Questions multiplied faster than answers last week following an appellate court ruling that threw out the Federal Energy Regulatory Commission’s jurisdiction over demand response compensation.
Market leader EnerNOC issued a statement May 27 saying that the energy payments that are the subject of Order 745 were responsible for only 2% of the company’s $1 billion of revenue over the last three years.
“EnerNOC’s preliminary estimate of the impact of Friday’s decision suggests that EnerNOC and its customers could be required to refund in a future period as little as $0 and as much as $20 million if Friday’s decision on Order 745 survives any continued appeals process. Order 745 does not pertain to capacity payments which the Company is contractually due or has previously earned.”
FirstEnergy sees it differently. It reacted to the court ruling by filing a complaint (EL14-55) seeking to bar DR from the capacity market.
FirstEnergy’s complaint asked FERC to order the removal of “all portions of the PJM Tariff allowing or requiring PJM to include demand response as suppliers to PJM’s capacity markets.”
The company also asked FERC to bar PJM from releasing the results of the May capacity auction, saying it “must be considered void and legally invalid because the inclusion of demand response in the auction parameters was unlawful.”
EnerNOC said Tuesday that it cleared about 4,000 MW of DR worth more than $185 million. The company’s shares jumped more than 10% on the news but gave back most of that by the end of the week.
EnerNOC said it “would expect state regulators to take a much more active role in facilitating demand response activity. If the decision is broadened to include capacity and ancillary services markets, the Company would expect state programs to expand significantly to preserve the nearly $12 billion of consumer savings that demand response delivered last year in the PJM market.”
Exelon CEO Christopher Crane told an investment conference last week that the ruling could mean DR looks “less like a supply and more like a demand element.”
States taking over DR regulations could result in disparate rules, UBS Securities said. “We see the potential for more generous compensation in jurisdictions encouraging participation, while those that have been opposed, implementing tighter rules. Additionally, under state regulation, it would appear that utilities might ultimately be the entities controlling the bidding-in of DR products.”
At last week’s Markets and Reliability Committee meeting, PJM officials said they were awaiting guidance from FERC.
“For now, it’s business as usual for PJM, for PJM markets,” Assistant General Counsel Jackie Hugee said. “As of today, we still have a Tariff and an Operating Agreement in full force.”
The court’s order won’t take effect until at least mid-July to allow time for motions for rehearing, she said.
Hugee also said the ruling is likely to stand because there are no conflicting rulings in other jurisdictions that might prompt the circuit or Supreme Court to reconsider it. “It’s rare that a circuit court will grant rehearing of one of its orders,” she said.
“Our primary hope is [that] it will not be disruptive this summer,” when PJM typically calls on DR to reduce peak load, Executive Vice President for Operations Mike Kormos said.
Marji Philips of Direct Energy asked whether states might delegate management of DR to PJM, similar to the arrangement that governs the Generation Attribute Tracking System (GATS), which states use in awarding renewable energy credits (RECs).
Kormos said PJM will “reach out to the states” to determine their response to the ruling.
To support its claim for recovery of $9.8 million in “stranded” gas, Duke Energy filed audio recordings and transcripts of its conversations with PJM dispatchers on Jan. 27 and 28. Duke said it included the audio to emphasize “the urgency of the communication and the emergency circumstances it reflected.”
Below is a summary of those conversations, which offer a behind-the-scenes look at PJM operations under extreme stress.
Maximum Generation Alert
PJM Control Room (source: PJM Interconnection, LLC)
At 8:45 a.m. on Jan. 27, PJM issued a Maximum Generation Alert for the following day, signaling that all generation capacity resources should be ready to operate. The RTO estimated peak load of 141,000 MW, leaving it with only 1,000 MW of reserves, a fraction of its 9,450 MW reserve objective. It also issued a voltage reduction alert for the day.
A few minutes after the alerts, Greg Cecil, managing director of generation dispatch and logistics for Duke’s Midwest Commercial Generation unit, called PJM to inform dispatchers that gas might be a “limiting factor” in its ability to run its Lee County, Ill., generators the following day.
