Duke Energy has reached an agreement with the EPA about the cleanup of its massive coal ash spill on the Dan River. The agreement formalizes the cleanup activities already underway after February’s spill of an estimated 39,000 tons of ash and includes ongoing monitoring and post-cleanup assessment. It also provides penalties of up to $8,000 per day if the company doesn’t follow the conditions. Duke agreed to pay the EPA’s costs for responding to the spill, estimated at $1 million so far. The agreement is filed under the federal Superfund hazardous sites law.
Duke Energy contractors and engineers survey the site of the coal ash spill on the Dan River in North Carolina.
Duke is also facing a stockholder suit over its potential liability for spills at its other coal ash depositories. The complaint by shareholders Edward Tansey and the Police Retirement System of St. Louis alleges management exposed the company to billions in liability over its coal ash storage methods.
The suit was filed in the Court of Chancery in Delaware, where Duke is incorporated. It claims that Duke officials were aware of the risk of coal ash contamination from its stock piles and settling ponds. It seeks to force the company to eliminate ash contamination, as well as unspecified damages and changes in how Duke handles the waste.
Meanwhile, a North Carolina House bill filed last week aims to force Duke to clean up its most dangerous coals ash ponds within the next five years. House Bill 1226, introduced by Democratic lawmakers, includes a long list of coal ash regulations, including a moratorium on accepting more coal ash starting this summer.
Most notable about the bill is a provision denying the company the ability to recover remediation costs from customers. In addition to stopping new coal ash deliveries, the bill calls for all coal ash storage ponds to be closed by 2029 and the most dangerous coal ash ponds cleaned up by 2019.
American Electric Power Company is reportedly pondering the sale of its Midwestern power plants, becoming the second large generation owner, after Duke, to exit the Midwest regional generating business.
CEO Nick Atkins told Bloomberg that because of the paucity of long-term power purchasers, which bring certainty to merchant plants, the company could decide to concentrate almost exclusively on its regulated businesses, with their guaranteed rates of return.
Duke is seeking to sell 13 plants that produce 6,600 MW. AEP owns more than 10,000 MW of generation, valued at about $3 billion. The company said a final decision on whether to sell should come by the end of the year.
Exelon’s aging Oyster Creek nuclear power station last Wednesday reported a leak of chlorine used to control algae near the plant’s water intakes, but the plant remained at full power, authorities said. The “unusual event” was declared at 10:30 a.m. and ended an hour later, according to Nuclear Regulatory Commission spokesman Neil Sheehan. No one was hurt. Oyster Creek is scheduled to be retired in 2019.
Susquehanna 1 Refueling Done
But Turbine Work Needed
PPL’s Susquehanna Unit 1 will remain offline indefinitely while the company investigates the cause of turbine issues the unit experienced a year ago. The refueling and scheduled maintenance outage work on the 1,260-MW Unit 1 was done last week, but the plant on the Susquehanna River will stay cold while engineers inspect the low-pressure steam turbine. The company did not say when it would return to service.
Unit 1’s turbines have been inspected five times since 2011. Unit 2’s turbines have been inspected at least six times, most recently in March. Unit 2 remains operating at full power, according to the NRC.
PJM told the Federal Energy Regulatory Commission last week it should allow a Duke Energy peaking plant to recover $9.8 million it spent on expensive natural gas it was unable to burn in January.
Responding to a complaint filed by Duke May 2 (EL14-45), PJM disagreed with Duke’s legal analysis and some aspects of its claim. But it said not paying Duke under the circumstances would be an “[in]equitable result” for generation owners.
The Market Monitor and others argued against Duke’s claim, saying capacity resources such as Duke need to be responsible for their fuel-cost risk.
What’s at Stake
If FERC rules in Duke’s favor, PJM’s tab could total tens of millions. In a filing supporting Duke’s claim, NextEra Energy Resources said it will make a similar claim to recoup $1.3 million in gas costs. Mike Bryson, executive director of system operations, told RTO Insider last week that about 10 companies have informed PJM that they also suffered “stranded gas” losses.
On Thursday, the Markets and Reliability Committee approved a problem statement to improve PJM’s procedure for committing gas-fired units. The initiative was broadened at stakeholders’ suggestions to cover several additional issues, including the definition of an outage and handling of dual-fuel units. “We’d like to get [solutions] before the winter so we don’t have a replay of the confusion” of January, said Mike Kormos, executive vice president for operations.
Duke’s Claim
Duke’s claim resulted from the late January cold snap. On Jan. 27, PJM issued a Maximum Generation Alert for the following day, signaling that all generation capacity resources should be ready to operate. (See related story, Recordings Capture Tense Operations During January Cold.)
Duke Lee Energy Facility (Source: Bill Spindler, SouthPoleStation.com)
As a result, Duke purchased $12.5 million worth of gas, enough to run five of the eight 80-MW units at its Lee County, Ill., facility for 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.)
Duke said it was able to recoup $2.6 million by self-scheduling several of the Lee units on Jan. 27 and 28, selling unused gas and receiving “very limited make-whole payments and credits” from PJM, leaving it with a loss of about $9.8 million.
Duke asked PJM to indemnify it under section 10.3 of the PJM Tariff, which requires that a generation owner be held “harmless” for “obligations … to third parties, arising out of … a Generation Owner’s (acting in good faith to implement or comply with the directives of the Transmission Provider) performance of its obligations.”
As an alternative, Duke seeks “a one-time, Duke-specific waiver” of Operating Agreement and Tariff provisions that bar make-whole payments.
PJM: No Order
In its filing last week, PJM insisted that its conversations with Duke did not constitute a directive to buy gas.
