 400 tonnes (881,850 pounds) of dirt per load – and numerous other pieces of equipment.

To power those machines, Freeport bought 180 million gallons of diesel last year, according to regulatory filings, contributing to its so-called scope one (direct) emissions.

“We have to make investments to reduce carbon emissions,” Adkerson said in the interview released Wednesday. “We’re going to do that. It’s going to cost some money.”

The Phoenix, Arizona-based company is testing electric- and hydrogen-powered trucks and is studying other fuel sources for its coal-fired powered power plant in Indonesia, where it runs the world’s second-largest copper mine.

Joint efforts

Freeport is also participating in the Charge on Innovation Challenge with Rio Tinto Ltd, BHP Group Ltd and others to help better electrify mine sites.

It joined hydrogen fuel consortiums in South America and next year plans trial runs of diesel-electric trucks from Komatsu Ltd and Caterpillar Inc.

Energy accounts for roughly 20% of Freeport’s annual operational costs, though it is not clear yet how that could change once the entire fleet is converted, the company said.

“There will be an impact on supply as a result of converting all of this,” said Adkerson. “There are more questions than answers right now.”

But Adkerson, who has been CEO since 2003, said it was “absolutely necessary” for Freeport to curtail emissions. He cited extreme weather caused by global warming and the incongruity of copper mining creating emissions while the metal is needed for green energy solutions

“The world is going to need copper, and yet copper mining has emissions,” he said.

Net zero emissions by 2050

The International Council on Mining and Metals (ICMM), an industry trade group chaired by Adkerson, set a goal in October for all members – including Freeport – of net zero direct and indirect carbon emissions by 2050 or sooner, in part by retiring diesel-powered equipment.

Freeport is also studying ways to re-process waste rock at its mine sites to extract an estimated 10 billion pounds or more of copper. Adkerson said it is too soon to say how much copper could eventually be produced using this method but added: “Our technical team is really excited about it.”

In Spain, Freeport is recycling electronic scrap waste at one of its smelters. The operation is not expected to become a major focus for the company, which prefers to focus on operating large mines, Adkerson said.

“That (copper) scrap will be needed because of what I believe is the coming real scarcity of copper,” he said. “We just don’t see (recycling) as a business opportunity for Freeport.”


Japan Is Backing Oil and Gas Even After COP26 Climate Talks
Stephen Stapczynski, Tsuyoshi Inajima, Bloomberg, December 1, 2021

Officials said to fear fuel shocks caused by less investment

 Import dependent nation wants to avoid fuel shortages

It’s been less than a month since world leaders pledged to combat climate change at the COP26 summit in Glasgow, yet Japan is already showing signs of putting the brakes on divestment from fossil fuels.

Government officials have been quietly urging trading houses, refiners, and utilities to slow down their move away from fossil fuels, and even encouraging new investments in oil-and-gas projects, according to people within the Japanese government and industry, who requested anonymity as the talks are private.

The officials are concerned about the long-term supply of traditional fuels as the world doubles down on renewable energy, the people said. The import-dependent nation wants to avoid a potential shortage of fuel this winter, as well as during future cold spells, after a deficit last year sparked fears of nationwide blackouts.

Japan joined almost 200 countries last month in a pledge to step up the fight against climate change, including phasing down coal power and tackling emissions. However, the moves by the officials show the struggle to turn those pledges into reality, especially for countries like Japan which relies on imports for nearly 90% of its energy needs, with prices spiking partly because of the world’s shift away from fossil fuel investments.

The nation has been slow to make any concrete commitments to phase out coal in the near term, and has often been criticized for its funding of overseas power plants that use the dirtiest burning fossil fuel. The government has also avoided joining efforts by developed nations to reduce consumption of natural gas.

Japan’s Ministry of Economy, Trade and Industry declined to comment directly on whether it is encouraging industries to boost investment in upstream energy supply, and instead pointed to a strategic energy plan approved by Prime Minister Fumio Kishida’s cabinet on October 22. That plan says “no compromise is acceptable to ensure energy security, and it is the obligation of a nation to continue securing necessary resources.”

Dirty Mix

Japan depends on fossil fuels as it struggles to boost clean energy

That latest strategy calls for the share of oil and natural gas produced either domestically or under the control of Japanese enterprises overseas to increase from 34.7% in fiscal year 2019 to more than 60% in 2040. Japanese officials plan to convey to other nations the importance attached to continued investments in upstream supply, the people added.


Report: Markets like carbon-cutting firms
Ben Geman, Axios, December 2, 2021

Analysis of companies’ market performance shows a relationship between emissions-cutting and higher share prices relative to earnings, a metric of investor confidence.

Driving the news: Lazard, a financial advisory firm, explored the equity values and emissions of over 16,000 companies in 2016-2020.

What they’re saying: “The data accumulated so far make it clear that the more greenhouse gases a company emits, the lower its stock price relative to its earnings,” Lazard’s Peter Orszag and Zachery Halem write in a Bloomberg column.

  • “[I]t’s clear the stock market is already rewarding companies that reduce emissions with higher valuations,” they write.
  • Orszag, who headed the White House budget office early in the Obama era, is Lazard’s CEO for financial advisory. Halem directs the new Lazard Climate Center, which released the analysis yesterday.

Zoom in: The nexus between emissions and market performance varies by company size, type, and location.

  • It’s more pronounced for large companies, which the analysts posit is because of greater scrutiny and regulations.
  • “For European industrial companies with a market cap above $50 billion, the price-earnings multiple falls by a whopping 18% for every 10% increase in carbon emissions,” their column notes.

What’s next: They predict valuations will become increasingly tied to emissions as CO2 prices rise in Europe and, more broadly, as climate controls grow stronger.