The year 2021 may not be kind to the US natural gas sector as its struggles with environmental hurdles intensify. Foremost, as the page is turned on a presidential administration more prone to loosening regulation than reining in the industry, the transition is bound to be rocky. But there is also little doubt that the sprint to make the US a global LNG powerhouse will gain steam, even as headwinds continue to menace gas infrastructure in the Northeast.
President-elect Joe Biden’s inauguration in a few weeks will usher in major changes — and unknowns — for the role of gas in the new administration’s plans for carbon neutrality by 2050.
Top of mind for producers is how hard, and how quickly, Biden’s Interior Department will implement his proposed ban on new leasing and permitting within federal lands and waters — a big risk for future gas output in the Rockies. Open questions include whether existing leaseholders can still obtain permits, whether any areas will be exempted, and whether the ban applies to areas where the federal government only owns the subsurface.
Meantime, Biden’s choice of US Rep. Deb Haaland (D-New Mexico), a progressive favorite, to head Interior suggests a strong crackdown on industry access. Watch for further clues from her in the coming months on that topic, as well as possible hikes in oil and gas royalty rates.
Another question is where gas would fit into stronger greenhouse gas (GHG) regulations on power plants that are likely to be advanced by the Environmental Protection Agency. During the last days of the campaign, Biden indicated gas should have a role in a low-carbon economy if carbon capture is used. Watch to see if the power plant rules are moderate enough to promote both gas and renewables, or whether they squeeze out gas — and how quickly.
Infrastructure is another concern. Biden has promised to ensure every infrastructure decision at the federal level considers life-cycle GHG impacts. But it’s unclear how gas pipelines and LNG terminals fit, partly because gas is cleaner than oil on a carbon basis but also because gas infrastructure decisions are largely in the hands of the independent, bipartisan Federal Energy Regulatory Commission (FERC).
Biden will eventually have the opportunity to bring the commission to a 3-2 Democratic majority, which may result in a higher bar for approvals. Watch to see how strongly Biden’s FERC appointees’ positions evolve on the topic — especially whether the greater scrutiny would result in the outright rejection of projects or whether more mitigation steps would simply be required.
ESG Front and Center
The momentum pushing US natural gas independents to grapple with environmental, social and corporate governance (ESG) issues is gaining traction heading into the new year, and players could find themselves in the hot seat.
Already facing a likely crush of attention from the incoming Biden administration, producers will also confront increasingly aggressive investors in 2021. Major asset managers like BlackRock, Vanguard and State Street — crucial upstream investors with a 20% combined stake in the US space — put executives on notice this year that ESG will play a significant role in their investment decisions (NGW Dec.14’20).
Management is getting the message. Several gas producers have amplified their annual sustainability reporting; some say the ESG tumult is an opportunity.
Toby Rice, CEO of top US gas producer EQT, noted recently that the Marcellus Shale produces 16% of US supply, but accounts for just 4% of total onshore emissions.
“Appalachian players produce approximately 60% more gas with 70% lower emissions intensity. What excites me about this data is the differentiation of natural gas and in particular Appalachian natural gas,” Rice said during a recent conference call. “We think as people start to look at the data, there will be a decoupling of natural gas from other fossil fuels as it pertains to environmental and socioeconomic benefits.”
State Street this month joined BlackRock, JPMorgan Chase and other key investors when the firm signed on to the global Climate Action 100+ initiative. The move was made to help “asset owners reduce the carbon intensity of their investment portfolios and embrace the growth opportunities in green innovation,” CEO Cyrus Taraporevala said in a podcast.
Among the goals of the initiative is the adoption and implementation of the recommendations set by the Task Force on Climate-related Financial Disclosures (NGW Oct.26’20). Some $50 trillion is held in assets under management by the group’s membership.
Climate Action 100+ has achieved some success with management at European majors including Equinor, Royal Dutch Shell and Total on topics including setting emissions targets, linking executive pay to climate targets and reviewing lobbying activity.
But the track for such change in the US is muddier, although producers have slowly come around on disclosure. In December, Exxon Mobil adopted its first-ever comprehensive GHG emissions reduction targets through 2025, but shunned aspirations of net-zero emissions and skipped disclosure of emissions of its products.
Insiders say companies of all sizes will be expected to address their emissions and set targets for reduction, regardless of their operations’ scope. EQT’s Rice said that could be a problem for small-scale companies.
“Larger companies have the resources needed to dedicate to improving ESG performance,” he said. “And ESG performance is going to be a differentiator and something that investors care about.”
BlackRock and its investment peers typically move first with corporate engagement. But their new rhetoric suggests if that proves unsuccessful, they will employ their formidable proxy vote to influence companies on ESG matters.