Cecil told PJM Master Dispatcher Nathan Marr he might be able to buy gas for the following day. “But if I do that, I’ve got to be able come on, and last time we did this, you guys would not let us come on,” Cecil said. At the time, gas on the pipeline supplying the Lee plant was selling for $37/mmBtu.
99.9% Certain
After first telling Cecil he “cannot anticipate” whether the plant will be needed, Marr continued, “More than likely, your units will be running.” Barring transmission constraints, Marr said, he was “99.9% [certain] you will run.”
“If you can secure gas, we would advise you to secure gas for your units,” Marr continued. “We want all units available for tomorrow.”
Marr reiterated PJM’s need for “all units” in two subsequent calls a few minutes later, at one point telling another Duke employee “if [Cecil’s] not securing gas based on an economic decision — this is not an economic decision. This is a reliability issue, so all units must be available.”
Shortly before the noon offer deadline for the day‐ahead energy market, Duke purchased $12.46 million worth of gas, enough to run five of its eight plants on both Jan. 27 and 28. (Due to the mismatch of the gas and electric days and pipeline restrictions, Duke needed to purchase enough gas for two 24-hour periods in order to cover all hours for Jan. 28.) The five units cleared in the day‐ahead market for hours ending 0800 through 1200 and hours ending 1900 through 2100.
$12 Million of Gas
Shortly after 7 a.m. on Jan. 28, Duke’s Cecil called Marr to ask whether his plant was likely to be dispatched in the real-time market. “What’s going to be the state of Lee today? Cause we’re sitting on $12 million worth of gas … And, I’ve got to do something with it,” he said.
“Right now, I’m not calling any units on,” Marr responded. “The loads are not coming in where we anticipated it.”
Marr then told Cecil there was a chance the plant would be dispatched in the evening. Cecil replied that if he sold gas it would delay the ability of the plant to begin generation.
“That [risk is] part of having a gas unit, I guess,” Marr said. “I mean, I don’t know what to tell you … You’re going to have to do whatever you have to do.”
The morning peak would hit only 133,137 MW — 4,500 MW below forecast. The evening peak, 137,336 MW, was PJM’s fourth highest winter peak on record. But it was almost 3,100 MW below forecast, and interchange provided an unusually large 6,500 MW. Additionally, generating resources performed better than expected with an 11% forced outage rate, half what it had been earlier in the month.
Stakeholders approved a problem statement last week that could make it easier for banks to purchase capacity providers’ revenue streams.
Under current rules, these “auction-specific” transactions cannot be submitted to PJM until after the third incremental auction for a delivery year.
Barry Trayers of Citigroup Energy, who presented the initiative to the Markets and Reliability Committee, would like the rules changed to allow the transactions to be entered into PJM’s eRPM system after the auction that initiated them.
Trayers said the current rules were instituted to ensure that Reliability Pricing Mechanism transactions involved physical capacity. Trayers said the delay is unnecessary because PJM filings with the Federal Energy Regulatory Commission have clarified that all capacity transactions are physical.
He said the performance risk remains with the original capacity seller, but if they should default, the buyer of the auction-specific transaction would be on the hook. Other stakeholders would only be at risk should both entities default.
Trayers initially proposed that the MRC approve the rule change immediately, but stakeholders were hesitant to do so.
Dave Pratzon of GT Power Group said he would vote against the solution because the agenda listed a vote for the problem statement only. “I am unsure of what the implications are,” he said.
The problem statement was approved unanimously. The issue will be considered by the Market Implementation Committee.
PJM said yesterday that the flexibility included in the Environmental Protection Agency’s proposed carbon emission rule is “an encouraging sign.”
PJM and other grid operators have called for a “reliability safety valve,” similar to that in the EPA’s Mercury and Air Toxics rule, which would allow the EPA to relax or delay implementing the standards in a region whose reliability would otherwise be threatened. (See related story, Carbon Rule Falls Unevenly on PJM States.) Grid operators also asked for regional compliance measurement so that states can take advantage of the efficiencies of integrated generation dispatch across multiple states.
Several PJM member companies weighed in with their own reactions yesterday, while their stock prices barely budged:
AEP
“It appears that for some states where we operate, the reduction requirements could be much more than 30% by 2030. Climate change is a global issue, and some states should not bear a disproportionate share of the cost of U.S. action to cut emissions.
