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.
Members last week approved rule changes to reduce “adder” payments to frequently mitigated generation units (FMUs), after rejecting a joint proposal from the RTO and the Independent Market Monitor.
The PJM-IMM proposal won only 43% support in a vote of the Market Implementation Committee. It would have limited adders to units whose net revenues are not covering their avoidable cost rate (ACR).
Three generator-backed proposals won at least 60% support from the MIC and are eligible to be considered by the Markets and Reliability Committee on May 29.
Topping the voting with 65% support was a proposal (Package G) to cap adders at 12% of the gross Cost of New Entry (CONE). It will be the primary proposal considered by the MRC — where, unlike the MIC, the voting will be sector-weighted.
Another proposal (Package H) 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. The units currently receive $30/MWh, or 15% of the cost offer, not to exceed $40. The revision would eliminate the 15% option, leaving only the $30 adder.
The final proposal (Package F prime) would restrict the adder to a percentage of the cost offer for units with more than 500 run hours in a rolling 12-month calculation period. The cap would be 15% for Tier 1 units (60% – 70% mitigated hours), 20% for Tier 2 units (70% – 80% mitigated hours) and 25% for Tier 3 units (over 80% mitigated hours). Adders would be unchanged for units with less than 500 run hours.
Packages H and F prime will be considered only if the primary proposal fails to win a two-thirds sector-weighted vote at the MRC.
Market Monitor Joe Bowring says the adders are no longer needed because of PJM’s capacity market. Had the PJM-IMM proposal been in effect in 2013, PJM said it would have reduced the number of units receiving adders from 112 to only 28 — 23 of which are scheduled to retire. (See Increased FMU Costs Lend Urgency to Fix.)
But Dave Pratzon of GT Power Group, which represents generators, said the PJM-IMM proposal was “too extreme a screen.”
“It’s like a homeowner saying to their mortgage company, ‘You should be happy because I’m covering the insurance and taxes. Don’t worry about the principal and interest,’” he said. “You can’t stay in your house that way. A unit owner can’t run their unit that way.”
Bowring said the adders were intended to ensure generators earn enough to cover their going-forward costs. “It’s not intended to provide a return on fixed costs,” he said.
The failure of the PJM-IMM proposal was not a surprise. It won support from little more than one-quarter of those polled in a generation-heavy MIC subgroup that has been considering alternatives.
Acknowledging they were taking what several called “a leap of faith,” stakeholders last week endorsed PJM’s plan for cutting uplift and capturing reserve costs in energy prices.
The Market Implementation Committee voted 118-48 in favor of the PJM proposal, with 37 members abstaining.
While all who spoke said they endorsed the goal of reducing uplift, some stakeholders said they were concerned that the plan would unfairly penalize load and potentially increase overall costs.
It would increase day-ahead and real-time reserve requirements when hot- or cold-weather alerts or max emergency generation alerts are issued for the RTO or for either the Mid-Atlantic-Dominion or Mid-Atlantic regions.
The adder for day-ahead reserves would be set at 3% of forecasted load, boosting reserves from 6.27% to 9.27%. The real-time reserve adder would be equal to the default Mid-Atlantic-Dominion (MAD) synchronized reserve requirement of 1,300 MW.
The increased reserves would be reflected in market clearing engines, ensuring that the costs go into Locational Marginal Prices and not uplift.
The adders would be reduced or cancelled if scheduling the additional resources causes difficulty managing the area control error (ACE).
Simulation Not Possible
PJM had hoped to provide members a simulation to illustrate the impact of the changes but was unable to do so. “We don’t have a system that can create real-time [simulations] in the granularity that real time occurs,” said Adam Keech, director of wholesale market operations. Although PJM calculates LMPs every five minutes, the “perfect dispatch” tool that would be used for the simulation can only calculate by the half-hour.
Instead, officials showed the MIC a range of impacts the new practices might have had on eight days in January that resulted in almost $343 million in uplift.
The projection assumed that lost opportunity costs, a component of uplift, would increase by the same percentage that total uplift decreases. Keech said that assumption was an “intuitive” guess, acknowledging, “It’s probably not a one-to-one relationship.”
On Jan. 27, the worst day of the month, uplift totaled $76 million while LOC was $2.1 million. If the change offset 5% of uplift, it would have resulted in net savings of $3.7 million. If the change reduced uplift by 50%, the savings would have been $37 million.
Keech said the impact of the changes will vary daily depending on “how much uneconomic generation … we have on the system that we can soak up.”
MRC Vote
The Markets and Reliability Committee will vote on the changes May 29. But because the new procedures involve only changes to Manual 11, PJM could implement them unilaterally even without stakeholder support.
PJM officials said they plan to implement this “short-term” fix in time for summer and consider other long-term changes that would entail Tariff changes later.
