Regulators Rattle AEP’s Plans to Operate 4.2-GW of Coal Power Through 2040

The Virginia State Corporation Commission (SCC) on Aug. 23 rattled American Electric Power’s (AEP’s) plans to operate the 2.9-GW John Amos and 1.3-GW Mountaineer coal power plants through 2040 when it partly denied cost recovery for expenses that the West Virginia plants need to comply with the federal Steam Electric Effluent Limitations Guidelines (ELG) rule.

The SCC on Monday approved a $27.44 million Virginia revenue requirement for the first year of an environmental rate adjustment clause (E-RAC)—a rider that recovers expenses from AEP’s Virginia customers associated with federal rules regulating the disposal of coal ash at the two plants in West Virginia. But while the SCC moved to approve AEP’s recovery of costs related to the federal Coal Combustion and Residuals (CCR), the commission denied about $4.2 million of expenses AEP had proposed for projects that would help the plants comply with the ELG rule.

Appalachian Power, the AEP subsidiary that owns the two plants, warned in its last 10-Q filing, dated July 22, that denial of ELG investment recovery could cause the company to close the generating facilities by 2028—more than a decade earlier than their planned retirement in 2040. The two plants represent around two-thirds of the subsidiary’s generating fleet.

In a statement to POWER this week, however, Appalachian Power said that a number of options still exist for the two plants, given that regulators in West Virginia recently approved cost recovery at CCR and ELG investments at both plants. “Our next steps will be to evaluate our options in light of those orders, determine the best path forward to meet the resource needs in each state, and return to the commissions if necessary for consideration of our updated costs and plans,” a spokesperson said.

American Electric Power’s 1.3-GW Mountaineer plant at New Haven, W.Va., is reflected in the Ohio River at sunset. Photo by Timothy E. Black

A Complicated Regulatory Landscape for the 2.9-GW Amos and 1.3-GW Mountaineer Plants—and a Third Giant Coal Plant, the 1.6-GW Mitchell

The SCC’s order is a new setback for Appalachian Power, which has said cost recovery of CCR and ELG retrofits at the plants would allow their generating units to provide crucially needed capacity and energy value to the utility’s customers in Virginia and West Virginia through 2040.

We are required to have a certain level of capacity—in other words, we must be ready to provide our customers a certain amount of power at any given time. Amos and Mountaineer are valuable to customers as capacity resources,” Appalachian Power spokesperson Jeri Matheney explained to POWER on Aug. 25. “In addition to avoiding replacement capacity costs, the plants also serve to protect customers from potentially volatile energy costs, with energy being the actual amount of electricity used from whatever source. The early and simultaneous retirement of nearly two-thirds of the company’s capacity would expose the company and our customers to an imprudent level of uncertainty and market volatility,” she said.

Amos, a 2,930-MW coal plant located near the Kanawha River in Putnam County, West Virginia, is the AEP system’s largest generating plant. The plant’s three units were completed between 1971 and 1973. The 1,300-MW Mountaineer Power Plant outside New Haven in Mason County, West Virginia, was completed in 1980.

In separate December 2020–submitted cost recovery filings with regulators in West Virginia and Kentucky, two other AEP subsidiaries—Wheeling Power and Kentucky Power—had also sought cost recovery for CCR and ELG investments for another West Virginia coal plant, AEP’s 1,560-MW Mitchell Plant in Marshall County.  Wheeling Power and Kentucky Power each hold a 50% stake in the Mitchell Plant, which began operating in 1980.

The West Virginia Public Service Commission (WVPSC) on Aug. 4 ultimately approved cost recovery for both CCR and ELG investments at all three plants—Amos, Mountaineer, and Mitchell. However, the Kentucky Public Service Commission (PSC) on July 15 only approved CCR-compliance projects at Mitchell, moving distinctly to deny projects related to the ELG rule. And while that order would have meant Mitchell will need to cease operations in 2028, the PSC on Aug. 19 issued another order granting Kentucky Power’s request for a partial rehearing of the July 15 order.

The Kentucky PSC’s new order, notably, directs Kentucky Power to explain Wheeling Power and Kentucky Power’s plans regarding the Mitchell plant “by submitting status reports every ten days.” Regulators also required Kentucky Power to “explain the impact” of the conflicting ELG decisions by the West Virginia and Kentucky PSCs on AEP’s strategic review of Kentucky Power’s assets. “The order also directs Kentucky Power to provide the journal entries recorded when Kentucky Power acquired Mitchell and Mitchell’s remaining net book value, including all plant accounts and asset retirement obligations, as of the most recent month for which records are available,” the PSC said in a statement.

At the Virginia SCC, Appalachian Power had argued its proposed investments for specific projects at the Amos and Mountaineer plants were the most “cost-effective means” of compliance with the federal CCR and ELG rules. The company sought recovery of an estimated $240 million investment to ensure both plants will be in compliance with both federal rules. According to Appalachian Power’s testimony, the Virginia jurisdictional share of the ELG investments would be about $60 million. As of June 30, Appalachian Power estimated its total ELG investment capital work in progress (CWIP) balances at both plants amounted to $28 million.

But in its order on Monday, the SCC said Appalachian Power had failed to meet its burden of proving that the ELG investment is “reasonable and prudent,” including “from an economic or a resource adequacy perspective.” Still, the SCC allowed Appalachian Power to provide more analyses and evidence to support the ELG investment. “We find it is critically important to analyze the overall impact of this investment on both customer rates and reliability, and that [for this specific expense] the instant record is currently lacking in both regards,” the SCC said in its order.

