PJM said last week it agrees with about one-quarter of the recommendations in the Independent Market Monitor’s 2013 State of the Market report.
PJM’s response to the Monitor’s annual review disagreed with about 40% of the recommendations. The RTO was noncommittal, or said it was unable to act, on about 35% of the more than 70 recommendations.
PJM agreed with about the same share of the IMM’s recommendations in its 2012 report but directly disagreed with about half of them.
The RTO’s 2012 response urged the Monitor to focus its findings on those with the biggest potential payback, noting that more than 90% of the suggestions pertained to subjects comprising less than 20% of total wholesale power market costs. The RTO said it was happy, however, that the Monitor had begun prioritizing the recommendations in the 2012 report.
In the 2013 report, the IMM prioritized only the new recommendations.
“Given the scope of issues to be considered in the stakeholder process, evaluation of priority and materiality of recommendations is an important consideration,” PJM said in its response. “PJM encourages the IMM to include consideration of priority and materiality in discussion and development of all recommendations along with associated detailed rationales for suggested changes to market rules.”
Acting on the eve of PJM’s base capacity auction, the Federal Energy Regulatory Commission Friday approved most of PJM’s new dispatch rules for demand response but rejected a plan to curb speculation in the auction, saying it created undue barriers to entry.
Instead, the commission ordered a technical conference to develop solutions to eliminate arbitrage opportunities between the base residual auction (BRA) and incremental auctions (IAs). It approved all but one of the major provisions of PJM’s DR proposal, rejecting the ability of the RTO to dispatch resources on a subzonal basis.
The commission said PJM’s proposed arbitrage fix — which the RTO proposed unilaterally after failing to obtain stakeholder consensus — “will simultaneously increase risk to suppliers and costs to load, without guaranteeing equally offsetting benefits to the PJM grid as a whole” (ER14-1461).
PJM proposed the arbitrage fix in March after the Markets and Reliability Committee failed for a second time to reach consensus. (See Second Time Not the Charm.)
No Consensus
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.
Generators, including AEP, Calpine, PSEG, LS Power, Exelon, the PJM Power Providers and the Electric Power Supply Association, submitted interventions backing the PJM proposal. The Maryland Public Service Commission, Brookfield Energy Marketing LP, demand response provider Comverge, Old Dominion Electric Cooperative and American Municipal Power, Inc. were among those filing in opposition.
‘Disruptive’ Proposal
The commission said PJM’s “disruptive” proposal would increase risks for capacity sellers, creating undue barriers to entry, and increase costs to load through the acquisition of excess capacity. The commission was also unpersuaded by PJM’s “limited demonstration of the presence of speculative sell offers.”
“PJM has not demonstrated the degree to which purchases of replacement capacity are, in fact, the result of resources’ inability to meet their capacity obligations for non-speculative reasons, or resources submitting physical offers and responding to subsequent economic signals, or overly-optimistic offers `insured’ by consistent price spreads, or speculators looking to profit from consistent price spreads,” the commission wrote.
“Even existing generation resources, typically the most `physical’ of all resources, may seek to purchase replacement capacity as a result of unforeseen circumstances. More generally, both existing as well as planned capacity resources face a chance of being unable to meet their delivery year obligations due to unforeseen problems with a resource, or a resource’s development, and thus may reasonably wish to recoup certain sunk costs.”
The commission said the proposal could also increase costs for load by limiting the ability of the RTO to sell excess capacity back to the market.
The revised rule would have allowed PJM to sell into the IAs only if the clearing price equaled or exceeded the original BRA price. The commission said PJM had already taken steps to prevent capacity sellers from profiting from the purchase of cheap replacement capacity through a provision to recapture any such profits.
While it ruled PJM’s proposal not just and reasonable, the commission said it agrees “that PJM has identified a reliability issue that merits consideration.”
The commission said FERC staff will convene a technical conference to help develop a solution. The proceeding will be conducted in a new docket (EL14-48) using the procedures spelled out in Section 206 of the Federal Power Act.
DR Dispatch Proposal
PJM fared better in its proposal to increase its options for dispatching demand response. The commission voted 3-1 to approve all but one of PJM’s rule changes, with Commissioner John Norris dissenting.
The order (ER14-822) allows PJM to dispatch DR before emergencies, reduce default notice times to 30 minutes from as long as two hours and reduce minimum run times to one hour from two. However, the commission ordered PJM to allow small commercial customers to be eligible for the “mass market” exemption from the 30-minute notice.
