Exelon last week filed an application with the Federal Energy Regulatory Commission seeking approval of its acquisition of Pepco Holdings Inc. FERC approval is expected to come fairly swiftly, as PHI has no generation, and market power issues shouldn’t come into play.
The two companies announced the proposed acquisition late last month. If approved, it will bring together Exelon’s three electric and gas utilities – BGE, PECO and ComEd – with PHI’s three utilities – Delmarva Power, Pepco and Atlantic City Electric. The combined companies would become the largest electric and gas utility in the Mid-Atlantic.
Because no generation plants are involved, the companies are asking for approval within 90 days. The acquisition still requires approval from state regulatory agencies in Delaware, Maryland, New Jersey and Virginia, as well as from the D.C. Public Service Commission. Those approvals are expected to take longer to obtain. The companies have said they anticipate full approvals by the second or third quarter of 2015.
FERC has gained a valuable new tool in the fight against energy market manipulation as a result of an agreement giving the commission access to the Commodity Futures Trading Commission’s Large Trader Report. “Until recently, we didn’t have a lot of visibility into large trading data, [but] the CFTC has given us a lot more transparency in terms of positions,” Sean Collins, FERC’s deputy director of surveillance, told a conference in Texas last month.
Collins said the memorandum of understanding between the two organizations has given FERC investigators a clearer view of what is going on in the derivatives market, which often plays a crucial role in manipulative schemes that involve both physical and financial products. “The ability to see across those two markets and to be able to see what market participants are doing is essential, so we’re very thankful for that data,” he said.
Citing previous safety studies, the Nuclear Regulatory Commission rejected calls from lawmakers to speed up the transfer of spent fuel bundles from pools to dry cask storage.
The commission, relying on its staff’s recommendations, has said it believes it makes more sense to leave the spent rods in on-site cooling ponds than engage in hurry-up transfers to dry cask storage.
An NRC Northeast Regional administrator said both pools and dry casks were “adequate storage processes for spent fuel, and there is not a significant safety benefit to requiring transfer to dry cask storage.”
Some lawmakers, however, citing security concerns and dwindling space in cooling pools, are pushing for the transfers.
Several senators wrote to NRC Chair Allison Macfarlane earlier to complain about a lack of security around the pools and closed plants. “We are one natural disaster, mechanical failure or terrorist attack away from a disaster,” said Sen. Bernie Sanders (I-Vermont). “The sooner we get the spent [fuel] out of the pools and into dry casks, the better, and if the NRC will not change the rules, I will continue to work with my colleagues to change the rules through legislation.”
The EPA successfully fended off efforts by environmental groups to hasten implementation of rules combatting acid rain. The U.S. Court of Appeals for the D.C. Circuit last week accepted the EPA’s arguments that rules covering acid rain must take into account “large complexities” and shouldn’t be hurried. The EPA announced two years ago that it needed more time to determine new standards of certain pollutants, primarily those emitted by fossil-fuel fired power plants. Environmental groups, including the Center for Biological Diversity, sued and accused the EPA of delaying the implementation of new regulations.
“In light of the deference due EPA’s scientific judgment, it is clear its judgment must be sustained here,” U.S. Circuit Judge A. Raymond Randolph wrote for a three-judge panel.
A joint proposal from PJM and the Independent Market Monitor to reduce payments to frequently mitigated units (FMUs) rose from the ashes to best three generator-backed proposals last week.
The PJM-IMM proposal earned nearly 70% approval in a sector-weighted vote of the Markets and Reliability Committee, despite earning just 43% support from the Market Implementation Committee in early May. (See Members Reject PJM-IMM Plan on FMUs).
The proposal was approved after three packages favored by suppliers failed to earn enough support for approval.
Market Monitor Joe Bowring has said the adders are no longer needed because of PJM’s capacity market.
The PJM-IMM proposal (Package A) leaves the calculations for adder payments unchanged but limits them to units whose net revenues are not covering their avoidable cost rate (ACR). PJM said that had the proposal been in effect in 2013, it would have reduced the number of units receiving adders from 112 to only 28 — 23 of which are scheduled to retire.
Neil Fitch of NRG Energy said his company couldn’t support the PJM-IMM package because it “seems tantamount to eliminating FMUs.”
Package G, which was considered first based on the 65% support it received at the MIC, received only 40% support from the MRC. It would have capped adders at 12% of the gross Cost of New Entry (CONE).
Of the three generator-backed proposals, only Package H received more than 50% of sector-weighted support, though it didn’t come close to the two-thirds support needed for approval. It would change adders only for Tier 2 FMUs — units that are offer-capped between 70% and 80% of their run hours over the prior 12 months.
Members last week agreed to create a senior task force to fix the underfunding of Financial Transmission Rights (FTRs) following a debate over the role of Auction Revenue Rights.
PJM says over-allocation of Stage 1A ARRs have become the biggest cause of the problem, responsible for $420 million of underfunding for planning year 2013/14, 73% of the total. That was up sharply from 2012/13, when ARRs caused only 26% of underfunding, or $75 million. (See chart below.)
PJM agreed to modify the task force’s initiating documents to include an evaluation of the causes of underfunding after several stakeholders raised concerns that ARRs were being unfairly singled out. ARRs are allocated annually to firm transmission service customers and entitle them to receive a share of the revenues from the annual auction of FTRs.
Ed Tatum of Old Dominion Electric Cooperative objected to the original problem statement, which he said improperly included a solution that targeted ARRs.
