By Rory D. Sweeney and Rich Heidorn Jr.

PJM’s first capacity auction requiring year-round availability saw prices drop by one-quarter in most of the RTO, with only the EMAAC and Duke Ohio-Kentucky regions recording increases.

Base Residual Auction prices fell to $76.53/MW-day in most of the RTO, down from $100 last year. ComEd dropped to $188.12 from $202.77, and MAAC, which cleared with the RTO at $100 last year, dropped to $86.04. EMAAC, which cleared at less than $120 last year, jumped to $187.87, while the Duke region, which did not price separately from the RTO last year, cleared this year at $130.

This was the first year in which all generation must be Capacity Performance, meaning it’s expected to be available throughout the delivery year and faces stiff penalties for nonperformance.

It was also the first year under relaxed seasonal aggregation rules, which resulted in almost 400 MW of capacity pairing winter generation (mostly wind) with summer solar, demand response and energy efficiency.

With seasonal DR no longer allowed — outside of that matched with other resources through aggregation — price-responsive demand (PRD) participated for the first time in this year’s auction. PJM members committed to 558 MW of demand reductions under PRD.

The auction also followed Illinois’ approval in December of zero-emission credit subsidies for nuclear plants. Exelon said neither its Quad Cities plant in Illinois nor its Three Mile Island nuclear plant in Pennsylvania cleared the auction.

Load Forecast Down

The auction reflected a 2.1% reduction in forecast peak load from last year’s level to 153,915 MW. The reliability requirement was reduced by 2,800 MW from DY 2019/20 because of the lower peak forecast and the PRD elections.

“When the reliability requirement goes down for the same amount of [available] capacity, it’s going to yield a lower clearing price,” said Adam Keech, PJM’s executive director of market operations, in a press conference Tuesday.

PJM acquired 165,109 MW for 2020/21, down about 2,000 MW from last year and providing a 23.3% reserve margin — the highest ever in the 14-year history of the BRA, and well above the required 16.6%.

About 189,918 MW was offered into the BRA, out of about 213,000 MW that was eligible, a decrease of 4,325 MW from last year’s offers.

Keech said the auction will cost load a total of about $7 billion in 2020/21, about the same as for 2019/20.

In total, about 3,144 MW (UCAP) of new generation offered into the auction including uprates, down 3,400 MW from last year. About 2,824 MW of the new generation cleared, mostly natural gas combined cycle and combustion turbines. (See related story, Analysts See End to New Builds in PJM Capacity Results.)

Almost 4,000 MW of capacity imports cleared, up 121 MW (3%) from last year, most of them from west of PJM. Combined with internal generation of almost 152,000 MW, generation made up 94% of the capacity acquired, with DR (7,820 MW) and EE (1,710 MW) making up the balance.

Price Separation

Prices in ComEd, MAAC and EMAAC separated from the rest of the RTO in response to unit retirements and increased transmission congestion in those regions, requiring the acquisition of local generation, said Keech. The Duke region clearing price increased because “we would need to incentivize locational capacity specifically in that area due to retirement,” Keech said.

“We have units that are at financial risk in the area that, if they retire, it could create a reliability issue,” he said.

Although Keech said confidentiality requirements restricted him from going into detail about which units were involved, the creation of the Duke Ohio-Kentucky and Dayton, Ohio, locational deliverability areas were apparently driven by the scheduled 2018 retirements of Dayton Power and Light’s Killen and Stuart coal-fired plants. At 2,700 MW, the plants represent more than half of the capacity in the Dayton LDA.

The Dayton LDA, however, cleared along with the rest of the RTO.

Seasonal Aggregation

Under relaxed rules that allowed aggregation across LDAs, 398 MW of seasonal capacity cleared. PJM filed plans with FERC in October, without stakeholder consensus, to ease restrictions on how seasonal resources can aggregate and offer into the BRA. With FERC lacking a quorum, staff tentatively approved it in March, and PJM quickly established rules in time for the auction. (See PJM Outlines Aggregation Rules for Upcoming Capacity Auction.)

The figure includes intermittent resources that exhibit seasonal performance differences, such as wind, which performs better in winter, and solar, which performs better in summer. It also includes DR resources, many of which are unavailable in the winter.

DR accounted for about 289 MW of the summer seasonal product, while EE accounted for about 103 MW and solar generation the remaining 6 MW. All 398 MW of wind seasonal product was supplied by generation, and Keech said wind accounted for 384 MW of it.

Keech said there were “quite a number” of winter capacity injection rights that didn’t get used as part of the seasonal aggregations.

“Certainly, from our perspective, we would have loved to see some more participation in that area,” he said. “Given that we have 400 MW that we otherwise wouldn’t have ever had, I think that’s successful.”

Renewables as CP

Another 504 MW of wind cleared as CP, for a total of 888 MW of wind (6,828.5 MW nameplate capacity at a 13% capacity factor). That was down about 80 MW from last year’s auction.