“BlackRock believes that climate change has become a defining factor in companies’ long-term prospects,” said Sandy Boss, global head of investment stewardship. “Specifically, we expect companies to articulate how they are aligned to a scenario in which global warming is limited to well below 2°C and is consistent with a global aspiration to reach net-zero GHG emissions by 2050.”
Andrew Logan of sustainability nonprofit Ceres tells Energy Intelligence that after years of little to no action on shareholder proposals beyond incremental disclosures, shareholders are reaching an inflection point.
“There is a point at which investors lose patience, particularly on climate, where there’s a growing sense that the time is relatively short,” he said. “The real lever that investors have at the end of the day is changing the board.”
During the 2020 proxy season, BlackRock opposed the re-election of more than 5,100 directors, its most voluminous opposition ever, “sending a strong signal of concern when companies did not make sufficient progress,” Boss said.
LNG Rests on Laurels
The LNG sector will likely take a break from growth as the US settles in as one of the top three exporting nations, while again demonstrating its contractually set flexibility in another year where demand is expected to be buffeted by Covid-19 impacts.
No additional US LNG capacity is expected to enter service during 2021, although the build-out past 100 million tons per year of capacity (13.7 billion cubic feet per day) will continue apace.
The 4.5 million ton/yr (0.64 Bcf/d) Corpus Christi Train 3 shipped its first cargo in early December and will continue to ramp up operations during the early part of 2021. That brings total US LNG capacity to about 71 million tons/yr (10.1 Bcf/d), comparable to its chief international rivals Qatar (77 million tons/yr) and Australia (87 million tons/yr).
The US build-out will continue post-2021 with the 4.5 million ton/yr Sabine Pass Train 6 being completed in the second half of 2022. Venture Global’s 10 million ton/yr (1.4 Bcf/d) Calcasieu Pass project is expected to see six of its 10 modular trains installed by February 2021; however, operations are set to start in the second half of 2022.
What about US LNG final investment decisions (FIDs) in 2021?
For one project, an FID appears likely next year. For others, a 2021 FID appears essential or funding will run out.
The 10 million ton/yr (1.4 Bcf/d) first phase of Venture Global’s Plaquemines LNG plant may see an FID in 2021, especially given that all its initial capacity will be fully contracted by the end of June, according to Venture Global CEO Mike Sabel.
It was a bold prediction to make in a Covid-19-stalled market, but Venture Global’s track record in bringing Calcasieu Pass to FID makes it hard to ignore. Also, the fully approved project has already signed 20-year binding agreements for 3.5 million tons/yr (0.5 Bcf/d) with Poland’s PGNIG (2.5 million tons/yr) and French EDF (1 million tons/yr).
Plaquemines LNG could turn out to be the only US FID in 2021 as Covid-19-related demand shifts force developers to keep their powder dry (NGW Nov.23’20). Leading US LNG developers Cheniere Energy and Sempra Energy in particular have the financial wherewithal to calmly await the post-Covid-19 rebound (NGW Nov.16’20).
But for at least one US LNG project, next year could be do-or-die.
NextDecade, developer of the 27 million ton/yr (3.8 Bcf/d) Rio Grande project, reported in its most recent corporate presentation that it has “confirmed pre-FID liquidity to operate through year-end 2021.” More funding could, of course, be found, and the project has seen activity this year, if not momentum (NGW Nov.9’20). However, as it stands, 2021 could be the end of the road for Rio Grande.
Will 2020’s cargo cancellation wave make a reappearance in 2021? As world LNG markets emerge from Covid-19 demand constraints, there may be less need for cargo cancellations. However, if a global supply glut were to build because of normally light seasonal loads, US cargoes are — by contract — the most easily cancelable supply (NGW Jun.29’20).
One theme that will definitely find its way into 2021 is the environment, with the various US LNG projects likely going to great lengths to show how clean and green they plan to be. Carbon-neutral announcements like that of Rio Grande are expected to proliferate (NGW Oct.12’20).
US LNG developers are generally wary of regulatory changes, and there will be some of that as President-elect Joe Biden takes office in January. But the current build-out will continue on a fully approved basis through 2026, past Biden’s first term, when the last liquefaction train of Golden Pass goes on line.
No Respite for Pipeline Projects
After a tough 2020, natural gas pipeline projects could again be swimming upstream against two formidable currents: regulatory and legal actions vacating faulty permits and intransigence by some states to issue the needed permissions allowing water crossings.
This has been especially true for marquee projects providing egress from Appalachia to burgeoning Southeast markets. The year 2020 saw the 600 mile Atlantic Coast Pipeline canceled outright, while the stalled, 92%-complete Mountain Valley Pipeline (MVP) spent the year lurching toward restarting construction only to have litigation led by green groups slam the door shut (related).