“AEP is retiring more than one-fourth of our existing coal-fueled power plant fleet in the next few years. The plants that remain are the most efficient in our fleet and are equipped with more than $10 billion worth of emission controls that were installed to meet other EPA requirements. The investments that our customers made in these plants should not be prematurely lost when ultimately, it will have no impact on growing global greenhouse gas concentrations.”
AEP showed a modest gain, closing at $53.48, up 13 cents, or 0.24%
Calpine
“Calpine supports the EPA’s proposal because we believe it will ensure continued progress toward cleaner energy in a way that supports ongoing grid reliability while allowing market forces to work to deliver the lowest-cost solution for reducing GHG emissions,” said Thad Hill, Chief Executive Officer of Calpine.
Calpine, which has invested heavily in natural gas-fired generation, showed a modest gain, climbing up 15 cents to close at $23.47, up 0.64%.
Exelon
“We have just received the draft rule and are reviewing it and cannot provide any detailed comments at this point,” Exelon spokesman Paul Elsberg said. “However, we are pleased that the draft rule recognizes the critical importance of supporting the continued operation of the nation’s nuclear fleet. We look forward to working with EPA and key stakeholders during the coming months as the rule is finalized.”
Exelon closed at $36.60, down 23 cents, or 0.62%.
FirstEnergy
“Through investments in plant efficiency and multiple plant retirements, FirstEnergy expects a 25% reduction below 2005 levels in CO2 emissions by 2015,” company spokeswoman Stephanie Walton said. “This puts the company on target to meet the Obama Administration’s goal of a 30% percent reduction in greenhouse gas emissions by 2030, if credit is given for plants retired since 2005.
“Following our initial review, FirstEnergy believes it is in a strong position to meet the requirements outlined in the proposed rule, given our expected CO2 reductions in the coming years,” she said. “We are still reviewing how plant retirements will be counted towards the reduction target. As proposed, the rule uses an appropriate baseline year, provides states with reasonable flexibility, and gives an adequate compliance timeline.”
FirstEnergy closed down 27 cents, or 0.80%, closing at $33.55.
NRG Energy
“NRG views achieving significant GHG emission reductions — domestically and globally — as essential for creating sustainable businesses and a sustainable economy,” NRG said in a statement.
“Policies that focus on moderate, near-term emissions reductions, coupled with more aggressive out-year targets, will allow NRG and the rest of the power sector to continue to deploy a wide variety of clean energy solutions.
“Based on our initial reading of the EPA’s proposed GHG rule for existing power plants, we have concerns that EPA’s dramatically varying state emission targets may derail these objectives by adversely impacting electricity reliability and consumers in certain states and introducing excessive uncertainty and legal risk around the important objective of reducing GHG emissions.”
NRG Energy closed at $35.63, down a penny, or 0.03%.
PJM won stakeholder approval of its short-term plan for capturing reserve costs in energy prices after agreeing to a sunset provision that won over load representatives.
The Markets and Reliability Committee initially rejected PJM’s plan by a 49-64 vote, with only a single vote from End Use Customers and none from Electric Distributors.
The committee then approved by an 87-4 margin an alternative proposed by Direct Energy’s David “Scarp” Scarpignato that would sunset the plan on Sept. 30, with PJM filing a proposed long-term solution with the Federal Energy Regulatory Commission Oct. 1. Later in the meeting, the MRC also approved a problem statement on the long-term solution.
Critics repeated those concerns at the MRC meeting Thursday. Scarp said that by putting the cost of reserves into LMPs, which are borne by load only, the proposal violated cost-causation principles. “Generators failing to start, at least today, they pick up some of that” cost, he said.
Ed Tatum of Old Dominion Electric Cooperative agreed. “We feel that we’re rushing into a solution that will have dire unintended consequences,” he said. “All of the sudden load is going to start picking up [the cost of] operational problems.”
Tatum also questioned how such a significant change could be accomplished by only a manual change, rather than a Tariff change that would require FERC approval.