Dan Griffiths, executive director of the Consumer Advocates of PJM States (CAPS), said he wanted to see more examples to be convinced of PJM’s assurances that the changes will only capture actions PJM operators are already taking when weather emergencies mandate “conservative operations.” He said he was concerned the new rules could result in PJM invoking shortage pricing more often.
“It’s a leap of faith we’re being asked to take,” said Dave Mabry, of the PJM Industrial Customers Coalition. “We’re just not sure that we’re [not] going too far.”
Worst Uplift Ever
Keech said PJM was responding to concerns voiced by many stakeholders. “We’re coming off a winter with the worst uplift we’ve ever seen,” he said.
Jung Suh of Noble Americas said PJM’s proposal was a reasonable solution to a major problem. “We’ve seen the uplift charges this winter. It was real. It was painfully real.”
Suh said uplift over the summer will be lower than the past winter, allowing an opportunity to test the effectiveness of the new procedures under less stress. “This makes sense,” Suh said. “I don’t think we should go into the winter with an untested proposal.”
Louis Slade of Dominion said his company could not support the changes because it shifts cost allocation in a way “that’s not in line with cost causation.”
David “Scarp” Scarpignato of Direct Energy agreed, saying it was unfair to charge load for costs it didn’t cause. He noted that synchronized and primary reserves are intended to replace units that trip off line. “That’s why [reserve targets] are based on the largest single contingency,” he said.
“I do fear that the short-term solution becomes the long-term solution when there’s no consensus on a long-term solution,” he added. “… We’ve seen that a bit.”
Keech said changing the cost allocation would require a Tariff change and could not be completed before the summer.
An unplanned shutdown of the Salem 1 nuclear generating facility Wednesday was the third for the PSEG-operated plant in Lower Alloway Township, N.J., in less than a month.
Salem 1 Nuclear Plant (Source: PSEG)
Nuclear Regulatory Commission regulations call for stepped-up oversight for reactors that have three unplanned shutdowns within a nine-month period. The latest incident occurred when the protection system for the main generator activated after detecting an unexpected voltage change. NRC spokesman Neil Sheehan said the cause of the shutdown is still under investigation but added shortly after that the plant was a “in a safe condition.”
Salem 1 tripped offline April 8 after the breakdown of a condensate pump. It also tripped April 13 due to a faulty generator protection relay, a switch that protects the generator from changes in voltage. Salem 1 was licensed in 1976. Salem Unit 2 is offline for refueling.
Exelon’s Limerick Generating Station got a thumbs-up from the Nuclear Regulatory Commission in its 2013 annual review. The results mean the station will receive a “normal” level of oversight by NRC inspectors – which still means 5,440 hours of inspection per year.
“We take very seriously the task of stepping back on a regular basis to size up plant performance,” said Bill Dean, NRC’s Region 1 administrator. “Limerick, by virtue of its performance in 2013, will receive our routine — though still substantial — battery of inspections,” Dean said.
Energy Future Holdings Corp., the company that emerged from a leveraged buyout of Texas giant TXU, has filed for bankruptcy after failing to find funding for $40 billion in debt.
The company filed for Chapter 11 protection, saying it has reached deals with some of its largest creditors and that it aims to emerge from protection with 11 months. Investors took TXU private in 2007 with $32 billion in cash and $13 billion in assumed debt. But a series of bad positions, including being on the wrong side of plunging natural gas prices, doomed the company.
Rates for Commonwealth Edison residential customers will go up 20% starting in June, as bills start to reflect a new charge for supply during peak-demand hours. The new energy charge of 7.596 cents per KWh compares to the 5.52 cents residential customers now pay.
The charge reflects prices secured during a power-generator auction held last month by the Illinois Power Agency. Those prices, in turn, reflected higher-than-usual future winter costs, based in part on this past winter’s experience. Different classes of residential customers, such as apartment or condo residents, or single-family homes, may pay slightly different rates. ComEd executives have said the energy-price increase will boost the average monthly bill to about $82.
A flaw around a tube in the reactor’s vessel head at FirstEnergy’s Beaver Valley Unit 2 is being fixed with a welded patch, according to the company and the Nuclear Regulatory Commission. The microscopic flaw was found during the unit’s refueling procedure. An NRC spokesman said the flaw was not a safety threat, but could have grown into one if not addressed.
The reactor pressure head is the original, dating back to 1977. It is scheduled to be replaced in 2017, according to company officials.
Dominion Resources has added to its growing solar portfolio by buying two solar projects in Tennessee’s McNairy County, near the town of Selmer. The two fixed-tilt photovoltaic (PV) plants, named Mulberry Farm and Selmer Farm, will generate 16 MW when completed. The projects, which are being developed by Chapel Hill, N.C.-based Strata Solar LLC, will sell its output to the Tennessee Valley Authority.