“It is a common occurrence that PJM dispatchers indicate that units need to be available to run only to later find that due to changes in load conditions, PJM does not need to commit the particular unit,” PJM said. “Although clearly done under more stressful conditions here, dispatchers are called on a routine basis and asked to prognosticate on whether units might be picked up and run in real time. Dispatchers answer those questions based on the best information they have available but are not providing guaranties through their answer.”
PJM also disagreed with Duke’s request for indemnification under the Tariff.
“Any extension of Section 10.3 to cover the type of loss Duke incurred under the circumstances at issue would read the indemnification provision into a blanket insurance policy for losses of whatever sort, caused by accident, act of God or plain misfortune that a Market Seller may incur in responding to PJM dispatch,” PJM said.
Commission approval of Duke’s request, PJM said, “would open the floodgates for a host of meritless claims that would present an existential threat to PJM and every independent system operator and regional transmission organization.”
PJM said capacity resources such as Lee must be offered into PJM’s markets on a daily basis and “do not have an automatic right to recover all of its costs should the units not actually be dispatched.”
Nevertheless, it said Duke should be compensated under a waiver because of the “extraordinary” circumstances of January. “Gas balancing losses that are usually no more than a routine `cost of doing business’ were in some cases transformed, in large part due to the conditions of the gas market and large price fluctuations, into multi-million dollar losses,” PJM said.
Monitor: Don’t Pay
In its own filing last week, the Market Monitor called on FERC to reject Duke’s request, saying it would be “a dramatic change in market rules and an associated, inappropriate shift in the costs and risks of the market to customers.”
The Monitor said Duke chose to rely solely on interruptible gas pipeline service and did not invest in back up fuel capability. “It is inappropriate for Duke to ask PJM customers to hold it harmless from such decisions, from which Duke has benefitted. It is also unfair to Duke’s competitors, who may have made different choices about fuel supply.”
The Monitor also said more than half of Duke’s claimed losses resulted from its delay in purchasing gas, which rose from $37/mmBtu to $63/mmBtu in the hours before Duke decided to purchase.
Retailers and the PJM Industrial Customer Coalition were also unsympathetic. The “waiver would harm the market, principles of market certainty and market participants … who may be forced to pay even more for Balancing Operating Reserve costs,” said the Retail Energy Supply Association.
Several generators, the PJM Power Providers Group and the Electric Power Supply Association filed comments siding with Duke.
“Denying Duke’s complaint despite Duke’s good faith efforts to comply with the PJM directive would be unjust and unreasonable,” FirstEnergy said. “System dispatchers need to have confidence that resources will perform when instructed to do so. And market participants must have confidence that, when directed by system operators to act for the sake of reliability, they will be made whole for the costs to carry out dispatcher’s instructions.”
NextEra Energy Resources also supported Duke, saying it also suffered losses in late January. NextEra said PJM “committed” a 290-MW generator in Sayreville, N.J., that NextEra co-owns with GDF Suez before the Jan. 27 operating day. PJM cancelled its dispatch, leaving the plant with a $1.3 million loss for unburned gas.
NextEra’s filing included a transcript of its exchange with PJM, in which one PJM dispatcher assured the company it would be reimbursed for its gas purchases: “I understand that you guys have already purchased the gas, ah, that’s not an issue, as far as if you’re worried about being reimbursed for that … PJM will obviously take care of that.”
Concept design of planned data center (Source: University of Delaware)
A plan to construct a 279-MW natural gas-fired plant for a developing data center on the grounds of a shuttered car factory is being challenged in the state’s Superior Court. The plant was described as being crucial to provide reliable power for the University of Delaware’s new state-of-the-art data center. But opponents are arguing that the site’s zoning doesn’t allow for such a power plant, and another challenge said the air emissions studies are flawed.
With a major approval from the Federal Energy Regulatory Commission in its pocket, Dominion Resources passed another test when it received conditional approval for a 130-MW generating plant crucial to the operations of a proposed liquefied natural gas export terminal on the Chesapeake Bay. The Maryland Public Service Commission authorized the plant but imposed nearly 180 conditions, including air and water quality monitoring, forest conservation, low-income energy assistance and $40 million for community programs and state renewable energy programs.
More than 50 Maryland legislators signed a letter calling on the state Department of the Environment to finalize regulations on smog and fine particle pollution from power plants.
Twelve counties regularly fail federal air quality standards for smog. The state is mandated to set limits on air pollution from coal-fired power plants and other emitters and to require that they use the best available emission control technology. “Coal plants in Maryland are the largest individual sources of air pollution and in many cases lack modern pollution-cutting technology,” read the letter, which was addressed to Gov. Martin O’Malley. “We urge you now to follow through on your commitment to public health and direct [the department] to expeditiously finalize — not delay or weaken — the proposed regulations that will protect our children.”
Ashville-based Innovative Solar Systems says it wants to start constructing large-scale solar farms in the state. North Carolina ranks fourth among states in installed solar capacity, but most of its projects are 5 MW or smaller.
Innovative Solar Systems is proposing 12 solar farms of between 25 and 80 MW, most of them in the eastern section of the state. The projects are still in the planning stage and will need large tracts of farmland, interconnection agreements and purchase power agreements. Taken in whole, Innovative’s planned projects will produce about 620 MW.
North Carolina provides a bullish solar energy climate, with green-energy mandates and tax credits.
Robert Powelson, chairman of the state Public Utility Commission, resigned from an energy-lobbying group last week over conflict-of-interest allegations.
A dispute over Powelson’s unpaid role as a member of the Greater Philadelphia Energy Action Team arose as the PUC was being asked to rule on Sunoco Logistics’ request to expand a natural gas pumping station in Chester County. The chairman of the advocacy group is Phil Rinaldi, CEO of Philadelphia Energy Solutions LLC, which lists Sunoco Inc. as a minority partner.