Harry Singh of Goldman Sachs acknowledged that the increase in LMPs is likely to exceed the uplift costs because marginal costs are higher than average costs. But he said the LMP costs can be hedged, unlike uplift.
After the first vote failed, members quickly coalesced around Scarp’s proposal, for which he had been building support for weeks.
The sunset proposal “moves the ball forward,” Executive Vice President of Markets Andy Ott said. “It gives us a chance to evaluate the impact [of the change] during the summer. It’s a workable way forward while still respecting the concerns raised.”
Plan Described
PJM’s short-term plan would increase day-ahead and real-time reserve requirements when Hot- or Cold-Weather Alerts or Max Emergency Generation alerts are issued for the RTO or for either the Mid-Atlantic-Dominion or Mid-Atlantic regions.
The adder for day-ahead reserves would be set at 3% of forecasted load, boosting reserves from 6.27% to 9.27%. The real-time reserve adder would be equal to the default Mid-Atlantic-Dominion synchronized reserve requirement of 1,300 MW.
The increased reserves would be reflected in market clearing engines, ensuring that the costs go into locational marginal prices and not uplift.
Long-Term Solution Sought
The MRC also approved a problem statement and issue charge giving the Energy and Reserve Pricing and Interchange Volatility (ERPIV) stakeholder group authority to develop long-term solutions to the problem, which would likely involve Tariff changes and revisions to PJM software. The expansion of the ERPIV charter passed by acclamation.
Stakeholders last week approved new rules designed to ease the way for public policy transmission projects, but Maryland regulators said the “multi-driver” approach may be irrelevant because of parallel cost allocation rules proposed by PJM Transmission Owners.
The Markets and Reliability Committee Thursday approved Operating Agreement and Tariff revisions that envision two types of multi-driver projects:
The “incremental” method would be used when the multi-driver project was developed as a result of a single driver, such as reliability or market efficiency, but is modified to satisfy one or more other goals and becomes a more cost-effective solution to all of the drivers. Under the TOs’ proposal, the original driver would have its cost allocation reduced by “an amount equal to the ratio of the estimated incremental cost of the new driver(s) to the estimated new total cost of the project multiplied by the estimated cost of the original driver.”
The “proportional” method would be used when the multi-driver project is developed in parallel with individual solutions to different drivers and then combined. The TOs would allocate costs based on the relative costs of the individual projects that would have been required to address each driver alone.
Stakeholders won’t get a vote on the TOs’ proposal, although the TOs are accepting comments on the plan through June 6. The opportunity for opponents to challenge the proposal will come after the TOs make a Section 205 filing seeking Federal Energy Regulatory Commission approval.
“We are one of those who are very concerned with the TOs’ cost allocation” proposal, Walter Hall of the Maryland Public Service Commission told the MRC. Hall said the OA and Tariff changes approved Thursday “may become much ado about nothing” because the TOs’ cost allocation may make public policy projects too expensive to pursue.
John Farber of the Delaware Public Service Commission said that PJM, which will administer the cost allocation process, should use a case-by-case approach for evaluating the relative benefits rather than the “formulaic, rigid approach” envisioned under the TOs’ plan.
Steve Herling, vice president of planning, said Farber’s proposal was unworkable. Cost allocation “has to be formulaic,” Herling said. If the RTO did evaluations project by project, “we’d spend all our time doing cost allocation,” he said.
The states say the rules being drafted by the TOs differ from those outlined by PJM last year.
In a presentation to the Regional Planning Process Task Force (RRPTF) in August, the incremental approach envisioned public policy projects being allocated only the costs added to the proposal to accommodate the public policy needs. For example, if a $250 million project originally designed for reliability and market efficiency grew to $600 million as a result of the public policy needs, public policy would be apportioned only the $350 million additional cost.
Under the current TO proposal, however, the original drivers would receive a credit for some of their costs, with public policy paying more than just its incremental increase.
For example, if a $300 million reliability project expanded to $400 million to accommodate public policy, the public policy would be allocated $175 million — the incremental $100 million plus an additional $75 million based on the ratio of the incremental cost to the total cost. The costs allocated to the reliability portion would be reduced from $300 million to $225 million. (See chart)
Businesses with up to 100 kW in annual peak demand will be exempt from the new 30-minute notice rule for demand response providers under a compliance filing yesterday by PJM.
