PJM added an Interregional Data Map to its website last week. The map shows actual and scheduled flow across interfaces along with Locational Marginal Prices. Green and red and arrows indicate whether power flows are economic or uneconomic.
CC’s Synchronized Reserve Performance Drops
Combined cycle generators’ performance in providing Tier 2 synchronized reserve has fallen by half since 2008, according to a new analysis provided to the Operating Committee last week.
In response to earlier stakeholder questions, PJM staff analyzed SR response rates since 2002 by generator type. They found that combined cycle units, which once had the best performance rates — averaging over 100% for all but one year during 2002-2008 — now is the worst performer, at below 60% (see chart).
PJM’s Tom Hauske, who presented the findings, said there’s “no obvious” explanation for the decline. “I assume it has something to do with how [plant operators] are optimizing their output now and they don’t have as much margin to move” when synch reserve events are called, he said.
While combined cycle rates have declined, the performance of hydro units and combustion turbines has been relatively constant, as have steam units, excluding a two-year jump in performance in 2010-2011.
Retrofits to Tighten Reserve Margins in 2014-15
Retrofits and other planned outages will make it challenging to maintain reserve margins in 2014 and 2015 and PJM will likely need to reschedule some outage requests as a result.
PJM’s Dave Schweizer briefed the Operating Committee last week on planned outages scheduled and anticipated for the two-year period, which will see 46 units totaling 7,725 MW of generation retire and 59 units totaling 25,890 take outages for retrofits.
PJM is awaiting retrofit/retirement decisions from the owners of 21 units totaling 3,456 MW.
The 2015 analysis shows the combination of scheduled and anticipated outages reducing generation below PJM’s targeted 15% reserve margin in May and September 2015, meaning officials will need to reschedule some shutdowns to months with more margin.
Projections also anticipate tight operations in May and September 2014.
“The key takeaway: If you’re a generation owner … please submit these (planned outage) tickets as soon as reasonably possible,” Schweizer said.
No Major Changes Seen from Temp Corrections
Steam generators that currently correct their capacity ratings to reflect ambient temperatures make changes averaging less than 1%, meaning new rules requiring corrections of all steam units should not have a major impact on PJM operations.
The largest change among the units that currently correct — representing 58% of PJM’s installed capacity (ICAP) — was 2%.
“At least for the units that already temperature correct, we’re not seeing a major change in their ICAP ratings,” PJM’s Tom Falin told the Planning Committee last week.
About half of PJM’s steam units already adjust their ratings although Manual 21 requires adjustments only for combustion turbines and combined cycle plants. Falin said the committee will be asked to endorse manual language adding the correction requirements for nuclear, coal and oil units as soon as January.
Revised Economic Data Reduces Load Forecast
PJM predicts summer peak loads will increase by about 1% annually over the next decade, with a 1.4% increase in 2014, according to a draft forecast outlined to the Planning Committee last week.
The 2014 load forecast reduces peak and energy forecasts from the 2013 report due to revisions to historical economic data and the addition to the PJM model of another year of load experience.
A restatement in federal economic data made “the recent recession a little less deep and the recovery a little faster than data used in last year’s forecast,” PJM’s John Reynolds told the committee.
The projected 2014 summer peak is 157,399 MW, an increase of 2,214 MW from this summer’s weather normalized peak of 155,185 MW.
The RTO summer peak is projected at 173,852 MW for 2024 (an annualized increase of 1%) and 180,137 MW in 2029 (0.9% per year).
Compared to the 2013 load report, the new forecast reduces the anticipated summer peak for the next delivery year (2014) by 1,318 MW (-0.8%); the next RPM auction year (2017) by 2,777 MW (-1.7%) and the next RTEP study year (2019) by 3,457 MW (-2.0%).
Individual zones are expected to see average annual load growth of between 0.4% (RECO) and 1.8% (DOM) over the next 10 years. Several zonal forecasts were adjusted to account for large, unanticipated load changes:
- AEP: The closure of the Ormet Corp. aluminum smelter in Hannibal, Ohio — the largest single load in PJM — reduced the summer peak by 370 MW in all years;
- APS: 80-120 MW were added to the summer peak to reflect expansion of hydraulic fracturing facilities;
- BGE: An “undisclosed project” currently under construction adds 120-315 MW to the summer peak;
- DOM: Data center construction adds 288-896 MW to the summer peak.