The SCC’s order, notably, adopts nearly all findings and recommendations contained in a July 2021 report issued by a Virginia senior hearing examiner. In that report, the examiner recommended that the SCC should approve only recovery of CCR-related costs. The examiner also recommended that if the Virginia SCC did not ultimately grant Appalachian Power approval of the ELG investments, the regulatory body should delay “consideration of the reasonableness and prudency of previously incurred ELG costs until a future case.”

AEP Walking an Energy and Environment Tightrope

While AEP has made a major effort to pare down its reliance on coal power—keeping with ambitions it announced in September 2019 that it would seek to go net-zero by 2050—as of June 30, the AEP system held 12.1 GW of coal-fired capacity, which is still nearly half its total capacity of 24.7 GW. Last year, AEP said it would shut down or refuel 5.6 GW of its 2020 coal-fired power fleet by 2030 to comply with environmental rules—including recent revisions to federal CCR and ELG rules—and rebalance its portfolio in a bid to meet ambitious climate goals. 

As POWER has reported, however, plant economics are a major factor in AEP’s spate of recently announced closures. The company, like other U.S. coal generators, is grappling with refining cost estimates of complying with environmental rules against a number of factors. Adding another level of complexity are the changing federal rule requirements as new administrations take the helm in Washington, D.C. The ELG rule, for example, has been mired in rollbacks, prompting some uncertainty within the coal power sector about where and when to make investments.

Under the Obama administration, the Environmental Protection Agency (EPA) finalized the first updates to federal effluent limitation guidelines since 1982 in November 2015, setting stringent Best Available Technology (BAT) effluent limitations and pretreatment standards for existing sources (PSES) as they apply to bottom ash transport water and flue gas desulfurization (FGD) wastewater. But in October 2020, the Trump administration issued a final rule revising the technology-based ELGs, extending timeframes, adding subcategories, and introducing a voluntary incentive program. For FGD wastewater, the 2020 rule established numeric BAT effluent limitations on mercury, arsenic, selenium, and nitrate/nitrite. For bottom ash transport water, it revised the 2015 rule’s zero-discharge limitations. 

On July 26, meanwhile, the Biden administration initiated a supplemental rulemaking to strengthen certain discharge limits in the ELG rule. A proposed rule is expected in fall 2022. Until that rule is finalized, current regulations, including the 2015 and 2020 rules will be implemented and enforced, the EPA said.

AEP’s decision to retrofit Amos and Mountaineer for ELG compliance builds on the 2020 rule, which “establishes additional options for reusing and discharging small volumes of bottom ash transport water, provides an exception for retiring units and extends the compliance deadline to a date as soon as possible beginning one year after the rule was published but no later than December 2025,” the company said in late July.

“Management has assessed technology additions and retrofits to comply with the rule and the impacts of the Federal EPA’s recent actions on facilities’ wastewater discharge permitting for FGD wastewater and bottom ash transport water.” Permit modifications for affected facilities were filed in January 2021 that reflect the outcome of that assessment, AEP said. “We continue to work with state agencies to finalize permit terms and conditions.”

At Amos, Appalachian Power has proposed to modify the bottom ash handling system (to prevent discharge of bottom ash transfer water), as well as install two new ash bunkers. Plans include retrofitting economizer ash handling systems on Amos 1 and 2 and installing a new FGD biological treatment system with ultrafiltration. Similar projects are slated for the Mountaineer plant, including a modification of the bottom ash handling system, installation of a new ash bunker, and a retrofit of a new ultrafiltration system to the existing FGD treatment system.

According to direct testimony submitted to the SCC earlier this year by Brian D. Sherrick, managing director of Projects for AEP Service Corp., continued operation under CCR and ELG rules would cost $177.1 million at Amos and $72.9 million at Mountaineer. The CCR-only option at Amos and Mountaineer—which anticipates both plants would retire by 2028—would cost a total $72.7 million at Amos (including $52.1 million in capital costs, $3.7 million in other charges, and $16.9 million in asset retirement obligation [ARO] costs), and $52.1 million for the Mountaineer plant (including $19.3 million in capital costs, $3.4 million in other charges, and $29.5 million in ARO costs).

However, James Martin, director of resource planning strategy, testified that if both the plants were to retire in 2028 in lieu of ELG compliance, customers could initially see savings but suffer the surge of customer costs through 2028 to 2039. Martin’s analysis suggested that “[t]he cumulative net cost of an Amos-only early retirement reaches a peak $880 million, and the Amos and Mountaineer early retirement net cost impact reaches $1.55 billion by 2039.” These costs anticipate the quick installation of new resources that would be required to replace the plants’ combined 4.2-GW capacity, his testimony suggested.

Appalachian Power spokesperson Matheney on Wednesday reiterated this point, underscoring the tight timeframe in which new replacement capacity will be needed if Amos and Mountaineer were retried earlier than planned.

We told the Virginia SCC that making the environmental investments for both CCR and ELG compliance at Amos and Mountaineer plants is more beneficial for customers than making only the CCR compliance investments, retiring the plants in 2028, and finding replacement capacity,” she said. “If we instead retired one or both of the plants, we would have to spend billions of dollars on replacement capacity much earlier than necessary. Virginia customers would bear the costs of this unprecedented capacity overhaul.”

Appalachian Power now faces a complex situation. “We have many factors to consider,” Matheney said. “We will take into consideration the three commission orders and the many impacts of all possible options. We’ll determine the best path forward to meet the resource needs in each state, and return to the commissions if necessary for consideration of our updated costs and plans.”

Sonal Patel is a POWER senior associate editor (@sonalcpatel@POWERmagazine).

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