In approving the new “operational” DR rules last month, the Federal Energy Regulatory Commission ordered PJM to add small commercial customers to the list of those eligible for a “mass market” exemption from the requirement that they respond within 30 minutes of notice (ER14-822). (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)
PJM told the Markets and Reliability Committee Thursday that it planned to file changes to Manual 18 that reserved the exemption to businesses with less than 20 kW of annual peak demand. PJM said 20 kW is the threshold FERC has used to define “small commercial.”
Representatives of the Maryland Public Service Commission and Pepco Holdings Inc. said such a low threshold could cripple current and planned demand response programs for small businesses.
Walter Hall of the Maryland PSC said the 20-kW cut-off would force 30% of commercial customers in his state to drop out of the DR program. Hall said the threshold should be increased to at least 100 kW, adding that the PSC would contest the issue before FERC.
Gloria Godson
Gloria Godson of Pepco said PJM should look to the rate classes set in state tariffs for guidance in setting the threshold. The 20-kW limit “is not going to work,” she told PJM officials. “Your approach is really very constraining.”
GT Power Group’s Dave Pratzon, however, said that “PJM is being entirely appropriate in setting these limitations.
“A 100-kW customer — or a 350-kW customer, as suggested at another meeting — is nothing like a small C&I.”
PJM made no commitments to changing the threshold at the meeting. But in its compliance filing yesterday, the exemption limit was increased to 100 kW.
A change to PJM’s Regional Practices in response to a FERC directive sparked an exchange between Market Monitor Joe Bowring and consultant Roy Shanker.
In April, FERC ruled that PJM’s scheduling rules did not fulfill Order 764, which requires transmission providers to offer scheduling at 15-minute intervals. The order is intended to remove barriers to wind and other variable energy resources. (See FERC Rejects PJM Schedule Rules.)
Roy Shanker
FERC took issue with PJM’s practice of requiring that interchange transactions have a minimum duration of 45 minutes. The commission said the practice was inconsistent with Order 764 because it does not allow a generator to schedule for less than three consecutive 15-minute intervals.
PJM implemented the 45-minute rule in 2008, after MISO officials determined that nearly 60% of intra-hour schedules between MISO and PJM occurred in the final 15 minutes of the hour. PJM said the trading was the result of market participants’ ability to “predict with relative certainty the direction of the price separation between the two RTOs.” PJM said this resulted in interchange spikes of up to 1,000 MW — increasing uplift charges because of the need to balance the generation swings.
With FERC rejecting the restriction, Shanker said PJM and the Market Monitor should clarify the circumstances under which trades made in the last 15 minutes of the hour would be subject to enforcement action. Shanker said failing to create a “safe harbor” for traders would leave them unfairly vulnerable to “subjective judgment.”
“It is not acceptable to put market participants in this position,” Shanker said. “Some profitable transactions in the last quarter of an hour are OK and some are not? Who’s to tell?”
Among Shanker’s clients are Powhatan Energy Fund, which has mounted a public campaign in response to a FERC enforcement action over up-to congestion transactions. Shanker said FERC was incorrect in describing the company’s transactions “wash” trades. (See PJM Trader Calls FERC on Manipulation Probe.)
Executive Vice President for Operations Mike Kormos said PJM was making the rule changes to comply with the FERC order. Whether transactions are referred to FERC “will be Joe’s decision,” Kormos said.
Bowring said he wanted to retain the ability to review such trades for manipulation. “It is possible to game the market while following the rules,” he said.
No Debate
The MRC endorsed the following changes without debate:
Manual 36: System Restoration: Annual update of manual as required by NERC Standards EOP-005-2 (R3) and EOP-006-2 (R3).
Manual 03: Transmission Operations: Updates to special protection schemes, operating procedures, etc.
Manual 28: Operating Agreement Accounting: Changes resulting from the Settlements Formulation Review project — including revisions regarding calculation of regulation lost opportunity cost credits during shoulder hours — and other clean-up items.