The Energy Action Team has acted as a booster for energy projects and expansion projects, including some regulated by the PUC. State law does not forbid commission members from unpaid positions with advocacy groups. Powelson’s resignation letter said he had minimal interaction with the Energy Action Team.
The Public Utility Commission said PECO’s restoration work in the wake of a winter ice storm was up to standards but said the company needs to improve communications with customers during such events.
Adding to customer frustration over power outages were erroneous messages from the company indicating that power had been restored when it had not. “Many of the phone calls that we got … [were] that people were frustrated by the lack of information, or the inaccurate information, they were getting from the utilities, including PECO,” said PUC Spokeswoman Jennifer Kocher. The company has until September to respond to the report.
FirstEnergy wants to amend its recent rate hike increase request to cover the cost of complying with a Public Service Commission mandate to read its customers’ electric meters monthly. In April, it asked for a 13.95% increase for its Monongahela Power and Potomac Edison subsidiaries.
The PSC ordered the monthly readings to begin in July 2015. FirstEnergy hasn’t said how much more it is seeking to comply with the order but previously estimated the cost at $15 million.
While the commission has indicated it believes it reasonable for FirstEnergy to cover the costs with rate hikes, critics are not so sure. “FirstEnergy created the problems that customers were having with their bills, denied for months that there were any problems and blamed everyone but itself for the impact on customers,” said Keryn Newman of the Coalition for Reliable Power. “Yet the PSC says it’s ‘punitive’ for the company to pay the cost of getting its billing right. That makes no sense.”
Rule changes since last year’s auction resulted in reductions in cleared generation imports and demand response. The mix of DR that cleared also changed, with more annual resources and less summer-only.
Capacity Import Limits
In last year’s auction, generation imports nearly doubled, leading some to question their deliverability. (See FERC Clears Capacity Import Limits.)
FERC also approved several rule changes intended to make demand response a more flexible resource.
Clearing of Limited DR
Perhaps the most controversial change was one that reduced the volume of limited demand response that could clear in the auction (ER14-504). The new rules cap the amount of limited and extended summer DR at 10% of PJM’s reliability requirement, with limited DR providing no more than 4%.
The PJM Board of Managers proposed the changes to FERC in March despite a lack of stakeholder consensus. PJM told FERC the volume of limited DR clearing in the capacity market had to be reduced because the then-current rules resulted in a vertical demand curve that threatens reliability. (See FERC OKs Limits on DR in Capacity Auction.)
DR as an ‘Operational Resource’
FERC also approved most of PJM’s proposal for making demand response an “operational resource.” The order (ER14-822) allows operators to dispatch DR before emergencies, reduces default notice times to 30 minutes from as long as two hours and reduces minimum run times to one hour from two. However, the commission ordered PJM to allow small commercial customers to be eligible for a “mass market” exemption from the 30-minute notice along with residential ratepayers. The commission also rejected a proposal requiring DR providers to respond to sub-zonal dispatch. (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)
DR Sell Offer Plans
DR providers must also provide more assurances that they will be able to deliver the demand reductions promised in their offers under an order approved in February (ER13-2108).
PJM had filed manual changes before the 2013 auction requiring DR providers offering into the capacity market to submit a “Sell Offer Plan” that included a template with certain information and a certification from an officer of the provider. It also required DR providers to submit details on their end-use customers in areas where PJM suspected double counting.
The commission ruled on the eve of the 2013 auction that the new requirements significantly affected rates, terms and conditions of service, and thus required changes to the Tariff.
PJM filed the required Tariff changes last August. It said it was concerned that some of the increasing volumes of DR offered and cleared in the capacity auctions represented overly optimistic projections or double counting of the same resources. It also suspected that some DR providers were offering resources in the base residual auction assuming they could buy out of their commitments in the bilateral market or incremental auctions.
Some observers believe that although the requirements were not in effect for the 2013 auction, the expectation that they would be resulted in the decline in DR offers in last year’s base auction.
Auction Speculation Fix Rejected
PJM was unsuccessful in its attempt to eliminate financial speculation in the auction.
Because clearing prices in IAs are usually lower than those in the BRA, participants can profit by selling capacity in the BRA and buying out their commitments in the IAs. PJM and the Market Monitor say such buyouts are suppressing capacity prices and could undermine system reliability.
PJM’s solution would have reduced the number of IAs (currently three) and set conditions eliminating the potential to arbitrage between the BRA and IAs. PJM unilaterally proposed the changes in March after the Markets and Reliability Committee failed for a second time to reach consensus on a fix.
On May 9, FERC rejected PJM’s proposal (ER14-1461), saying it would increase risks for capacity sellers, create undue barriers to entry and increase costs to load through the acquisition of excess capacity. The commission was also unpersuaded by PJM’s evidence of speculative sell offers.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
2. PJM Manuals (9:10-9:30) — The committee will be asked to endorse the following manual changes:
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.)
PJM Regional Practices:Removes a requirement that all interchange transactions be at least 45 minutes long to comply with an April 17 FERC ruling. FERC ruled PJM’s 45-minute rule did not comply with Order 764, which required 15-minute energy scheduling intervals with 20-minute notifications. The order, issued in 2012, is intended to remove barriers to variable generation sources such as wind. PJM removed the 45-minute restriction from the EES application and from the Regional Practices document effective May 19. The MRC will be asked to endorse these revisions at first reading, due to the implementation date required in the FERC order. (See FERC Rejects PJM Schedule Rules.)