Dominion has 41 MW of solar operating in Connecticut, Georgia and Indiana and 139 MW under construction in California.
Dominion Considering License Extensions for Nuke Plants
Dominion Resources is considering seeking a second 20-year license extension for each of its six nuclear units in Virginia and Connecticut. The six already received 20-year extensions atop their original 40-year operating licenses. This would extend their service lives to 80 years. Without the extensions, the plants’ licenses would expire between 2032 and 2045.
“We believe it is possible to relicense these units for another 20 years of safe operations,” said Rick Zuercher, a Dominion spokesperson. The average age of the 100 operating U.S. nuclear plants is 34.7 years, according to Nuclear Regulatory Commission spokesman Scott Burnell.
Dominion’s four reactors in Virginia produce 42% of the electricity used by Dominion Virginia Power’s nearly 2.4 million customers. The company will need approval from both the NRC and the state Corporation Commission for the extensions in Virginia.
With PJM planners nearing a proposed fix for the Artificial Island stability problem, the issue of who will pay for the project took center stage last week. Delaware regulators were not happy with what they heard.
Paul McGlynn, general manager of system planning, presented the Transmission Expansion Advisory Committee with preliminary cost allocation examples on the two least expensive projects among 10 finalists.
The cost of a $240 million proposal by Exelon and Pepco Holdings Inc. to add a 17-mile 500-kV line paralleling an existing 500-kV line from Red Lion to Hope Creek would be spread among two dozen transmission zones and merchants. The Jersey Central Power & Light zone would be responsible for about 27% of the project, with the Atlantic City Electric zone picking up almost 20%. No other zone was as high as 8%.
In contrast, LS Power’s $234 million proposal to run a 230-kV line across the Delaware River to a new or expanded substation on Delmarva Peninsula would be assigned entirely to the Delmarva Power and Light (“Delmarva”) zone, McGlynn said.
John Farber, of the Delaware Public Service Commission, said he couldn’t understand how Delmarva would be wholly responsible for a project meant to address stability problems in New Jersey. He said the assessment would boost total network transmission costs for Delmarva by 20%.
Farber requested that PJM provide cost allocations for all the projects still under consideration so those who would have to pay could use it to “assess PJM’s decision.”
McGlynn defended the allocation. “The flow on that line [would be] from Salem to Silver Run [Delaware] all year long,” he said.
McGlynn said the cost allocation, which will follow methodology approved by the Federal Energy Regulatory Commission, will not be a factor in determining which project is selected.
Just and Reasonable?
Sharon Segner, of LS Power, said PJM should consider Delmarva’s concerns and whether the RTO’s choice produces just and reasonable rates. “There may be some wiggle room in terms of working with Delaware on the cost allocation,” she said. “It would be worthwhile to be creative.”
The LS Power proposal is the lowest cost option, according to an analysis presented to the TEAC in April. The Exelon-PHI proposal was the second cheapest. (See Planners Near Artificial Island Pick.)
McGlynn also presented the TEAC last week with the results of market efficiency studies that showed neither the southern Delaware crossing nor the line to Red Lion would produce sufficient savings to be a consideration in the selection. The two projects showed benefit-to-cost ratios of 0.25 and 0.15, respectively, well below the 1.25 threshold for market efficiency projects.
PJM has scheduled a special TEAC meeting for May 19 to share information on how the 10 finalists fared in several key areas, including cost, project complexity, siting and permitting.
After receiving feedback from stakeholders, another special meeting will be held June 16 during which PJM will discuss its final recommendation. “I wouldn’t expect, necessarily, a recommendation on the 19th,” McGlynn said. “I expect a recommendation on the 16th.”
The PJM Board of Managers is expected to consider the recommendation at its July 22 meeting.
Artificial Island is the home of the Salem and Hope Creek nuclear plants in Hancocks Bridge, N.J. Five utilities and three independent developers made more than two dozen proposals in PJM’s first competitive transmission project under FERC Order 1000.
FERC Rejects Arbitrage Fix; OKs Most of DR Changes
By Rich Heidorn Jr. and Ted Caddell
PJM yesterday opened the 2017/2018 Base Residual Auction amid modest hopes among generators that the RTO’s rule changes will cause a rebound in prices.
Last year’s capacity auction saw big price drops in most of PJM, compounding the woes of generators, whose energy revenues have been suppressed by cheap shale gas.
PJM stakeholders approved several major changes in an attempt to bolster the capacity market, including a cap on imports and limits on demand response. But lackluster load growth and auction parameters that suggest there may be less price separation this year than last have tempered expectations.
Late Friday, the Federal Energy Regulatory Commission 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 related story, PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)
2013 Results
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.
