Potentially facing billions of dollars in lost revenue, states and utilities pursuing clean energy projects are deciding how to react to a Federal Energy Regulatory Commission order that could push vast amounts of new renewable and existing nuclear power out of the PJM Interconnection's capacity market, which spans parts of the Mid-Atlantic and Midwest.
The stakeholders most exposed to the new FERC order, including those in states that have adopted aggressive clean energy targets or passed laws to provide zero-emissions credits to existing nuclear plants, may have to choose between having their ratepayers support unsubsidized power plants, such as older merchant coal-fired units, or implementing new programs to procure their own capacity outside the 13-state market.
On Dec. 19, 2019, FERC issued an order that will greatly expand the PJM's minimum offer price rule, or MOPR, to mitigate the impact of state-subsidized resources on the region's annual capacity auction. That auction ensures that PJM has sufficient resources to meet power demand three years ahead.
Under the new directive, the MOPR, which sets an administratively determined price floor for various types of resources, would be expanded to apply, with some exceptions, to "all new and existing, internal and external, state-subsidized resources that participate in the capacity market, regardless of resource type," the order said.
Unless resources subject to the new MOPR can demonstrate that their actual costs are lower than the administratively determined price under a unit-specific review, those resources must offer their capacity at that price floor, preventing them from making bids as a low as zero in order to clear PJM's capacity auction. That change makes the task of competing against unsubsidized resources that are not subject to the MOPR more difficult for state-sponsored nuclear plants and new generation built under a state renewable portfolio standard. Customers of subsidized resources are also at risk of paying double for capacity — first through the state subsidy and again if the subsidized resource does not clear the capacity auction and a load-serving entity must procure power from another source.
The order exempts from the MOPR unsubsidized renewable energy and existing renewable resources that receive credits under state RPS programs. But the MOPR would apply to new renewable generation that receives state credits, as well as existing nuclear plants that benefit from state-issued subsidies. In a surprise move, the MOPR will also now apply to new capacity from public power producers, electric cooperatives and vertically integrated utilities that "self-supply" their own generation to members and regulated ratepayers.
FERC Chairman Neil Chatterjee said the commission's directive for PJM to change its capacity market rules is fuel-neutral and will create a more level playing field among capacity resources. But utilities and other clean energy developers say the policy change will disrupt state clean energy goals and force PJM capacity prices higher.
In an October 2018 related filing, PJM estimated that default MOPR floor offer prices in the region, net of energy and ancillary services market revenue, for the 2022/2023 Delivery Year Base Residual Auction would be $4,327 per MW-day for offshore wind projects, $2,489 per MW-day for onshore wind power, and $1,451 per MW-day for nuclear plants. Those prices are well above the floor offer prices of $1,023 per MW-day for coal and $438 per MW-day for combined-cycle natural gas-fired generation. Solar photovoltaic generation would be more competitive, with PJM estimating a MOPR floor offer price for those resources of $387 per MW-day.
Although the December 2019 order allows for unit-specific reviews that could exempt some facilities from the new rule, the expanded MOPR "makes it literally impossible for many new renewable resources to clear" PJM's capacity auction, said Mason Emnett, vice president of competitive market policy at Exelon Corp. After the release of FERC's order, Exelon said in a statement that the new rule could "cost thousands of jobs, increase air pollution and unnecessarily raise electricity bills by $2.4 billion annually."
Exelon owns 75% of the 1,819-MW Quad Cities nuclear plant in Illinois, which supplies 1,364 MW of its capacity to PJM, and roughly 43% of the 2,328-MW Salem nuclear plant in New Jersey, which it co-owns with Public Service Enterprise Group Inc. Those plants are eligible for zero-emissions credits that Illinois and New Jersey have approved under respective state laws.
In addition to state-supported nuclear generation, many planned renewable projects could be vulnerable to the FERC order.
According to a July 2019 presentation from PJM, the grid operator has over 34 GW of new generation in its interconnection queue, most of which are solar projects in Virginia, Ohio and Pennsylvania, and wind projects in New Jersey and Virginia. However, most projects that enter the queue do not reach commercial operation, meaning the figures "are not indicative of how much generation will actually be built," PJM spokesman Jeff Shields said.
But the number of new clean energy projects planned for the PJM in the coming years could be much higher when factoring in future RPS goals. PJM has received more than 92 GW of wind and solar interconnection requests, with many of the projects having already invested significant capital in development, according to a Jan. 8 presentation by Advanced Energy Economy.
Furthermore, public power producers, electric cooperatives and any "political subdivision" offering new capacity in PJM will be subject to the broader MOPR, although the order would not apply to existing self-supply arrangements and new self-supply resources can seek unit-specific exemptions. The move angered public utilities and rural cooperatives, which argue the change will increase costs for customers if their new generation projects and long-term power purchase agreements cannot clear PJM's capacity market.