3. Regionial Planning Process Senior Task Force (RPPTF) (9:30-10:00)
The committee will be asked to approve Operating Agreement and Tariff revisions related to “multi-driver” transmission projects under an approach developed by the RPPTF. Members of the task force expressed overwhelming support for the changes in a poll in March. But a parallel initiative by the Transmission Owners Agreement Administrative Committee (TOs) to incorporate multi-driver projects in Schedule 12 of the Tariff has caused unease among some state regulators. On May 22, the TOs issued a notice that they had revised their proposed changes based on feedback from members. (See Conflict Ahead for States, TOs over ‘Multi-Driver’?)
4. Frequently Mitigated Units (FMU) (10:00-10:20)
The committee will vote on proposed rule changes to reduce “adder” payments to frequently mitigated generation units (FMUs). Three generator-backed proposals won at least 60% support from the Market Implementation Committee on May 7 and are eligible to be considered by the MRC. The MIC rejected a joint proposal from PJM and the Market Monitor. (See Members Reject PJM-IMM Plan on FMUs.)
5. Energy and Reserves Pricing and Interchange Volatility (ERPIV) (10:20-10:50)
Members will vote on PJM’s plan for cutting uplift and capturing reserve costs in energy prices. The proposal was developed during special sessions of the MIC. (See PJM Reserve Proposal OK’d Despite Misgivings.)
6. Auction Specific Transactions in RPM (10:50-11:05)
The committee will consider a problem statement and issue charge proposed by Barry Trayers of Citigroup Energy Inc. to consider changing rules that are making it difficult for banks to purchase capacity providers’ revenue streams. (See Bankers: Change Timing on Capacity Revenue Reassignments.)
7. Revisions to definition of Zonal Base Load (OA 1.3.39) (11:05-11:20)
The committee will be asked to approve a problem statement and issue charge presented by Executive Vice President for Markets Andy Ott on first reading. The initiative will attempt to address the underfunding of Financial Transmission Rights. (See FTR Holders Seek Shortfall Fix.)
The 2017/2018 base residual auction exceeded expectations of analysts and generation company executives, with annual resources clearing at $120/MW-day in most of PJM following rule changes that limited demand response and generation imports.
Click chart(s) to zoom.
Prices in Virginia, West Virginia, North Carolina and much of Ohio doubled from $59/MW-day in last year’s BRA. The east was essentially flat, with the PSEG zone falling to $215/MW-day and MAAC up by less than $1. ATSI rose 5%.
Unlike last year’s auction, which saw the PSEG, ATSI and MAAC zones separate from the rest of the RTO, only the PSEG zone cleared separately. The auction procured 167,004 MW for the delivery year beginning June 1, 2017, giving the RTO a 19.7% reserve margin.
Six new combined-cycle plants cleared for the first time, all of them located east of the west-to-east transmission constraints or in other areas with capacity needs. In total, more than 5,900 MW of new entry cleared.
Reasons for Increase
In a press conference late Friday, Executive Vice President for Markets Andy Ott said the increase in clearing prices resulted from the costs of compliance with state environmental regulations and new limits on generation imports and summer-only demand response. (See related story, Major Rule Changes Reduced Imports, DR)
“I think the changes that we have made … certainly had their intended effect,” Ott said. “Anytime you have an auction with competitive new entry with this kind of volume, we look at that as a success story.”
Demand Response Changes
About 11,000 MW of demand response cleared, a drop of 1,433 MW from last year’s auction. Annual DR increased by 1,400 MW and extended summer by almost 4,700 MW, while limited summer-only resources dropped by more than 7,500 MW. Limited DR cleared between $14 and $80 lower than annual resources, which include generation, annual demand response and energy efficiency.
Ott touted the “dramatic shift” in DR. “All in all we saw it as a positive result that we got higher value DR,” he said.
Imports dropped to about 4,500 MW, down from 7,500 last year. Unlike last year, all of the imports came with firm transmission. All but about 500 MW cleared after winning exemptions from the import limits, which required them to also be pseudo-tied.
Exceeding Expectations
In first-quarter earnings calls before the auction, executives of PJM companies said they didn’t expect a dramatic rise in prices following the rule changes.
FirstEnergy officials said they were encouraged by PJM’s “modest reforms” but sought additional changes such as a premium for having fuel on-site, which could boost nuclear and coal plants. PPL CEO William Spence said there were too many variables to make any prediction on prices.
AEP CEO Nick Akins said he expected RTO prices of $80 to $100, while UBS Securities predicted RTO prices of $80 with MAAC flat at $120. Barclays Capital analyst Dan Ford accurately predicted that only PSEG would separate from the RTO, but his $100/MW-day target for MAAC and the RTO was also low. His PSEG target was slightly high at $229.
Below is a detailed analysis of the auction results.
Prices
Clearing prices remained volatile, with prices doubling in much of the RTO. For the first time in seven years, the RTO and all of the MAAC zones cleared at the same price.
Increased supply from new generation and uprates was offset by the drop in imports and demand response, PJM said.
Although RTO prices rebounded from last year, they were still below the $136/MW-day for 2015/16 and the all-time high of $174, set in planning year 2010/11.
Capacity Offered & Cleared
The nearly 179,000 MW of unforced capacity offered was down 3% from the total offered a year ago. An additional 21,300 MW was eligible but did not offer because it was exported, included in Fixed Resource Requirement capacity or excused due to environmental restrictions or pending retirement.
Generation was responsible for 93% of the cleared capacity, with DR providing 6% and energy efficiency 1%.
Almost 7,150 MW of “incrementally new” capacity was offered this year, including new generation, capacity upgrades to existing generation and energy efficiency. Generation capacity deratings and a reduction in DR offers exceeded the new capacity, however, resulting in a net decrease of almost 5,700 MW of installed capacity.
The cleared capacity for 2017/18 includes 5,185 MW of generation that postponed or cancelled retirement and 1,224 MW of reactivations.