Assumptions for future load management also have decreased from the 2013 report, to 12,400 MW from 14,600 MW. Projected energy efficiency was reduced to 900 MW from 1,100 MW.
Winter peaks are expected to grow by 0.9% annually over the next decade (to 144,496 MW) and 0.8% over the next 15 years (148,423 MW). Individual zones are projected to grow by 0.3% (ATSI) to 1.7% (DOM) annually for the decade.
Reynolds and Paul McGlynn, PJM general manager of system planning, asked transmission owners for feedback on the projections in their zones. “PJM does not have a deep understanding of what’s going on in Richmond and Allentown and Columbus,” Reynolds said.
Economist James Wilson, consultant to the public advocates of New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia, questioned what he called the “exogenous adjustment” to the BGE projection.
“Does it make sense to increase the BGE zone based on new load given the chronic over forecast in that zone?” he asked. Despite PJM predictions of increasing load, Wilson added, “The peak in BGE has gone sideways since 2005.”
Wilson also questioned PJM’s authority to make changes based on anticipated load additions. Manual 17, he noted, refers to adjustments for “load that’s already been experienced.”
“The plain language of the manuals does not authorize this sort of adjustment,” Wilson said. The change, he added, “has the potential to contribute to an RPM price spike.”
“We have not interpreted the manual that way recently,” Reynolds responded. “PJM and members wanted this.”
“Maybe we need to do a manual cleanup” to address the discrepancy, he acknowledged.
State Briefs
DuPont Activates Solar Facility
DuPont started up a 548-kW solar installation on a former Superfund landfill site in Newport. The project, developed by Tangent Energy Solutions and owned by Greenwood Energy, had its solar panels supplied by DuPont Apollo, a DuPont subsidiary.
More: DuPont
ILLINOIS
Midwest Gen Coal Ash Suit Can Proceed
The Environmental Law and Policy Center’s suit against Midwest Generation can go ahead, a bankruptcy judge ruled. The group alleges groundwater pollution from coal ash at the Romeoville, Pekin and Joliet generating plants, now owned by NRG Energy. The suit was put on automatic stay when Midwest Gen filed for bankruptcy, a stay the judge has now lifted.
More: nwitimes.com
Exelon Disputes Byron Tax Assessment
Continuing a long dispute, Exelon appealed Ogle County’s $509 million tax assessment on its Byron nuclear plant, which the company says should be cut by half. Exelon paid $32 million in taxes on Byron this year.
More: SaukValley.com
MARYLAND
BGE Granted $106M; ROE Hike Denied
The Public Service Commission granted Baltimore Gas and Electric $106 million in distribution rate increases and reliability riders, cutting the company’s request by more than half and denying the higher rate of return the company had sought.
The $33.6 million distribution rate increase, effective Dec. 31, was only 41% of the request. For BGE’s proposed Electric Reliability Initiative, the PSC approved five of eight proposed five-year programs for a total expenditure of $72.6 million instead of $136 million. The return on equity for electricity operations was kept at the current 9.75%; BGE had asked for 10.5%.
More: Maryland PSC
NEW JERSEY
Senate Dems Want to Put RGGI to Voters
The Democrat-controlled Senate Environment and Solid Waste Committee approved a resolution (SCR146) that would have voters decide on a constitutional amendment to have the state return to participating in the Regional Greenhouse Gas Initiative, which Gov. Chris Christie pulled out of in 2011. A constitutional amendment would put the matter out of Christie’s hands. But Assembly Democrats are not seen likely to take up the resolution, if the full Senate passes it.