It also approved an escalating price cap based on notice requirements:
30 minutes: $1,000/MWh, plus the primary reserve penalty factor, minus $1.
60 minutes: $1,000/MWh, plus the primary reserve penalty factor divided by two.
120 minutes: $1,100/MWh.
The previous rules capped DR at $1,000/MWh plus two times the applicable primary reserve penalty factor, for a total of $1,800/MWh. With rising penalty factors, the offer caps would have risen to $2,700/MWh over the next two years.
PJM’s proposed changes to measurement and verification rules were also approved, but FERC required a revision to allow DR providers to aggregate their performance for dispatches on the same operating day and within the same zone. The commission also ordered PJM to produce reports documenting its implementation of the new rules.
Sub-Zonal Dispatch Rejected
The commission rejected PJM’s call for sub-zonal dispatch inside an operating day. The commission ruled that PJM failed to show that DR providers which provide day-ahead sub-zonal dispatch can comply with sub-zonal dispatch on the operating day within 30 minutes without suffering “prohibitive costs.”
The commission said complying with the rule could be “difficult and costly” for curtailment service providers with customers in multiple locations and for individual customers with a footprint larger than a sub-zone.
“The necessary technology for demand resources to comply with this provision of PJM’s proposal is not widely available today,” the commission said. “If it becomes more widely available in the future, that change could enable PJM to show that this aspect of the proposal is just and reasonable.”
Norris Dissents
Commissioner Norris issued a dissent arguing that the 30-minute notice requirement imposed “a significant barrier” on DR participation in the capacity market that would undermine reliability and increase costs for consumers.
“I am particularly troubled because PJM’s proposal represents the third major tariff filing recently approved by this Commission that collectively will have the impact of reducing demand response participation in PJM capacity markets,” Norris wrote, referring to earlier rule changes that capped capacity offers for limited and extended summer DR (ER14-504) and required DR providers to give more assurances in their offers (ER13-2108).
“Demand response has repeatedly demonstrated its value in helping PJM meet system needs, but because some resources will be unable to meet the new performance requirement, such demand response will now be valued at zero and driven out of the market,” Norris continued. “As was made clear from this past winter’s polar vortex weather events, PJM needs all the resources it can get to help ensure reliability, particularly during times of system stress. I fail to understand why the Commission through today’s order would sanction efforts to unnecessarily reduce the pool of potential resources at PJM’s disposal.”
The first project window for the 2019 Regional Transmission Expansion Plan will open in about a month, PJM told the Planning Committee last week.
PJM has posted results of its baseline N-1 study and expects to post its generation deliverability study in about a week, PJM’s Mark Sims said. The window will open when PJM completes a load deliverability study. “We’re looking at at least a month [to complete the third study]. It’s not going to be three months,” Sims said.
The window, which will be open for about 30 days, is unlikely to result in a large number of opportunities for non-incumbent transmission developers. Paul McGlynn, general manager of system planning, said “95% of projects in RTEP are upgrades to existing facilities,” which are assigned to incumbent transmission operators under FERC Order 1000.
McGlynn added that PJM is considering creation of a template for “no brainer” RTEP upgrades, to simplify and standardize the process for those submitting such projects.
PJM will open a second proposal window after completing its study of 2019 N-1-1 violations this summer. Approved projects will be submitted to the PJM Board of Managers in the fall.
Below is a summary of the recommendations from PJM’s report on the operational challenges from January 2014. Recommendations new to the report are marked.
Unit Performance (NEW): Improve unit performance through incentives for performance and penalties for non-performance. Investigate unit testing, including testing dual-fuel capability. Improve preparation in advance of winter operations.
Unit Characteristics: Improve information sharing with generation owners, including fuel source and emission limitations. Improve specificity of the outage cause types in eDart and consider methods for validation. Clarify the rules for claiming an “Outside Management Control” event for taking an outage.
Gas/Electric Coordination: Improve harmonization of the timing of the gas and electric operating days. Allow generators to better include natural gas costs in their energy and capacity offers. Consider a review of offer caps and allowing generators to make changes to offers during the operating day. Consider allowing generators to reflect fuel availability in start-up and notification times.
Fuel Limited Resources (NEW): Improve information sharing for fuel-limited resources (those with less than 72 hours’ worth of fuel at maximum capacity).
Fuel-Specific Limitations (NEW): Consider methods for calling on long-lead generation based on fuel procurement limitations.
Energy Market Uplift: Review the cost allocation of energy market uplift.
