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Energy

U.S. EPA Unveils Carbon Dioxide Regulations That Could End Coal and Natural Gas Power Generation

Published

2 years ago

6 minute read

From Heartland Daily News

By Tim Benson Tim Benson

The U.S. Environmental Protection Agency (EPA) announced new regulations on April 25 that would force coal-fired power plants to reduce or capture 90 percent of their carbon dioxide emissions by 2039, one year earlier than in the rule originally proposed in May 2023.

Other newly announced coal regulations include a final rule “strengthening and updating the Mercury and Air Toxics Standards (MATS) for coal-fired power plants, tightening the emissions standard for toxic metals by 67 percent, finalizing a 70 percent reduction in the emissions standard for mercury from existing lignite-fired sources,” and another rule to “reduce pollutants discharged through wastewater from coal-fired power plants by more than 660 million pounds per year.” The EPA also issued an additional rule to require the safe management of coal ash in locations not previously covered by federal regulations.

“Today, EPA is proud to make good on the Biden-Harris administration’s vision to tackle climate change and to protect all communities from pollution in our air, water, and in our neighborhoods,” said EPA Administrator Michael S. Regan. “By developing these standards in a clear, transparent, inclusive manner, EPA is cutting pollution while ensuring that power companies can make smart investments and continue to deliver reliable electricity for all Americans.”

EPA estimates its new regulations will reduce carbon dioxide emissions by 1.38 billion metric tons by 2047 and create $370 billion in “climate and public health net benefits” over the next twenty years.

Coal in a Regulatory Decline

Partially due to increasingly stringent regulations, electricity generation from coal has fallen from 52 percent of the nation’s total output in the 1990s to just 16.2 percent in 2023. Critics of the new regulations, including Jason Isaac, CEO of the American Energy Institute, argue that EPA’s new rules would make it impossible to open new coal plants and will effectively force those already online to shut down operations.

“These rules are a direct attack on an important and necessary source of American energy—one of our most affordable, reliable resources, and one that is essential here and growing in use around the world,” said Isaac. “The ignorance of this administration is negligent at best, criminal at worst, relegating the least among us to more expensive energy, or even none at all, as millions of Americans are finding out by having their electricity disconnected.

“On one hand they push to electrify everything and then with the other leave us with unreliable electricity,” Isaac said. “The Biden administration is hell bent on destroying coal and reaching new levels of recklessness.”

‘De Facto Ban’ on Coal

The new regulations almost assuredly will face legal challenges from the coal industry and others, says Steve Milloy, founder of JunkScience.com.

“Another unconstitutional EPA rule from the Biden regime that will be DOA at [the Supreme Court] but not until much harm has been caused,” said Milloy. “Congress has not authorized EPA to issue regulations that operate as a de facto ban on coal plants, yet that’s what this regulation amounts to because it mandates emissions control technology (i.e., carbon capture and sequestration) which does not, and will never, exist for coal plants.”

EPA, by contrast, says carbon capture and sequestration (CCS) is the “best system of emission reduction for the longest-running existing coal units” and a “cost-reasonable emission control technology that can be applied directly to power plants and can reduce 90 percent of carbon dioxide emissions from the plants.”

“The requirement for imaginary technology violates Clean Air Act notions of only requiring the best available and adequately tested technology,” Milloy said. “The de facto ban violates the 2022 [Supreme Court] decision in West Virginia v. EPA, which established the major questions doctrine, under which agencies cannot undertake significant new actions, like banning coal plants, without authorization from Congress.”

Natural Gas Targeted, Too

Coal plants were not the only target of new EPA regulations, as natural gas power plants are also now required to eliminate or capture 90 percent of their carbon dioxide emissions by 2032, three years earlier than called for when the draft rule was originally proposed in 2023.

The EPA is acting as if it has absolute power unconstrained by the law and prior court rulings, Darren Bakst, director of the Competitive Enterprise Institute’s Center on Energy & Environment, says in a press release.

“The [EPA] absurdly thinks its authority to regulate means it has the authority to shut down businesses,” said Bakst. “Establishing new regulations for power plants does not mean the agency can effectively force them out of business.

“This is Clean Power Plan Part II, but like with many sequels, it is worse,” Bakst said.