More: The Star-Ledger
Offshore Turbines Would Blunt Hurricanes
Massive wind farms offshore New Jersey and New York would have cut Hurricane Sandy’s winds by 65 mph and the accompanying storm surge by 21%, according to a Stanford University research team. The analysis assumed 70,000 offshore turbines capable of generating 300 GW. A similar “wall of turbines” offshore New Orleans would have reduced the power of Hurricane Katrina, the team said.
More: Climate Central
NORTH CAROLINA
Duke Puts 625-MW Plant Online
Duke Energy Progress put in service its new 625 MW L.V. Sutton combined-cycle gas plant at Wilmington. The plant, with modern pollution controls, replaces a 59-year-old 575 MW coal plant that Duke retired. The company soon will start deconstructing the coal units and “effectively closing” the coal ash basins, which are the subject of a lawsuit by the Southern Environmental Law Center for leakage that allegedly has damaged groundwater and Lake Sutton fish.
More: Duke Energy
OHIO
Final Hearing in Electric Competition Debate
In its final public hearing as it contemplates whether to change the state’s retail electricity regime, the Public Utilities Commission heard from competition advocates supporting expansion of deregulation and from consumer advocates warning that customers need regulatory protection. The PUC’s examination of the issue began last year and has no timetable for completion.
More: The Columbus Dispatch
Wind Project Delayed Again
Legal disputes are creating more delay for the proposed 200 MW Buckeye Wind Project. Everpower Renewables had hoped to start building in the spring, but challenges from Union Neighbors United, Champaign County and others continue to mean uncertainty and postponement of construction.
More: Springfield News-Sun
PENNSYLVANIA
NRC: No ‘Incident’ at Beaver Valley
The Nuclear Regulatory Commission backed off its initial finding that FirstEnergy’s Beaver Valley station in Shippingport required extra monitoring because of its performance in a mock attack in April. In what an NRC spokesman described as an unusual decision, the agency concluded after further discussion with the company that no security-related incident had occurred.
More: BloombergBusinessweek
Abruzzo Sworn in as DEP Secretary
The Senate confirmed Christopher Abruzzo as secretary of the Department of Environmental Protection, where he had been acting secretary since Gov. Tom Corbett appointed him in April. Previously he was deputy chief of staff in Corbett’s office. His confirmation was preceded by a small firestorm following statements about climate change at his confirmation hearing.
More: The Patriot-News
WEST VIRGINIA
PSC OKs Amos Transfer, Defers Other Moves
The Public Service Commission approved American Electric Power’s plan to transfer complete ownership of its 2,900-MW John Amos plant to AEP’s West Virginia unit, Appalachian Power. ApCo already owned all but 867 MW. The commission deferred a ruling on the company’s proposal to transfer half-ownership of the Mitchell plant to ApCo and on its request to merge AEP’s Wheeling Power with ApCo.
Virginia regulators had already rejected the Mitchell plant deal, and the PSC said there was no reason for it to rule on it now. The PSC said it deferred action on the merger because the Amos transaction alone would resolve ApCo’s generation capacity deficit until at least 2015.
More: The Charleston Gazette
Wind Farm Has Bat Conservation Plans
The Beech Ridge Energy wind farm in Greenbrier and Nicholas counties is the first wind project to implement a habitat conservation plan for Virginia big-eared bats and among the first to implement such a plan for the Indiana bat. A Fish and Wildlife Service permit containing the plans for the 100 MW project covers 67 existing turbines and up to 33 more. Beech Ridge is a subsidiary of Invenergy.
More: The Register-Herald
Federal Briefs
At least 29 major companies are incorporating a carbon price into their long-range planning, according to a report from the environmental data company CDP. “It’s climate change as a line item,” said CDP North America President Tom Carnac. Among the companies identified are American Electric Power and Duke Energy as well as oil majors such as ExxonMobil.
More: The New York Times
Co-ops Members Can Get Loans
Customers of rural electric cooperatives can apply next year for federal loans to make energy efficiency improvements. The Agriculture Department’s Rural Utilities Service previously made loans only to cooperatives for infrastructure projects. Under a policy change, the service will make $250 million in funding available for customer projects in 2014.