Interregional Coordination (NEW): Increase situational awareness with the VACAR Reserve Sharing Group and Reliability Coordinator.
Unit Commitment (NEW): Clarify rules and conduct training regarding start-up costs and cancelled dispatch provisions.
Voltage Reduction Emergency Procedure: Review the voltage-reduction capabilities of transmission owners, particularly those without SCADA control.
Emergency Energy Bids: Enhance the tools and processes for accepting Emergency Energy Bids.
Regulation Market Rules (NEW): Reexamine the performance of the Regulation Market and investigate whether current rules are adequate. Consider going short regulation during system peaks.
External Capacity (NEW): Develop ways to confirm that external capacity resources either bid into the day-ahead market or submit eDart tickets indicating that they are unavailable. Ensure external resources are not declaring outages and selling energy into a different market.
Communications & Procedures (NEW): Improve how the Emergency Procedures tool is used to communicate. Consider adjustments to the roles and responsibilities for communications during emergency procedures. Refine training to reinforce processes and tools.
Public Appeals (NEW): Collect data on the impact of calls for conservation and improve processes for public notification during emergency procedures. Review triggers for public notifications.
The SPS was designed to mitigate transient instability conditions arising from an outage of the Conemaugh–Juniata 500-kV line, #5005. When enabled during an outage of the line, the SPS trips Conemaugh unit 2 if the Keystone-Conemaugh 500-kV line, #5003, is lost. Without the SPS, both the Conemaugh and Hunterstown generators would have had to reduce output in such a scenario.
The SPS hasn’t been used since 2011. The new Conemaugh 500/230-kV transformer and Conemaugh–Seward 230-kV line, which were placed in service in March, provide an additional outlet for Conemaugh and Hunterstown generation, rendering the SPS unnecessary.
The removal of the SPS is currently under review by Reliability First Corp.
New Mosby–BrambletonLine to Fix Overloads
Dominion Resources is adding a 500-kV line parallel to an existing 500-kV line between Mosby and Brambleton.
The new 500-kV Mosby–Brambleton line will be designated #546. The 2013 RTEP study identified overload violations on the Loudoun 500/230-kV transformers #1 or #2 for loss of the #590 Mosby–Brambleton 500-kV line. The new 500-kV line would be placed in an existing right-of-way and resolve this issue. The line (RTEP project #B2373) is expected to be in service by May 2018.
PJM transmission owners must notify the RTO when elements of their operations are reclassified as part of the North American Electric Reliability Corp.’s new Bulk Electric System (BES) definition.
Beginning July 1, TOs have two years to inventory their assets to determine which should be included in the BES, PJM told the Operating Committee last week.
Under a PJM compliance bulletin, notification is also necessary when TOs request an exemption from BES status and when they receive a ruling on the request.
The definition focuses on equipment rated 100 kV or higher, although it also includes some equipment rated below 100 kV.
Two weeks before Memorial Day, PJM and stakeholders are already worrying about next winter.
On Friday, PJM issued a comprehensive report on its response to the historic power demand during January’s deep freeze, adding nine proposed recommendations for action to five initiatives already underway.
Members began work on one of the new proposals last week, as the Operating Committee approved a problem statement and issue charge to consider resuming winter testing of generators. The testing would attempt to prevent a repeat of the poor generator performance in early January, when PJM saw a 22% forced outage rate, about three times its historic 7% average.
New Recommendations
The new recommendations in the 69-page report on January’s operational challenges focus on improving generator performance; handling of fuel-limited units; interregional coordination; unit commitment procedures; regulation market rules; and communications. (See Winter Report Recommendations.)
PJM executives Mike Kormos and Andy Ott answered questions about the report at the Capacity Senior Task Force meeting Friday.
Kormos, executive vice president of operations, said PJM staff is working on ways to quantify the risks identified in the report in order to prioritize the recommendations. “Is it a hair-on-fire, we-need-to-take-action-really-really-quick [issue] or is there more time?”
A common theme in the recommendations was the need to improve information-sharing to ensure operators know what generators have sufficient fuel and can be counted on to run. In tracking external resources, Kormos said, “we were doing a lot of things on spreadsheets and Post-it notes.”
Kormos also talked of the difficulty forecasting load on days when the weather made a big transition from one day to the next. “I don’t think any of us knew where load was going to end up,” he said.
Ott, executive vice president for markets, said PJM will also reconsider the way it schedules units. Because of restrictive gas pipeline rules, the RTO was often paying the most to run the least flexible units, an “inversion” of the normal situation.