An additional 119 MW of solar cleared as CP beyond the seasonal aggregation. The 125-MW total (about 330 MW nameplate at a 38% capacity factor) was down 210 MW from last year’s auction.

Demand Response, EE

The amount of intermittent resources offered as CP dropped by 3,400 MW from last year, while DR offers fell by 2,085 MW compared with total DR offers for 2019/20.

DY 2020/21 will see a 2,816-MW net decrease of DR from 2019/20 to 7,532 MW and a 195-MW increase of EE to 1,710 MW.

The filing to ease the seasonal aggregation rules came after only 6% of DR cleared last year as CP. Stu Bresler, PJM senior vice president of operations and markets, said 4,700 MW of DR could have qualified as CP but didn’t clear economically. This year, 76% of EE and 79% of DR cleared.

Subsidy Impacts

Keech said he couldn’t discuss the specific impacts of the Illinois ZECs on clearing prices.

Aside from Quad Cities and TMI, Exelon’s nuclear plants in PJM did clear, with the exception of Oyster Creek, which did not participate because it is scheduled to retire in 2019.

The company “remains fully committed” to keeping Quad Cities in operation, “provided that [Illinois’] zero-emissions credit program is implemented as expected and provided that Quad Cities is selected to participate,” Joe Dominguez, Exelon’s executive vice president of government and regulatory affairs and public policy, said in a statement. The ZEC program, to be implemented by the Illinois Power Agency, has not yet been implemented.

The company used the results to call for an expansion of ZECs to Pennsylvania, noting that it was the third year in a row that TMI left the capacity auction empty-handed. “Exelon has been working with stakeholders on options for the continued operation of TMI, which has not been profitable in five years.”

Another generator looking for nuclear subsidies is FirstEnergy, which has been pressing Ohio officials for aid for its 889-MW Davis-Besse nuclear plant near Toledo and the 1,231-MW Perry plant near Cleveland. (See FirstEnergy Hopeful on State, Federal Support.)

The company’s hopes suffered a blow last week when the chair of the Ohio House Public Utilities Committee suspended hearings on the subsidy without calling for a vote. “I am not sensing a keen desire on the part of the House members to vote on this and doubt that we will have more hearings in the near future unless something cataclysmic should happen,” The Plain Dealer quoted Chairman William Seitz.

But the auction brought some good news for the company. Asked whether Perry and Besse-Davis cleared the auction, spokesman Doug Colafella responded: “Yes, a portion of all of the units FirstEnergy Solutions bid into the auction cleared.”

Also reporting on its fortunes was Dynegy, which said Wednesday that it cleared 10,217 MW, representing $456 million in revenue at a weighted average of $122.19/MW-day. That included 9,772 MW from the company’s PJM fleet ($124.27/MW-day) and 444 MW exported from MISO ($76.53/MW-day).

Still Getting Gas

Gas-fired units continue to benefit from ongoing pipeline constraints that have built up a glut of natural gas and depressed prices in the Marcellus and Utica shale regions throughout PJM’s footprint. Despite clearing prices of approximately 26 to 66% of the net cost of new entry, the auction attracted 2,350 MW of new gas-fired generation.

“I think it’s intuitive that that [gas entry] will slow down given that the prices are below” net CONE, Keech said.

Price Responsive Demand

PJM members committed to 558 MW of demand reductions under PRD, with the BGE (330 MW), PEPCO (170 MW) and EMAAC (58 MW) LDAs participating.

Unlike DR, which is counted on the supply side, PRD is deducted from the reliability requirement, shifting the LDAs’ demand curves to the left.

NRDC Critical

Jennifer Chen of the Natural Resources Defense Council was disappointed that wind, solar and DR resources declined compared to last year and that the RTO “is continuing to rely primarily on fossil fuels and nuclear.” She blamed the “arbitrary” CP rules for creating a “preference” of gas and nuclear over “clean power” and argued that the new seasonal aggregation rules squeeze out many summer-only resources that can’t find winter-only resources to pair with for the auction.

She also criticized PJM for securing too much capacity, saying consumers are paying more than they should pay for reliability.

Predictions

Results largely defied expectations, fueling a recurring complaint among market participants about the market’s volatility.

Earlier this month, ICF analysts Rachel Green, Himanshu Pande and George Katsigiannakis predicted prices would exceed $100/MW-day as the 100% CP requirement offset downward pressure from increased supply and lower demand. They predicted the EMAAC, ComEd and Dayton LDAs would see price separation from the rest of the RTO.

Julien Dumoulin-Smith, an analyst with UBS, predicted in March that the ComEd region would break $200/MW-day, and in April that EMAAC would remain “roughly flat.” He did, however, note changes to transmission accounting that would cause EMAAC to clear separately from the rest of the RTO and cautioned that demand reductions would likely depress clearing prices.

No analysts could be reached Tuesday for comment on the results.