Manual 18: PJM Capacity Market: Revisions developed by the Demand Response Subcommittee that would allow a curtailment service provider to add additional MWs as “existing” for offer into RPM auction through an exception process, if the nominated amount on the registration is low because the peak load contribution is low due to a load data anomaly. The current process does not allow for exception for one-time events such as power outages or major equipment failure.
Manual 33: Administrative Services for the PJM Interconnection Operating Agreement: Sets forth rules for communicating with electric distribution companies and reallocating load reallocation due to defaults by load serving entities. (See PJM Considers New Rules on Defaults.)
Exelon shareholders shed no tears last week over the news that five of the company’s nuclear units failed to clear PJM’s base residual auction.
In fact, analysts say the company will earn almost $150 million more in capacity revenue from planning year 2017/18 than it would have if all of the company’s capacity had cleared: The additional supply would have reduced the clearing prices.
Exelon confirmed that its Oyster Creek plant in New Jersey, as well as Byron Units 1 and 2 and Quad Cities Units 1 and 2 in Illinois, failed to clear the auction. Other plants that may not have cleared include two NRG coal-fired plants in Maryland, Chalk Point and Dickerson. (See related story, Capacity Results: Who’s in, Who’s Out?)
Prices cleared at $120/MW-day for most of PJM, doubling the RTO-wide clearing price of $59 for planning year 2016/17. Other owners of generation within PJM also benefited from the higher capacity prices, as total capacity revenues will increase from about $3.6 billion in 2016/17 to $7.3 billion in 2017/18.
Investors responded by bidding up shares of Exelon, FirstEnergy, PPL and NRG Energy by more than 5% last week, with Exelon leading the pack with a gain of 7.85%.
Meanwhile, the failure of Exelon’s nuclear plants to clear allows the company to continue making its case for changes to the capacity market rules that would benefit nuclear plants. FERC and PJM officials have indicated support for a “firm-fuel premium” or “clean” energy portfolio standards to ensure nuclear plants’ continued operation.
As the nation’s largest nuclear operator, Exelon is arguably better positioned than any company to capitalize on the carbon emission rules proposed yesterday by the EPA. The new rules seek to reduce U.S. greenhouse gas emissions by 30% from 2005 levels by 2030 — a target that would be much more difficult, if not impossible, to meet if the U.S. loses a substantial portion of its nuclear fleet, the largest carbon-free source of baseload capacity. (See related story, Carbon Rule Falls Unevenly on PJM States.)
“You can’t maintain the current emission level unless you keep the nuclear units viable today. And you surely can’t reduce if you start taking them off,” Exelon CEO Chris Crane told the Sanford C. Bernstein Strategic Decisions Conference last week. “So we think we’re uniquely positioned to be able to … work through a state-level design that will compensate the assets adequately” for their contributions to fuel-secure capacity and carbon reductions, Crane said.
A Good Quarter
Exelon shareholders have had a rough few years.
The company cut its dividend by 41% last year as its share price, which peaked at $90 in 2008, fell below $30.
But things have brightened considerably since January, when energy prices and demand spiked during the frigid winter. The company reported first-quarter earnings of $90 million, versus a loss of $4 million for the same period last year. Revenue rose to $7.24 billion, from $6.08 billion. Electric futures prices at PJM-West Hub are up by about 25% since November.
In addition, fuel supply problems that hampered production from coal- and gas-fired generators have PJM and Federal Energy Regulatory Commission officials talking about the possibility of adding a “fuel security” premium to the capacity market that would benefit nuclear generators.
FERC officials last week also talked about states supporting nuclear plants through “clean” energy portfolio standards similar to those that have supported renewable power. (See related story, ‘Clean’ Energy Portfolios Could Save Nukes, FERC tells NRC)
Hitting the Sweet Spot
As for the capacity auction, Exelon couldn’t have played its hand any better, said analysts from UBS Securities.
UBS said Exelon’s ideal strategy was to “withhold” 4,457 MW of its 25,000 MW PJM fleet — almost exactly the 4,225 MW of capacity that failed to clear. UBS Securities calculated that Exelon will earn $148 million more in capacity revenues in 2017 than it would have earned had all of its capacity cleared.