Over the objections of consumer advocates and others, FERC 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.)
The cap represents a 17% reduction from the imports that cleared in 2013. However, external resources can win an exception to the limits if they are pseudo-tied; have confirmed, firm long-term transmission service; and accept the same must-offer requirement as internal resources. PJM’s planning parameters show that only 1,524 MW of the 6,499 MW are available after 4,777 MW in exceptions.
FERC also 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) that a PJM simulation suggested could increase capacity revenues by $1 billion annually. (See FERC OKs Limits on DR in Capacity Auction.)
Utility Execs Not Excited
In earnings calls over the last two weeks, executives of PJM companies praised the RTO’s rule changes but said they didn’t expect a dramatic rise in prices.
AEP CEO Nick Akins predicted RTO prices of $80 to $100 but added, “But who knows? I mean … the way this capacity construct works … things happen all the time.” Akins’ prediction is in line with that from UBS Securities, which predicted in February that RTO prices will rebound to $80 with MAAC flat at $120.
FirstEnergy CEO Tony Alexander told analysts he was encouraged by these “modest reforms” but more excited that “momentum is growing for changes that can truly help” such as a premium for having fuel on-site, which could boost nuclear and coal plants.
“I don’t think any of the rules currently approved are going to move the auction substantially,” added Leila L. Vespoli, FirstEnergy’s executive vice president of markets.
FirstEnergy President Donald R. Schneider said the “wildcard” will be the volume of offers from new generation in the interconnection queue.
PSEG CEO Ralph Izzo, however, said it is the actions of DR providers that may have more impact. “Really, a large part of the auction turns on what you expect for DR,” he said. The volume of cleared DR dropped 16% last year over 2012.
PPL CEO William Spence said there are too many variables to make a prediction on prices.
“There are a lot of moving parts, a lot of modifications have been made. There is a lot of kind of noise out there around the residual auctions and so forth,” he said. “So I think for this year at least, we are not going to put out an expectation around where we expect RPM prices to settle out, because there is a lot more uncertainty, in our view, coming into this auction than we have seen in past auctions.”
Spence said neither the auction results nor the spike in energy prices over the winter would influence the company’s long-term strategy. The company is reportedly considering selling its generation assets.
“We continue to have, as our No. 1 priority, the aggressive cost control and optimizing the dispatch of our plants,” he said. “At the same time, we do continue to consider other options that could enhance value. There is no particular data point or viewpoint of forward prices that we are waiting for or that would substantially impact our thought process around strategic options for that business.”
IPP Views
Among independent power producers, Calpine was downbeat while NRG was more positive.
Calpine President and Chief Operating Officer John B. Hill said the company has a “flattish to the modestly down view” of this year’s auction prices. “PJM has pushed forward some very strong rules … but we don’t have super high expectations for the auction this year,” he said.
NRG Energy’s Chief Operating Officer Mauricio Gutierrez was a bit more optimistic. “The combined effect of higher requirements and limits on demand response, the limits on capacity imports and the significant levels of un-cleared coal megawatts are positive signs in PJM,” he said.
Load Forecasts
PJM’s load forecast, released in February, predicts the RTO’s summer peak growing almost 7,000 MW to 164,195 in 2017, a 4.4% increase.
PJM predicted growth of 80 to 120 MW in APS from hydraulic fracturing and a 288- to 896-MW boost in the Dominion zone from new data centers. An undisclosed project under construction is forecast to add 50 to 195 MW to BGE’s summer peak beginning in 2017. Peak demand in the AEP zone was reduced by 370 MW, reflecting the loss of an aluminum smelter.
CETO/CETL ratios
PJM’s planning parameters report noted that planners had added three Locational Deliverability Areas (LDAs) — ComEd, BGE and PPL — to the nine modeled in last year’s auction.
Prior to each BRA, the Capacity Emergency Transfer Objective (CETO) and Capacity Emergency Transfer Limit (CETL) are calculated for each of 27 potential LDAs to determine whether separate demand curves should be modeled for them to ensure reliability.
The MAAC, EMAAC and SWMAAC LDAs are always modeled separately.
LDAs are also modeled separately if the CETL is less than 1.15 times its CETO or the LDA had a locational price adder in any of the three prior base auctions.
PJM can also model LDAs separately if it believes it necessary for reliability.
PJM said it would model the ComEd, BGE and PPL LDAs separately for the first time because of concern over generation retirements. The RTO said it wanted to “proactively identify locational supply concerns before they actually occur.”
PJM said most CETL values are about equal to or slightly higher than last year’s auction. The exception is the Pepco LDA which dropped to 5,208 MW, a reduction of 22% from last year, due to generator retirements.
The PS, DPL and SWMAAC zones showed the lowest CETO/CETL ratios, all below 1.4.