“This is stuff we had never seen before and we didn’t necessarily have procedures for everything we saw,” he said.
“We’re used to calling every steam unit on during peak conditions,” added Kormos. “That may not have been the right answer.”
Testing
The Operating Committee unanimously approved the initiative to consider winter generator testing.
Mike Bryson, executive director of system operations, said designing a test that will be effective will be a challenge. PJM had winter testing until 2010, when the RTO decided to defer to new regional Reliability First Corp. standards, which were less burdensome and less costly.
The former rules allowed generators to test as late as February, which was often too late to address extreme cold conditions, officials said. Some stakeholders have questioned whether testing in December would truly help improve conditions at -10 degrees.
“I want to make sure we’re not doing testing for optics,” Bryson said. “Let’s take the 22% [outage rate] and find a way to improve it to a level that’s more typical of winter.”
Bryson said consideration of incentives for generator performance and penalties for failures would be considered in a separate initiative.
The brutal winter weather boosted revenue for many PJM companies in the first quarter, even while some were absorbing huge costs from strategy shifts.
Here’s an overview of the results from the major companies doing business in PJM.
NRG
NRG Energy, which closed on three acquisitions in the quarter, reported a loss of $56 million despite record earnings before interest, taxes, depreciation and amortization (EBITDA) of $816 million, more than double the $383 million cash flow it reported for 2013. More than half a billion of its earnings — $525 million — were from sales in the Northeast.
Duke
Duke Energy, while showing a $97 million loss from its pending sales of 13 coal-fired plants in the Midwest, still posted earnings of $1.17 per share, a 15-cent jump over the same period last year – primarily from winter energy sales.
Pepco
Pepco Holdings Inc. also showed its investors some love, turning a profit of $75 million, or 30 cents a share, compared with a year-earlier loss of $430 million, or $1.82 a share, on increased sales of electricity and gas.
Exelon
The same day Exelon reported an agreement to acquire Pepco parent PHI, for $6.8 billion, Exelon reported earnings of $90 million, or 10 cents a share, compared to a loss of $4 million, or 1 cent a share, for the same period last year. CEO Christopher Crane credited cold-weather sales at its PECO and Commonwealth Edison units for an extra bump in revenue.
Revenue shot up to $7.24 billion, from $6.08 billion last year.
“Our nuclear assets in particular contributed to grid reliability during the polar vortex, while our strategy of matching generation to load allowed us to capitalize on the increasing volatility in power markets,” Crane said.
Earnings would have been higher but for increased storm restoration costs, especially in the PECO service territory, and increased PJM capacity prices, Exelon said. These factors were partially offset by rate increases at BGE and ComEd and cold weather-related revenue in both the PECO and ComEd territories.
FirstEnergy
Cold weather drove FirstEnergy’s numbers, too. The company reported earnings of $208 million, or 50 cents per share, for the first quarter of 2014, compared with $196 million, or 47 cents a share, for the same period last year. Revenue was $4.2 billion, up 13.5%, compared with $3.7 billion for the first quarter of last year. Sales to residential customers increased 11% over 2013 while deliveries to commercial customers increased 6%. Industrial customers increased by 1%.
“The strong performance of our distribution and transmission businesses … partially offset the impact of extremely challenging market conditions on our competitive business,” CEO Anthony J. Alexander said.
American Electric Power
American Electric Power reported first-quarter earnings of $560 million, or $1.15 per share, up from $363 million, or 75 cents a share, for the same period last year, an increase of about 55%.
“We experienced the coldest temperatures in 35 years during the first quarter, which led to strong residential and commercial demand for the period,” CEO Nicholas K. Akins said. “Even when this demand is adjusted for weather, we saw improvement across residential and commercial customer classes for the second consecutive quarter.”
Dominion Resources
Dominion Resources, which sold its unregulated retail business to NRG Energy last month for $165 million, said its first-quarter earnings fell 23%, from 86 cents a share a year ago on $495 million to 65 cents a share on earnings of $379 million.
It said much of the slide was attributable to its exit from its unregulated business and its “repositioning” in the regulated market.
Mark F. McGettrick, Dominion’s chief financial officer, credited the winter weather for an additional 5 cents per share in earnings, however. At regulated Dominion Virginia Power, EBITA for the first quarter was $269 million.
PSEG
Public Service Enterprise Group reported a 21% increase in first-quarter earnings, with a profit of $386 million, or 76 cents a share, compared to $320 million, or 63 cents a share, for the same period last year.