Tim Benson ([email protected]) is a senior policy analyst with Heartland Impact.

For more on the Biden administrations power regulations, click here.

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Thawing the freeze on oil and gas development in Treaty 8 territory

Energy

Thawing the freeze on oil and gas development in Treaty 8 territory

Published on November 8, 2025

By

From Resource Works 

Will direct tenure awards to First Nations unlock Montney gas?

By Nelson Bennett

An innovative approach to facilitating natural gas production in B.C. while respecting treaty rights could become a case study for future cooperation and partnerships between First Nations, government and industry.

In an attempt to open an area that producers have essentially been shut out of in northeastern B.C., the B.C. government directly awarded oil and gas tenure to the Halfway River First Nation, giving them greater control over how oil and gas extraction in the area might happen.

That tenure is now getting “farmed out” to companies like ARC Resources.

“The granting of the tenure by the B.C. government to the nation is new,” said Greg Kist, executive manager for Tsaa Dunne Za Energy, the Halfway River First Nation’s energy business.

Greg Kist, former president of Pacific NorthWest LNG and current managing executive for Tsaa Dunne Ta Energy, THE CANADIAN PRESS/Jeff McIntosh.

Depending on the outcome of the experiment, it’s the kind of thing that might one day be showcased at a future Indigenous Partnership Success Showcase event.

For more than two decades, a large area in Halfway River First Nation traditional territory in northeastern B.C. has been off limits to industrial activities like logging and oil and gas exploration and extraction, due to treaty rights.

In 1999, the BC Supreme Court quashed a timber harvesting permit approved by the province for Canfor, based on Halfway River First Nation’s Treaty 8 rights.

An extraction moratorium of sorts was placed over core HRFN territory, which happens to be in the “fairway” of the Montney natural gas formation.

“All of the lands were deferred from any further development,” Kist said. “And that meant everything from logging it, to oil and gas activities.”

This “deferral” of industrial activities in the area has been one of the question marks hanging over the oil and gas-rich Montney formation in northeastern B.C.

The 2021 BC Supreme Court Yahey decision had also left Treaty 8 territory dotted with question marks.

In Yahey, the court ruled cumulative impacts of activities like oil and gas development constituted a breach of the treaty rights of the Blueberry River First Nation, one of eight B.C. signatories to Treaty 8.

These various treaty rights rulings in northeastern B.C. create a serious challenge: How can B.C. continue to benefit from an abundance of natural gas to feed a burgeoning LNG industry without infringing the rights of Treaty 8 First Nations?

In the case of Halfway River, the B.C. government, the First Nation and industry are taking an innovative approach, using oil and gas tenure.

Last year, the B.C. government and HRFN signed a treaty settlement agreement that grants the nation more control over land use and development. As part of the agreement, the B.C. government directly awarded HRFN oil and gas tenure over 34,000 hectares of land. It was the first time the province has directly awarded oil and gas tenure to a First Nation.

In turn, the HRFN is now farming out its tenure rights to companies like ARC Resources, whose existing land holdings in the Attachie play are directly adjacent to the HRFN tenure.

“The resource quality is comparable to ARC’s existing Attachie asset, further extending the development runway at one of ARC’s most profitable assets,” ARC said in its second quarter financials at the end of July.

The tenure awarded to HRFN through its energy business, Tsaa Dunne Ta Energy, encompasses prime Montney real estate that had been essentially sterilized from development for decades.

“That 34,000 hectares is right in the middle of the Montney fairway,” Kist said.

Under an “earning and development” agreement with Tsaa Dunne Za Energy, ARC Resources will gain access to 36 parcels of land contiguous with its existing land parcel in the Attachie play. This expands its Attachie holdings by 10%.

Green area denotes Halfway River First Nation tenure; blue represents ARC Resources tenure.

“Think of it as Tsaa Dunne farming that land out to ARC, and we have an agreement that benefits us financially,” Kist said.

“The tenure award and landscape planning pilot will help to ensure that oil and gas development in these areas is sustainable and managed in accordance with the values of the Halfway River First Nation,” Chief Darlene Hunter said last year with the signing of the treaty settlement agreement.

Kist notes that the agreement with ARC represents only 25% of the land tenure granted to HRFN. So 75% of the land tenure could be open to further agreements with other natural gas producers.