ARRs are “a touchstone issue for the load-serving entities,” Tatum said. “We don’t believe the numbers [cited by PJM] reflect the actual impact of the problem … We think it’s a much lower number and we’d like to understand how PJM calculated it. It’s more than likely there are other, more significant causes of the underfunding.”
Andy Ott, executive vice president for markets, said PJM wanted to keep the issue scope narrow to avoid the “food fights” of the past.
PJM says more than 15% of Stage 1 historical generation (25,544 MW) has retired or submitted deactivation notices since the ARR allocation process was designed. “This is the biggest reason for underfunding,” said Harry Singh of Goldman Sachs. “You’re allocating things that don’t exist.”
Singh said a failure to address FTR over-allocation could jeopardize the Commodity Futures Trading Commission’s order exempting FTRs from the agency’s jurisdiction. The order said FTRs must “be limited by the physical capability of the … transmission system.”
The problem statement also identified other underfunding causes, including external loop flows, maintenance- and construction-related transmission outages and the creation of temporary interfaces to capture operating procedures — such as the dispatch of demand response — in locational marginal prices.
The RTO introduced FTRs in 1999, intending them to provide a financial hedge against the costs of day-ahead transmission congestion.
Singh said that load-serving entities “should also care about having good hedges.” Those who oppose solutions to the problem “are not doing a favor for the people they work for,” he said. Over-allocation to a handful of load-serving entities amounts to a subsidy by other LSEs, he said.
Ott said the task force, which will report to the MRC, should complete its work by Oct. 31, before the next annual FTR auction. “If we don’t deal with it by October, then we miss a whole year,” he said.
ROCKVILLE, Md. — “Clean” energy portfolio standards may be a way for states to provide financial support for ailing nuclear plants, Federal Energy Regulatory Commission officials said last week.
FERC Commissioner Phil Moeller, FERC Acting Chair Cheryl LaFleur, NRC Chair Allison MacFarlane (L to R)
The comments came during FERC’s public meeting with the Nuclear Regulatory Commission on grid reliability Wednesday. Officials of the North American Electric Reliability Corp. (NERC) also took part in the 90-minute session at NRC headquarters, which included discussions on NRC’s actions to address lessons learned in the 2011 Fukushima nuclear disaster and FERC’s regulation of hydropower dams near nuclear plants.
But coming on the heels of a capacity market auction in which five Exelon Corp. nuclear generating plants in Illinois failed to clear, the financial health of nuclear power was the central topic. (See related story How Exelon Won by Losing.)
FERC Commissioner Tony Clark noted that PJM and other organized wholesale markets have been able to coexist with state renewable portfolio standards (RPS) that ensure a place for wind and solar power in the generation mix.
“So an elegant solution might be pivoting to a clean-energy standard if the concern of a state is emissions and … if we’re moving into a 111(d) world where carbon is going to be regulated,” Clark said, referring to the greenhouse gas rule released by the EPA yesterday. “These would seem to be some of the most valuable units we have.”
Arnie Quinn, director of FERC’s Division of Economics and Technical Analysis, said such a structure might overcome the jurisdictional challenges that he said have “hamstrung” regulators in restructured states.
Quinn said state regulators have expressed a desire to obtain purchase-power contracts to keep their nuclear plants open. “They look [for someone] to sign that contract and they have difficulty finding who they still have jurisdiction over,” he said. In states with RPS, load-serving entities are obligated to purchase minimum percentages of renewable sources such as wind and solar.
Fuel Security
FERC is also considering ways to bolster nuclear generators’ capacity revenues, perhaps through a “fuel security” premium.
FERCs Arnie Quinn
Acting FERC Chair Cheryl LaFleur said although the wholesale markets are “fuel blind,” they also acquire resources that possess important capabilities, such as ramping, needed to keep the grid functioning. Fuel security could be such a capability to incorporate, she suggested.
In January, natural gas-fired plants had trouble obtaining fuel due to high prices and pipeline constraints. Coal-fired plants also experienced problems due to frozen coal and delayed rail shipments.
Nuclear plants need to add fuel about once every two years — about the same frequency with which FERC and NRC hold these joint meetings.
“Knowing that you’ve got a stock of fuel on site … that will be there for the duration of a weather event — it’s another thing you don’t have to” worry about, Quinn said.
Causes of Nukes’ Problems
Quinn cited data from the PJM Market Monitor showing that nuclear generators’ net energy and capacity revenues in the RTO have declined from more than $300,000/MW-year in 2010 and 2011 to $240,000 in 2013.
Quinn said the causes include excess supply, particularly from low-cost natural gas and wind, and capacity prices depressed by demand response and transmission upgrades.
Quinn said that fossil fuel plant retirements resulting from the EPA’s Mercury and Air Toxics Standards and transmission expansion that makes it easier for generators to reach load may help boost prices. “But the degree to which any of these future changes will result in a full recovery of revenue levels is just uncertain at this point,” he said.
Quinn also noted that nuclear plants benefited from energy market prices in January that hit $1,000/MWh during some hours.
“In some degree the system has been designed so that’s where a lot of cost recovery occurs … If your marginal cost was down at $15 to $20 per megawatt-hour there was a lot of money there to be earned to recover some fixed costs.”
The question FERC is considering, Quinn said, is whether current energy and capacity revenues are enough to preserve the nuclear fleet or whether it requires some other payment stream.
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.
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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.
Exelon last week filed an application with the Federal Energy Regulatory Commission seeking approval of its acquisition of Pepco Holdings Inc. FERC approval is expected to come fairly swiftly, as PHI has no generation, and market power issues shouldn’t come into play.