Demand Response & Energy Efficiency
Demand response offered dropped 22% and cleared DR declined 12%, the second year in a row of declines. In all, DR offers have declined by 43%, and cleared DR by 26%, since peaking for delivery year 2015/16.
The biggest declines in cleared DR this year came in ATSI (-792 MW), PSEG North (-242), BGE (-145) and DEOK (-112). APS (+244) and COMED (+242) showed the biggest increases with AEP also up (+49).
Energy efficiency offered has increased by 43% over the two years, albeit from a much lower base.
About 97% of the demand resources and virtually all of the EE offered cleared.
The new limits on the volume of summer-only (limited) DR and extended summer DR that was permitted to clear changed the mix of DR clearing and resulted in price separation among the products. The volume of limited DR clearing dropped by three quarters, while extended and annual grew dramatically. Extended summer now represents nearly two-thirds of all capacity DR, up from 20% in 2016/17.
Annual DR cleared at the same price as generation, $120 in all but PSEG ($215). Extended summer DR also cleared with the annual products except in the PPL locational deliverability area, where it priced at $53.98/MW-day. Limited DR cleared at $40 in PPL, $201 in PSEG and $106 in the rest of the RTO.
New Generation
The auction received offers from almost 6,600 MW of what PJM terms “new” generation capacity, including new facilities, uprates at existing facilities and reactivations of plants scheduled for retirement that will be switching fuels.
Of the generation that was offered into the auction, 95% cleared.
The auction cleared 6,267 MW of new generation, the highest ever. Of that, 340 MW was in uprates to existing generation. The remaining 5,927 MW of new generating units included about 4,800 MW of gas-fired combined-cycle plants clearing for the first time. All of the new generation is located east of west-to-east transmission constraints or in LDAs that needed capacity.
Wind offers dropped 8% to 804 MW while solar increased 30% to 116 MW. All of the offers cleared.
The new generation helped prices in MAAC converge with the rest of RTO, PJM said.
Imports
Cleared generation imports dropped by nearly 3,000 MW to 4,526 MW, a reduction of almost 40% from last year.
Of the 4,526 MW, nearly 4,000 MW met the requirements for an exception from the capacity import limit (CIL).
The majority of the imports came from west of the RTO. PJM will export 1,223 MW of capacity. Before it began the capacity auctions, PJM was a net exporter of capacity.
The zones and their caps are:
North (New York ISO & ISO New England): 1,598 MW (Light green on the map).
West 1 (MISO East, MISO West & Ohio Valley Electric Corp.): 2,301 MW (orange).
West 2 (MISO Central + MISO South): 767 MW (salmon).
South 1 (Tennessee Valley Authority & LG&E Energy Transmission Services): 1,278 MW (orange-yellow).
South 2 (VACAR — non-PJM): 2,493 (creamsicle).
Long-Term Impact
PJM credits the implementation of the Reliability Pricing Model for a net of 62,464 MW in capacity since its implementation.New generation and generation upgrades have contributed more than half of the increased capacity since the start of RPM, with demand response, imports and cancelled retirements making up the rest.
The 11 base residual auctions to date have procured almost 29,100 MW of new generation, more than replacing the 20,700 of de-ratings and retirements. Demand response to date has totaled almost 11,300 MW with energy efficiency adding almost 1,300 MW.
Combined-cycle plants have been by far the biggest source of new generation since the capacity market began with a total of more than 19,000 MW. Steam units and combustion turbines have each added almost 6,000 MW. Additions among other fuel sources were each less than 2,000 MW.
[Editor’s Note: Click here for an updated and expanded version of this story.]
The 2017/2018 base residual auction cleared at $120/MW-day in most of PJM as restrictions on demand response and imports doubled prices in Virginia, West Virginia, North Carolina and much of Ohio.
Prices were essentially flat in the east, with the PSEG zone falling to $215/MW-day and MAAC up by less than $1. ATSI rose 5%.
Click chart(s) to zoom.
Unlike last year’s auction, which saw the PSEG, ATSI and MAAC zones separate from the rest of the RTO, only the PSEG zone cleared separately.
The auction procured 167,004 MW for the delivery year beginning June 1, 2017, good for a 19.7% reserve margin.
Six new combined-cycle plants, totaling 4,800 MW, cleared for the first time, almost all of it located east of the west-to-east transmission constraints or in other areas with capacity needs. In total more than 5,900 MW of new entry cleared.
In a press conference late this afternoon, Executive Vice President for Markets Andy Ott said the increase in clearing prices resulted from the limits on imports, summer-only demand response and the costs of compliance with state environmental regulations.
“I think the changes that we have made … certainly had their intended effect,” Ott said. “Anytime you have an auction with competitive new entry with this kind of volume, we look at that as a success story.”
About 11,000 MW of demand response cleared, a drop of 1,433 MW from last year’s auction. Annual DR increased by 1,400 MW and extended summer by almost 4,700 MW, while limited summer-only resources dropped by more than 7,500 MW. Energy efficiency rose to a record 1,339 MW, up by more than 200 MW.
Ott touted the “dramatic shift” in DR. “All in all we saw it as a positive result that we got higher value DR,” he said.
Imports dropped to about 4,500 MW, down from 7,500 last year. Unlike last year, all of the imports came with firm transmission. All but about 500 MW cleared after winning exemptions from the import limits, which required them to also be pseudo-tied.
Rule Changes
In last year’s auction, RTO prices dropped 56% to $59.37/MW-day, while prices in ATSI dropped more than two-thirds (to $114/MW-day) and MAAC fell 29% ($119). Prices in the Public Service zone rose 31% to $219. Generation imports nearly doubled, leading some to question their deliverability. (See Capacity Auction: New Generation, Imports Up, Prices, DR Down.)