“Environmental groups have become very good at finding mistakes in permits especially at the state and local level and have been able to hold up these projects,” Matt Lewis, a senior director at East Daley Capital Advisors, told Energy Intelligence.
Pennsylvania, however, does a “pretty good job” with permitting, which allowed Transco’s Atlantic Sunrise project to come on line in 2018 despite virulent opposition. “Environmental groups weren’t able to shoot against those permits,” Lewis said.
This could allow PennEast Pipeline to start the first phase of the project in Pennsylvania by this time next year, Lewis said (NGW Dec.21’20). Phase 2 construction depends on wresting needed water crossing permits from New Jersey.
It’s harder to discern where MVP, which runs 300 miles from Bradshaw, West Virginia, to Pittsylvania County, Virginia, will stand next year at this time as environmental groups have successfully tied up the project in regulatory knots. MVP is already two years behind schedule and $2.5 billion over its original budget.
“West Virginia took a year to rewrite some of their permitting rules for water crossings to allow this project to move forward and even after all that time and rewriting the laws, they still made mistakes in the permitting that caused this to get held up in federal court,” Lewis said.
MVP is also planning to divide the project into two phases. The first section within West Virginia will likely begin delivering 1 Bcf/d — half of MVP’s planned capacity — to the Columbia gas system later this year. The Virginia leg’s timing is more murky, although a 2021 completion is possible.
Meanwhile, brownfield projects designed to debottleneck Appalachia’s egress capacity will continue (NGW Nov.16’20).
Williams is in the process of rolling out two pipeline expansion projects on the Transco system that can push more than 1 Bcf/d of Appalachian supply into the mid-Atlantic and Southeast markets. Southeastern Trail is already delivering 230 million cubic feet per day and will add about 300 MMcf/d to the tally in the first quarter. Likewise, Leidy South expansion is delivering 125 MMcf/d and 450 MMcf/d will be added in the coming year.
Permian Pipes a Solid Go
The Permian Basin in West Texas will have fewer problems adding needed gas egress next year. Full operations are scheduled to start up at Kinder Morgan’s Permian Highway Pipeline in January and for the Whistler Pipeline in the late third quarter or early fourth quarter.
However, while the two 2 Bcf/d capacity pipelines should provide enough associated gas takeaway capacity from the oily play through 2024-25, the question remains how the additional gas supply will impact the Gulf Coast market.
“Obviously pushing 4 Bcf/d of gas into the Texas market is going to have some impact, but I don’t think you are going to see anything like basis cratering where there is a huge discount relative to Henry Hub,“ Lewis said.
Why not? Kinder Morgan has a vast Texas intrastate pipeline system on which it’s done a good deal of capacity debottlenecking. This should ensure the new supply will “move around fairly freely” to where it’s needed — be it LNG export terminals or industrial facilities.
Likewise, Haynesville producers should not be significantly impacted by the influx as demand is growing rapidly in their Gulf Coast markets, he said.
2021 Signals Bullish, Bearish Prices
More than anything, Haynesville E&Ps need higher gas prices in order to grow production. And Lewis and others think they’ll get it as prices move north of $3 per million Btu in 2021.
That’s especially likely in the western US where prices have already eclipsed the $3 mark in most regions.
“It’s a simple case of supply falling in areas that used to feed California and the Pacific Northwest.” Lewis said. As 2021 progresses, pressure will grow to raise production in Rockies and Southwestern supply basins now in decline, he said, “And frankly, unless you have over $3 natural gas, it’s not economic to drill in those areas.”
Meanwhile, there is a broad expectation that gas prices in the eastern US will follow suit even though the 2021 Henry Hub winter contracts are struggling to break above the $2.70s/MMBtu (related).
Nonetheless, East Daley analysts estimate that the market is still around 4 Bcf/d short at this point, Lewis explained. And just as in the West, a sustained $3/MMBtu price is needed to ramp up eastern US production — especially in the Haynesville — to meet growing Gulf Coast LNG feedstock and industrial demand.
One caveat. Lewis said his outlook would turn more bearish if Permian oil prices move above $50 per barrel, which would unleash more associated gas than expected.
But Dan Lippe of Petral Consulting remains firmly in the bear’s corner, holding to a 2021 average closer to the $2.25/MMBtu he predicted in September (NGW Sep.14’20).
“We are on track to end 2020 with more gas in working storage than in any of the past four years and at least as much as year-end inventory in any of the past 10 years,” he told Energy Intelligence, adding that he also doesn’t foresee a production shortfall as many of the more productive rigs are still running.
“Production is always more resilient than the 25-year-old MBAs predict and more resilient than grouchy oil geologists and geophysicists are willing to accept,” Lippe said. “Remember, 80% of sales are generated by only 20% of salesmen. Something similar has to be true for gas production.”