"To say that a co-op's ability to charge rates to its members is somehow an out-of-market revenue is a very narrow conception of what the market is," said Randy Elliott, regulatory counsel for the National Rural Electric Cooperative Association.
According to FERC's Dec. 19 order, new self-supply capacity, which can also be provided by vertically integrated utilities such as Dominion Energy Inc., represented 30% of new generation added to the PJM in capacity auctions between 2010 to 2017.
What states and utilities could do
FERC's order preserved an existing option for utilities to remove all their capacity from PJM under what is called a fixed resource requirement. The commission, however, scrapped an earlier proposal to do away with this all-or-nothing requirement and allow utilities to withdraw capacity and associated load from only specific resources.
With the market likely becoming less favorable to subsidized energy, states may help utilities pull their capacity out of PJM so that states can directly procure subsidized clean energy resources themselves.
Lawmakers in Illinois, which is home to several nuclear plants receiving state zero-emissions credits, have already proposed legislation to set up their own procurement program through a state agency rather than the PJM auction. The proposal for the Illinois Power Agency to manage capacity needs is contained in the state's Clean Energy Jobs Act, legislation that seeks to remove carbon from Illinois' power sector by 2030 and transition to 100% renewables by 2050.
Christie Hicks, a senior attorney and manager of clean energy regulatory implementation at the Environmental Defense Fund, thinks the FERC decision makes only more pressing the need for lawmakers to take up the proposal in the coming months. The risk to clean energy policies and for "substantial" increases to consumer bills could catalyze action during the spring session, she said.
"Illinois has really prided itself over the last few years on being a clean energy leader, not just for the Midwest but nationwide, and to keep that momentum going forward, I think legislators are interested in taking action this spring," Hicks said.
Illinois Gov. J.B. Pritzker recently signaled his support for clean energy legislation, telling NPR that the idea is "very much alive," according to a Jan. 14 report.
New Jersey regulators are also concerned with the order and its potential harm to the state's renewable energy program, Board of Public Utilities President Joseph Fiordaliso said. The state has both subsidized nuclear plants and an aggressive offshore wind goal.
"This ruling can potentially be detrimental to the state of New Jersey," Fiordaliso said during the board's Jan. 8 meeting. He added that the agency is working on many fronts to mitigate the order's impact. In addition, the Maryland Public Service Commission, Public Utilities Commission of Ohio and the Public Service Commission of the District of Columbia each plan to file for rehearing of the decision.
Maryland PSC Chairman Jason Stanek on Dec. 20, 2019, issued a statement outlining the commission's concern that it could undermine the state's clean energy goals in the coming years. Maryland requires utilities to get half of their power from renewable sources by 2030, a standard that includes an in-state solar carve-out and a directive for the installation of 1,200 MW of offshore wind capacity by 2030. Gov. Larry Hogan wants Maryland to get all of its electricity from clean resources by 2040.
Stanek said the Federal Power Act gives states the right to determine their own resource mix. "FERC's decision targets, and effectively nullifies, that prerogative and only confirms our misgivings regarding the future of PJM's capacity market," he said.
The District of Columbia PSC on Jan. 14 said it would fight the matter all the way to the federal appeals court, if necessary, and promised to follow through on the District's commitment to renewable resources.
But some market experts are skeptical that utilities will withdraw from PJM's capacity market given its huge size and associated revenues. "I don't see anyone leaving," said R. Scott Everngam, president of consulting firm Blue Horseshoe Energy LLC and a former analyst at FERC's Office of Energy Market Regulation.
"Partial reregulation by the states exploiting holes in the MOPR was artificially lowering ... capacity prices in my view," Everngam said. "So I feel these states should either stick with the merchant model for new resources or leave PJM. But they cannot afford to do so. It's just a big political bluff that would cause huge price increases to consumers, so I can't see any state leaving."
Requests for rehearing on FERC's order are due Jan. 21, with the commission typically taking many months if not years to act on such requests. In addition, PJM must submit a compliance filing by March 18 detailing how the grid operator will implement the order. Once FERC acts on rehearing, opponents of the capacity market order could seek judicial review.
"If NRECA were to take this order to court, we would argue that FERC's determination that every co-op arrangement to self-supply new capacity constitutes an inherent 'state subsidy' warranting mitigation by PJM's [MOPR] is arbitrary and capricious and not based on substantial evidence," NRECA's Elliott said.
Critics could also allege that FERC is effectively undermining states' authority under the Federal Power Act to craft policies on generation. In his dissent to FERC's order, the commission's lone Democrat, Richard Glick, said the order "permits the commission to zero out any state effort to address the externalities associated with sales of electricity," including the Regional Greenhouse Gas Initiative to reduce carbon emissions in the Northeast and potential future state carbon taxes, cap-and-trade programs and clean energy standards.
"A theory of jurisdiction that allows the commission to block any state effort to economically regulate the externalities associated with electricity generation is not a reasonable interpretation of the FPA's balance between federal and state jurisdiction," Glick said. (FERC dockets EL16-49, EL18-178)