In April, the Federal Energy Regulatory Commission approved PJM’s plan to create five import zones with a combined limit of 6,499 MW for this year’s base auction (ER14-503). (See FERC Clears Capacity Import Limits.)
FERC also recently approved most of PJM’s proposal for making demand response an “operational resource.” However, the commission rejected a proposal requiring DR providers to respond to sub-zonal dispatch. The commission also rejected PJM’s proposals for eliminating financial speculation in the auction, instead scheduling a technical conference to develop a solution. (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)
FERC previously approved rules requiring DR providers to give more assurances in their offers (ER13-2108), as well as limits on the clearing of limited demand response (ER14-504).
In first-quarter earnings calls before the auction, executives of PJM companies said they didn’t expect a dramatic rise in prices following the rule changes.
[Editor’s Note: RTO Insider will have a full report on the auction results Tuesday.]
A Federal Energy Regulatory Commission rule requiring PJM and other RTOs to pay demand response resources market clearing prices violates state ratemaking authority, a federal appeals court ruled today.
The Court of Appeals for the D.C. Circuit ruled 2-1 to void FERC Order 745, backing a challenge by the Electric Power Supply Association and others.
The commission’s 2011 order (RM10-17) required DR participating in the day-ahead and real-time energy markets to be paid locational marginal prices identical to those for generation. The order applied when DR was capable of balancing supply and demand and lowered the market-clearing price.
FERC said it had authority for the order under sections 205 and 206 of the Federal Power Act because reducing retail consumption through DR can aid reliability and lower wholesale prices.
The commission made a distinction between “price-responsive” DR, which it acknowledged was a retail product subject to state regulation, and DR response to incentive payments, which it called “wholesale demand response.”
Not a Wholesale Sale
Judges Janice Rogers Brown and Laurence H. Silberman disagreed. “A buyer is a buyer, but a reduction in consumption cannot be a `wholesale sale,’” they wrote in a 16-page opinion authored by Brown (11-1486). “FERC’s metaphysical distinction between price-responsive demand and incentive-based demand cannot solve its jurisdictional quandary.”
The commission “went far beyond removing barriers to demand response resources,” as Congress had ordered in the Energy Policy Act of 2005, the judges ruled.
In addition, the judges said, FERC’s reasoning had “no limiting principle,” agreeing with petitioners who said it would allow the commission to regulate the steel, fuel and labor markets because they also impact wholesale prices.
Windfall
Even if Order 745 did not encroach on state authority, it would have failed anyway because paying DR the LMP is not just and reasonable, the judges said, siding with Commissioner Philip Moeller, who dissented in the order. Moeller argued Order 745 overcompensates DR because it requires that it be paid the full LMP plus “be allowed to retain the savings associated with [the provider’s] avoided retail generation cost.”
The judges said this “potential windfall to demand response resources seems troubling, and the Commissioner’s concerns are certainly valid.”
Dissent
In a 28-page dissent, Judge Harry T. Edwards disagreed with the majority both on the jurisdictional question and on the propriety of paying DR at LMP.
Edwards said FERC deserved deference in its interpretation because the FPA is “ambiguous regarding whether forgone consumption constitutes a `sale’” and whether “a rule requiring administrators of wholesale markets to pay a specified level of compensation for such forgone consumption constitutes `direct regulation’ of retail sales” that would encroach on state jurisdiction.
Edwards noted that the compensation requirement built on the commission’s 2008 Order 719, which required that ISOs and RTOs accept bids from DR “unless not permitted by the laws or regulations of the relevant electric retail regulatory authority.”
Moreover, Order 745 was not the type of “direct regulation” of retail sales that would violate state prerogatives, Edwards said.
“All Order 745 says is that if a State’s laws permit demand response to be bid into electricity markets, and if a demand response resource affirmatively decides to participate in an ISO’s or RTO’s wholesale electricity market, and if that demand response resource would in a particular circumstance allow the ISO or RTO to balance wholesale supply and demand, and if paying that demand resource would be a net benefit to the system, then the ISO or RTO must pay that resource the LMP,” Edwards said. “That is it.”
Edwards also disagreed that upholding the order would leave FERC with unfettered authority, noting the restrictions the court had imposed in the California ISO case (372 F.3d 395), in which it ruled that FERC exceeded its jurisdiction in replacing the ISO board members on the theory that the composition of the board affected wholesale rates.
The court held that FERC’s authority was limited to matters “that directly affect the rate or are closely related to the rate, not all those remote things beyond the rate structure that might in some sense indirectly or ultimately do so.”
Edwards said requiring DR be paid the full LMP was reasonable to overcome barriers to entry.
Impact of Ruling
Before Order 745, ISOs and RTOs differed in the level of compensation paid to DR, with some underpaying demand resources in some circumstances, the commission ruled.
FERC’s response to the court’s rejection will be affected by the change in the composition of the commission since it issued the order. Order 745 was approved on a 4-1 vote that included two commissioners no longer on the panel: former Chairman Jon Wellinghoff, a strong proponent of DR, and Mark Spitzer.
Commissioner Tony Clark, who often sides with Moeller, replaced Spitzer, noted attorney Carolyn Elefant in a recent blog post.
Elefant said that an adverse ruling could affect FERC’s enforcement action against Lincoln Paper Co. for allegedly manipulating the ISO New England’s DR program. The Maine-based company filed a motion to dismiss in February that challenged the enforcement action on jurisdictional grounds.
Wellinghoff, now strategic counsel for the Advanced Energy Management Alliance (AEMA), said if the decision survives an appeal it will “lead to increased electricity costs for consumers by putting more money in the pockets of power generators.”