“There will likely be more deals over time as we look at the different opportunities that are out there,” Kist said.

Kist is the former president of Rockies LNG and, before that, president of Pacific Northwest LNG. He and Jim Stannard, a former Petronas executive, are now managers for Tsaa Dunne Za Energy.

The tenure award does not represent a transfer of subsurface rights. All subsurface rights to things like minerals, coal, and oil and gas belong to the Crown.

“And at the end of the day, the B.C. government still gets its royalties,” Kist said. “But now the nation is very much in control of that activity.”

The recent agreement with ARC to develop 36 parcels adjacent to its Attachie lands is just the first one to be signed so far. There may be more such agreements in the future, Kist said.

Kist said the First Nation tenure model could end up being used elsewhere.

“I think the B.C. government’s going to look at these sorts of opportunities in areas where maybe there is a lack of development moving things forward,” he said.

“I think this could potentially be the model for development, with First Nations leading the way.”

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Alberta

Alberta’s number of inactive wells trending downward

Published on November 7, 2025

By

Aspenleaf Energy vice-president of wells Ron Weber at a clean-up site near Edmonton.

From the Canadian Energy Centre

By Deborah Jaremko

Aspenleaf Energy brings new life to historic Alberta oil field while cleaning up the past

In Alberta’s oil patch, some companies are going beyond their obligations to clean up inactive wells.

Aspenleaf Energy operates in the historic Leduc oil field, where drilling and production peaked in the 1950s.

In the last seven years, the privately-held company has spent more than $40 million on abandonment and reclamation, which it reports is significantly more than the minimum required by the Alberta Energy Regulator (AER).

CEO Bryan Gould sees reclaiming the legacy assets as like paying down a debt.

“To me, it’s not a giant bill for us to pay to accelerate the closure and it builds our reputation with the community, which then paves the way for investment and community support for the things we need to do,” he said.

“It just makes business sense to us.”

Aspenleaf, which says it has decommissioned two-thirds of its inactive wells in the Leduc area, isn’t alone in going beyond the requirements.

Producers in Alberta exceeded the AER’s minimum closure spend in both years of available data since the program was introduced in 2022.

That year, the industry-wide closure spend requirement was set at $422 million, but producers spent more than $696 million, according to the AER.

In 2023, companies spent nearly $770 million against a requirement of $700 million.

Alberta’s number of inactive wells is trending downward. The AER’s most recent report shows about 76,000 inactive wells in the province, down from roughly 92,000 in 2021.

In the Leduc field, new development techniques will make future cleanup easier and less costly, Gould said.

That’s because horizontal drilling allows several wells, each up to seven kilometres long, to originate from the same surface site.

“Historically, Leduc would have been developed with many, many sites with single vertical wells,” Gould said.

“This is why the remediation going back is so cumbersome. If you looked at it today, all that would have been centralized in one pad.

“Going forward, the environmental footprint is dramatically reduced compared to what it was.”

During and immediately after a well abandonment for Aspenleaf Energy near Edmonton. Photos for the Canadian Energy Centre

Gould said horizontal drilling and hydraulic fracturing give the field better economics, extending the life of a mature asset.

“We can drill more wells, we can recover more oil and we can pay higher royalties and higher taxes to the province,” he said.

Aspenleaf has also drilled about 3,700 test holes to assess how much soil needs cleanup. The company plans a pilot project to demonstrate a method that would reduce the amount of digging and landfilling of old underground materials while ensuring the land is productive and viable for use.

Crew at work on a well abandonment for Aspenleaf Energy near Edmonton. Photo for the Canadian Energy Centre

“We did a lot of sampling, and for the most part what we can show is what was buried in the ground by previous operators historically has not moved anywhere over 70 years and has had no impact to waterways and topography with lush forestry and productive agriculture thriving directly above and adjacent to those sampled areas,” he said.

At current rates of about 15,000 barrels per day, Aspenleaf sees a long runway of future production for the next decade or longer.

Revitalizing the historic field while cleaning up legacy assets is key to the company’s strategy.

“We believe we can extract more of the resource, which belongs to the people of Alberta,” Gould said.

“We make money for our investors, and the people of the province are much further ahead.”

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