The company’s 2013 results were hurt by restoration costs following Superstorm Sandy.
“We delivered on many fronts during the quarter,” CEO Ralph Izzo said. “I don’t need to tell you how cold it was this winter. The record low temperatures challenged our employees, our equipment and our markets.”
PPL
PPL Corp.’s first-quarter earnings slipped 24% compared to the same period in 2013, dropping from $413 million, or 65 cents a share, for 2013 to $316 million, or 49 cents a share. The results reflect $207 million in “special item charges,” most resulting from “adjusted energy-related economic activity.”
Operating results were rosier, with earnings from ongoing operations totaling $523 million, or 80 cents a share, a 15% increase over 2013 ($454 million, 71 cents a share).
“The unusually cold winter weather resulted in increased sales to customers in Pennsylvania and Kentucky, and our competitive generating plants in the PJM Interconnection operated well during the periods of high electricity demand,” CEO William H. Spence said.
AES
The weather hurt earnings at AES Corp., parent company of Ohio’s Dayton Power and Light Co. The company reported earnings per share of 24 cents on revenue of $4.26 billion, a drop of 3 cents from the year before on revenues of $4.15 billion. AES pointed to a 3-cents-per-share “negative impact from forced outages and lack of gas availability during the extremely cold weather in January at DPL.”
Earnings also suffered from a drought in South America, where the company has significant hydropower holdings.
The company recorded a $307 million charge ($0.41/share) for goodwill impairment at DPL in the fourth quarter of 2013, citing “lower than expected PJM cleared capacity prices for 2016/2017, lower expectations of future PJM capacity prices and lower projected energy margins.” AES bought DPL in 2011 for $3.5 billion.
Like many other utilities, AES has said it is going to concentrate on regulated business, and it is looking to sell generation assets. The company, which derives 75% of its earnings from outside the U.S., announced late last year that it was shedding assets in Cameroon, India and Poland. It also announced earlier this year that it will sell DPL’s generation fleet rather than spinning it off into an unregulated subsidiary.
Stakeholders approved a rule change to ensure zones don’t lose Auction Revenue Rights due to anomalies caused by storms or other extraordinary events.
The vote to revise the definition of Zonal Base Load was prompted by Superstorm Sandy in 2012. Storm-related outages produced ZBLs in the AE, JCPL, PSEG and RECO zones that were far lower than would have been expected under normal conditions, PJM’s Brian Chmielewski told the Market Implementation Committee.
PJM obtained a waiver from the Federal Energy Regulatory Commission in February to prevent the zones from losing a portion of their Stage 1A ARR allocations as a result of the muted ZBLs.
ARR allocations are based on zones’ base loads, defined as the lowest daily zonal peak load for the year ending Oct. 21 preceding the annual ARR allocation.
The revised definition allows PJM to ignore load figures resulting from “extraordinary circumstances,” resulting in “an abnormal reduction” in energy consumption. The new definition will require changes to the Tariff, Operating Agreement and Manual 6.
Stakeholders approved two initiatives to improve demand response measurement and verification (M&V) last week.
The Market Implementation Committee approved a problem statement to improve the M&V accuracy for emergency DR. PJM’s Pete Langbein told members the existing procedures, which use the hour before an event as the customer baseline (CBL), may be inaccurate for dispatches in the early morning and on days with multiple dispatches.
Langbein said members have also raised concerns about the:
Cumbersome administrative process to use an economic CBL, which requires an Electric Distribution Company review;
After-the-fact selection of CBLs for use in settlements; and
Use of economic CBLs for customers that primarily participate in the ancillary services market.
Residential DR M&V
Separately, the MIC also approved an issue charge that tasks the Demand Response Subcommittee with developing more accurate M&V methodology for residential demand response. The MIC approved a problem statement on this issue last month. (See PJM Seeks Better Data on Residential DR.)
PJM currently measures load reductions for much of its residential DR based on data that was compiled more than a decade ago in Maryland and New Jersey. PJM’s Shira Horowitz has said the data is no longer representative because of the growth of PJM’s footprint, changes in DR programs and increases in the energy efficiency of air conditioners and other appliances.
The old data were collected based on legacy “direct load control” (DLC) programs. Residential DR now includes use of smart meters and programmable thermostats.
The timetable for developing new M&V rules for residential DR is six months if only manual changes are required, and nine months if they entail Tariff changes requiring a filing with the Federal Energy Regulatory Commission.