The alliance, a trade group for DR providers, noted a report by PJM’s Market Monitor that estimated DR saved consumers $11.8 billion in 2013.
Environmental groups also lamented the ruling. “As the U.S. advances into the clean energy economy, demand response should play an increasingly larger role in how our electricity is produced, delivered and consumed,” the Environmental Defense Fund said in a news release. “This order stymies that growth.”
If the jurisdictional ruling stands, “it could severely limit FERC’s ability to create a level playing field in wholesale markets and even planning for energy efficiency, demand response and other technologies,” said John Moore, senior attorney for the Natural Resources Defense Council’s Sustainable FERC Project.
“At a time when the transmission grid and our electric resource portfolio are changing rapidly — think more solar and wind power, rooftop solar, electric cars and two-way grid communications — the court’s decision could seriously constrain FERC’s ability to reform grid rules to accommodate these new dynamics, effectively cementing the agency into a 20th century approach to addressing 21st century challenges,” Moore said.
PJM Response
PJM noted that the ruling will not take effect immediately. The court told its clerk of the court to withhold issuance of the mandate on the order until seven days after disposition of any petitions for rehearing.
“Therefore, PJM hereby advises that it will continue to abide by the terms of its Tariff and Operating Agreement as relates to demand response in its markets,” the RTO said in a statement. “In other words, PJM will continue to operate business as usual.”
“At this point, it’s business as usual,” Andy Ott, executive vice president for markets said in a press conference today on capacity market results. If the order stands, he said, “FERC will have to [provide] some clarification on our Tariff.”
WASHINGTON — Federal Energy Regulatory Commissioner Cheryl LaFleur sailed through her Senate confirmation hearing Tuesday while Norman Bay was forced to defend his limited policy experience and his running of the commission’s enforcement division.
Cheryl LaFleur and Norman Bay being sworn in to the Senate hearing.
Bay also found himself having to negotiate a gender politics minefield resulting from President Obama’s decision to appoint him directly into the chairmanship — leapfrogging him over LaFleur, the acting chair and the only woman on the panel.
Based on the senators’ comments at the Energy and Natural Resources Committee hearing, Bay will likely need every Democrat — or will have to pick off a Republican or two — to win confirmation.
LaFleur’s reappointment to a second five-year term, by contrast, seems assured.
No one criticized LaFleur, and some of the Republicans, including ranking member Lisa Murkowski of Alaska, said they would like to see her retain the chairmanship.
Heavy-Handed Enforcement?
It was clear well before the hearing started that Bay would face strong headwinds.
Two days earlier, The Wall Street Journal published an op-ed by former FERC general counsel William Scherman, along with a piggybacking editorial by FERC antagonist Paul Gigot, accusing Bay of driving Wall Street banks out of energy trading with heavy-handed enforcement tactics.
It continued an attack that Scherman, now a well-compensated attorney representing FERC targets, had begun at the National Association of Regulatory Utility Commissioners conference in November. (See FERC Pick a Blank Slate.)
Norman Bay, with Richard Gates looking on, responding to questions on his handling of the Gates case.
When Bay stood up to be sworn in, Richard and Kevin Gates — the twin hedge fund managers whose case Scherman cited as exhibit A — were sitting in the row behind him. Richard was on camera, over Bay’s shoulder, during the entire two-hour hearing. (See PJM Trader Calls FERC on Manipulation Probe.)
Murkowski made it clear that Bay had failed his job interview when he met her in her office the previous week.
After praising his “impressive personal story and resume,” Murkowski said she judged his energy policy experience as “recent and limited.”
“I did feel that our discussions had raised questions about your qualifications not just to be a sitting commissioner but to serve as the next chairman of FERC,” she said.
Bay, a first-generation Chinese American who attended Dartmouth and Harvard before becoming a U.S. attorney for New Mexico, has served as director of FERC’s Office of Enforcement since 2009. But unlike most FERC commissioners in the last decade, Bay has never served as a state utility regulator. (See table.) In addition, the last five chairmen served a median of 30 months before becoming chair.
Other Republicans joined in the attack, citing the Wall Street Journal articles and Scherman’s accompanying May 13 article in the Energy Law Journal. The latter — a 49-page, 28,000-word article — alleged a “widespread view that the FERC enforcement has become lopsided and unfair” and called for reforms.
“I find this very troubling,” Sen. John Barrasso (R-Wyo.) told Bay. “I believe this raises serious questions about your fitness to be on the commission. I also believe that these tactics have contributed to driving investors out of the electric market and that means a less reliable grid and higher costs to consumers.”
Sen. Mike Lee (R-Utah) also pressed him on Scherman’s allegations, asking him, “Is this true? Do we need reforms?”
Bay noted that the commission had adopted the “Brady doctrine,” which requires prosecutors to provide targets exculpatory evidence in the government’s possession, at his suggestion. Scherman alleges that FERC officials have failed to abide by the doctrine.
Bay’s response to the criticism was curiously unemphatic. He did not say the allegations were false. He said he didn’t “believe” them to be accurate.
LaFleur provided Bay only limited cover, acknowledging she had dissented on several orders over application of penalty guidelines and investigative procedures. “This is a relatively new area of our work,” she said. “It’s to be expected that we would have debates about how the rules are to be applied … but I haven’t dissented on any of the settlements or the substance of the orders to show cause.”
Negative Pricing and Market Manipulation
Sen. Lamar Alexander (R-Tenn.) tried to corner Bay with a long series of cross examination-style questions in which he attempted to link FERC’s enforcement practices with wind farms, the production tax credit, negative energy prices and nuclear power’s financial woes.