Eliminating 4,457 MW reduces daily revenue by $267,000 but increases clearing prices by $33/MW-day, UBS said. With the higher clearing price, the remaining 20,543 MW fleet earns $148 million more in revenue than had the entire portfolio cleared at the lower price. (See graphic.)
Utility rate analyst Paul Chernick agreed with UBS’ math. “If you had another 4,000 MW in there at the prices they must have bid in, it would have almost certainly pushed it below the $70 level,” said Chernick, president of Resource Insight Inc., a Massachusetts consulting firm whose clients include the Maryland Office of People’s Counsel.
UBS said Exelon’s “maximum benefit can be obtained by withholding just enough supply to drive prices received for the remaining fleet up without eliminating too much revenue and reducing the overall benefit.
“Given that only a relatively small portion of the fleet is required to be withheld for maximum benefit, we would conclude that [Exelon], at any rate, has more than adequate market power to drive auction results through an aggressive bidding strategy,” UBS said.
UBS analysts calculated the revenue gains from “hypothetical withholding scenarios,” hastening to add “we do not intend to imply that this behavior took place as described.”
Indeed, refusing to bid the plants into the auction would violate PJM rules and likely federal antitrust law. But with new PJM rules limiting imports and demand response, and with economics and the EPA’s Mercury and Air Toxics Rules forcing as much as 14 GW of PJM coal capacity into retirement, Exelon felt confident in offering its nuclear plants at maximum price it was allowed — the Avoided Cost Rate less net energy revenue.
Bowring: No Rules Broken
Market Monitor Joe Bowring said in an interview Friday that all generation offers were screened by his staff and PJM to ensure market power was mitigated by offer caps. That included a determination that no generator with market power could offer at a price higher than ACR less net energy revenue. “We do not believe market power was exercised in the capacity market,” Bowring said.
UBS noted that “the outcome is highly dependent on the initial assumption for where the auction would have come out at without any withholding. Lower baseline assumptions generally incentivize more withholding since less revenue is removed by the withheld assets (less risk in the strategy) while overall net uplift increases as well.”
“While outright strategic collusion is prohibited, participants may have been `telegraphing’ their intentions to each other more subtly in public comments from more than one company regarding potential retirements, seeking higher Avoided Cost Rates (ACR), etc.,” UBS said.
Chernick said that with imports and demand response limited by new rules in the 2017 auction, there was little risk to Exelon’s bidding strategy. “I think you could get a pretty good sense that this change in supply was enough to drive the price up,” he said. “It wasn’t like you could get huge amounts of [supply] zooming in.”
Crane seemed to confirm the analysts’ conclusions in his remarks at the Strategic Decisions conference last week, saying that although five units failed to clear, “overall the clearing price was beneficial to the total fleet.”
In its presentation to the conference, Exelon said its PJM capacity revenues will increase by $150 million in 2017 versus 2016. The company also expects a $250 million increase in 2017 capacity revenues from the New England capacity auction, held in February.
Crane said generators exhibited more “discipline” in their bidding this year.
“In the last auction, over two-thirds if not about three-quarters of the participants in the auction took themselves in as a price taker, which means they bid zero [and] not their full Avoided Cost Rate,” he said. “… The way that the RTO cleared, there is much more discipline in bidding, where people did bid their full ACR as we did on our plants.”
Retirement Threat
Crane said the failure of the Illinois nuclear plants to clear “gives us an opportunity to work with the state and work with the RTO on the value that they provide not only as a firm fuel during any weather event, but also provide a clean energy source that, if taken away, would be very difficult to meet the new [greenhouse gas] mandates.”
Earlier this year, Exelon warned Illinois legislators that low energy prices and renewable energy subsidies could force them to shut down three nuclear plants in the state. Exelon lobbyists reportedly named the Quad Cities and Byron plants in addition to the Clinton plant in southern Illinois (part of MISO) as those most at risk. (See Exelon in Lobbying Push to Save Ill. Nukes.)
Oyster Creek is scheduled to retire in 2019 under an environmental settlement with New Jersey officials. Exelon spokesman Paul Adams said that plan is unchanged.