Senator Manchin
Democrat Joe Manchin and Republican Rob Portman, of the coal-dependent states of West Virginia and Ohio, spent their time on the clock asking what FERC could do to stop the EPA’s pending greenhouse gas rules.
Manchin, who helped sink the bid of Obama’s previous nominee, Ron Binz, did not indicate whether or not he would support Bay. He has previously expressed doubts about Bay’s experience. (See Senators Weigh in on Bay Nomination, PTC, Nuclear Waste.)
Portman offered perhaps the best news Bay heard all day, saying, “I assume you are going to be confirmed.”
Republican Ally
Bay had one notable Republican ally, a frail former committee Chair Pete Domenici, a fellow New Mexican, who introduced him in a rambling defense.
Senator Domenici
“He’s done everything right to entitle him to try this, try this job on …” Domenici said. “I’m not a great fan of the president of the United States. People know that. But this is a great appointment.”
Current New Mexico Sen. Martin Heinrich, a Democrat, also sponsored Bay. He praised Bay as “fair, balanced [and] consensus-oriented” and said he had used the enforcement tools that Congress granted FERC in 2005 to provide “$300 million in relief to consumers.” Heinrich dismissed Scherman’s attack as “sour grapes,” noting the attorney had represented “the losing side in a number of cases.”
Sen. Maria Cantwell (D-Wash.) also gave a spirited defense. She noted that Congress gave FERC expanded penalty powers in response to the Western energy crisis, during which traders at Enron and other companies boosted profits by manipulating the electricity market.
“The energy markets cannot be a tool for those who want to invest just for their own manipulation of the market. We have to have policemen on the beat,” she said. “… I want to remind everyone that the policeman has been on the beat and has done a lot of great work.”
Gender politics
But for most of the session Bay and his supporters found themselves playing defense, not only over his experience and FERC record but for his gender and Obama’s decision to appoint him as chairman. In addition to having one of five votes on the bipartisan commission, the chairman serves as FERC’s chief executive, responsible for managing staff and setting policy initiatives.
Senator Murkowski
Murkowski said she was troubled by “the fact that our lone female commissioner, who has certainly demonstrated her leadership, would be moved down from the position that she currently holds as chairman.”
Barrasso also said Bay’s qualifications paled in comparison to LaFleur’s, who came to FERC after more than two decades of experience in the electric and natural gas industries, including roles as chief operating officer, general counsel and acting CEO of National Grid USA and its predecessor.
“Given the wide gap in experience between you and chairwoman LaFleur, why should we demote chairwoman LaFleur to make room for you?” Barrasso asked. “And what specific qualifications do you have to be chairman of FERC?”
Bay responded by talking about his “great respect” for LaFleur and professing his confidence that they would work well together.
As to the president’s decision to pass over a seemingly more qualified woman?
“You would have to ask the White House that particular question,” Bay responded. “But I would like to think that the White House might have considered a number of factors. First that I’ve done work – and good work – to protect consumers and the integrity of the marketplace and to ensure that there’s a level playing field for all market participants.”
Bay also cited his “bipartisan record of commitment to public service and good government,” a reference to his work with the State and Justice departments during Republican administrations. Bay also said his experience in the energy industry began before he joined FERC, citing his work as counsel to Sandia National Laboratory and two summers in college during which he worked at a Department of Energy research facility.
Finally, Bay got to what may be the realpolitik answer for why the White House could have bungled the politics of the FERC chairmanship for a second time: “Geographical diversity,” Bay said.
Bay was backed for the post by former FERC chair Jon Wellinghoff, an ally of Senate President Harry Reid of Nevada.
“I do come from New Mexico,” Bay said. “It’s a Western state and it’s a producer state. And Westerners and Pacific Northwesterners have always cast a long shadow, not only on this committee but also on FERC as well.”
Maybe LaFleur, an unapologetic Boston sports fan, shouldn’t have worn her Red Sox jersey to the commission meeting last October.
The EPA’s cooling water rule resulted from a settlement following years of litigation with environmental groups including Riverkeeper Inc., Natural Resources Defense Council and the Sierra Club. Based on environmentalists’ reaction yesterday, the legal battles may not be over.
Reed Super, legal director for the Waterkeeper Alliance, said the EPA abdicated its responsibility “to state agencies that are simply not equipped to make these decisions alone.
“Unfortunately, EPA’s rule will perpetuate the unacceptable status quo that has allowed antiquated plants to withdraw nearly 100 trillion gallons of fresh and sea water each year, and indiscriminately kill fish and wildlife instead of recycling their cooling water or use dry cooling technology, as modern plants have done for the past three decades,” Super said. “We are beyond disappointed with this new rule.”
The energy industry’s initial review was more positive. “The Environmental Protection Agency, to its credit, has taken into account many viewpoints and made improvements to this rule based on the scientific data and procedural analysis that has been brought to its attention,” the Nuclear Energy Institute said in a statement. “We’re hopeful those improvements are included in the final rule.”
NEI said enforcement must recognize the impacts on electric reliability and include cost-benefit analyses to balance increases in electricity costs against environmental benefits.
“Cooling towers consume twice as much water from the aquatic habitats we want to protect compared to once-through cooling systems,” NEI continued “This fact is very important given projections that much of our country will face a water-constrained future. Technology-based solutions at a power plant’s cooling water intake structure can be highly effective in protecting fish and can accommodate the ecological diversity of the various sites. As the EPA has pointed out previously, solutions like traveling screens, with a collection and return system, are comparable to cooling towers in protecting aquatic life in water bodies used for cooling power plants.”
Tom Kuhn, president of the Edison Electric Institute, said the association was “pleased that EPA had avoided imposing a categorical one-size-fits-all approach to compliance; has embraced significant elements of flexibility; and has acknowledged the importance of weighing costs with environmental protection.”