Exelon said it has agreed not to make any retirement decisions about its Illinois plants before June 2015. The Illinois House introduced a resolution (HR1146) that calls for changes to recognize nuclear power’s reliability and environmental benefits. The resolution urges FERC, PJM and MISO to “expeditiously adopt market rules and policies, including transmission expansion rules and policies, that will ensure the continued operation” of the nuclear fleet. It also urges the EPA to make nuclear power a central part of compliance with the greenhouse gas rules.
GHG Rules to Benefit Nukes
Crane predicted last week that Illinois will seek a clean energy standard that would provide nuclear plants clean energy credits it can sell, similar to renewable energy credits (RECs).
A second path to compliance is the cap-and-trade approach used by California and the nine-state Regional Greenhouse Gas Initiative, which includes Maryland and Delaware.
Exelon made no secret last week that its Oyster Creek, Bryon and Quad Cities nuclear plants failed to clear the base residual auction.
Other generators — representing almost two-thirds of the 11,500 MW of generation capacity that failed to clear — were less forthcoming.
Dickerson Plant (Source: EPA)
UBS Securities analysts believe that at least some of the units at two NRG coal-fired plants in Maryland, Chalk Point and Dickerson, also failed to clear. UBS said it believes some of the 750 MW of uncleared capacity in the ComEd Zone may have been part of NRG’s Midwest Generation fleet.
An NRG spokesman, citing competitive reasons, declined to comment on the auction results.
A proposed 859-MW combined-cycle plant planned by Panda Power in Brandywine, Md., also may have failed to clear, according to UBS, which cited “air permit issues.” A Panda Power spokesman Friday declined to comment on the auction results but said the planned plant is still going forward.
Last year, FirstEnergy announced it would deactivate Hatfield’s Ferry and Mitchell plants in southwestern Pennsylvania after both plants failed to clear the auction. While a company spokesman wouldn’t say whether it bid those plants in this year’s auction, he said the decision to retire those plants stands.
New Generation
Rendering of the Oregon, Ohio Power Plant (Source: North American Project Development LLC)
PJM said it cleared 5,927 MW of new generation, the most ever. About 4,800 MW is combined-cycle generation clearing for the first time, all of it east of the west-to-east transmission constraints or in zones short of capacity.
Among this new combined-cycle generation is believed to be an 800-MW plant planned in the ATSI zone in Oregon, Ohio. The plant is being developed by North America Project Development LLC with funding from Energy Investors Funds, a private equity firm.
UBS said it believes Old Dominion Electric Cooperative’s 800-MW Wildcat expansion and PSEG’s Linden advanced gas path (AGP) uprate also cleared.
Reactivations
In addition, PJM cleared about 1,100 MW of generation that was slated for retirement but will be reactivated after switching from coal to another fuel.
NRG spokesman David Gaier said the company has several repowering projects underway or in the planning stages.
The company’s 732-MW Avon Lake, Ohio, plant and 325-MW New Castle plant in West Pittsburg, Pa., are in the process of being switched from coal to natural gas.
Its 158-MW, coal-fired Portland, Pa., plant ceased operations last week, but the company announced it will switch that unit to low-sulfur diesel, a project expected to be completed in June 2016.
Gaier said NRG is also considering converting its 597-MW Shawville, Pa., coal-fired plant to natural gas.
FirstEnergy spokesperson Stephanie Walton said the company doesn’t have any current plans to repower any of its coal-fired plants.
Stakeholders gave final approval to a revised Zonal Base Load definition last week that will ensure that zones don’t lose Auction Revenue Rights due to “extraordinary circumstances” that suppress their base load calculations.
The vote by the Markets and Reliability Committee was prompted by Superstorm Sandy in 2012. Storm-related outages produced base loads in the AE, JCPL, PSEG and RECO zones that were far lower than would have been expected under normal conditions. (See Superstorm Sandy Stirs Change to Zonal Base Load Definition).
PJM obtained a waiver from the Federal Energy Regulatory Commission in February to prevent the zones from losing a portion of their Stage 1A ARR allocations as a result of the muted ZBLs.