More: Des Moines Register
Renewables Target Upped to 20%
President Barack Obama ordered the federal government to obtain 20% of its electricity from renewable sources by 2020, nearly triple the current 7.5% goal. The American Coalition for Clean Coal Electricity said the order was impractical and would raise electricity costs.
More: AP
Eagles Now Fair Game
In a decision sought by the wind power industry, the Obama administration issued rules that allow wind-power companies to get permits to kill and harm bald and golden eagles for up to 30 years. Environmentalists oppose the rule as “a blank check” for the so-called takings and said they would challenge it.
Industry Growth Cancels Coal Closings: Report
All the carbon emission reductions from closing coal plants may be canceled out by the large amount of new industrial activity fueled by natural gas, according to a report from the Environmental Integrity Project. The organization says the Environmental Protection Agency should regulate industrial greenhouse gas sources.
More: Huffington Post
Company Briefs
Ontario-based Algonquin Power is buying the remaining 40% of a 400-MW U.S. wind power portfolio from Gamesa Wind US for about $117 million. Algonquin already holds 60% of the three projects, which include Minonk in Illinois, Sandy Ridge in Pennsylvania and Senate in Texas.
More: Heraldonline
Executives Move Up at Dominion
Dominion promoted executives to head two business units, effective Jan. 1. Robert M. Blue, now a vice president, will become president of Dominion Virginia Power and Diane Leopold, vice president at Dominion Transmission, will become president of Dominion Energy. Among other changes, Dominion also named P. Rodney Blevins to senior vice president and chief information officer and Katheryn B. Curtis to senior vice president for power generation.
More: Dominion
Duke Names Plant for Jim Rogers
Duke Energy renamed its Cliffside Steam Station after former President and CEO Jim Rogers, who will retire as board chairman this month. The 1,375-MW James E. Rogers Energy Complex comprises two coal units. Because of Rogers’ efforts, 825-MW Unit 6 is “one of the cleanest, most efficient coal units in the world,” the company said.
More: Duke Energy
Duke – Union Tension Prompts NRC Review
The Nuclear Regulatory Commission is reviewing Duke Energy’s safety plans at the shuttered Crystal River plant due to concerns over a possible strike by the plant’s unionized workers. Duke’s contract with 1,800 members of the International Brotherhood of Electrical Workers expired last week. The IBEW represents operations, maintenance, chemistry, radiation protection and warehouse personnel.
More: Tampa Bay Times
Dynegy Closes on Coal Plants
Houston-based Dynegy closed on its purchase of five Illinois coal plants from Ameren, which is focusing more on its regulated businesses. The closing came about two weeks after Dynegy got a five-year pollution control waiver from the Illinois Pollution Control Board for the Ameren plants. The deal had hinged on that waiver.
More: Daily Herald
Generators: Ban Planned DR
PJM generators told the Federal Energy Regulatory Commission last week that it should go beyond PJM’s qualification rules for demand response providers — with some proposing that planned DR resources be banned from the capacity market altogether.
Seven generators and two generator trade groups filed comments last week following a FERC technical conference Nov. 13 on PJM’s proposal to require “Sell Offer Plans” certified by the DR company officers and resource-specific data in some zones. Only a single Curtailment Service Provider, Comverge Inc., submitted comments opposing the rules, filed by PJM Aug. 2.
Support from Market Monitor
The generators — Calpine, Exelon, PSEG and four Ohio utilities — said the overwhelming stakeholder support for the proposed rules and the silence of most DR providers means the changes are reasonable and should be approved.
PSEG, the PJM Power Providers trade group and the Ohio utilities — FirstEnergy, AEP, Dayton Power & Light and Duke-Ohio — went further, saying FERC should order PJM to take tougher action against DR than the RTO could get through the stakeholder consensus process.
The failure to do so will allow speculative DR offers to continue suppressing capacity market prices and threatening reliability, they said. “The issue here is not `existing generation versus DR’ as some may seek to cast it,” the Ohio utilities wrote. “The issue is real versus speculative capacity resources.”
The generators have an ally on this issue in the Market Monitor, which called the PJM proposal a “compromise that does not solve the issue and which will lead inevitably to the need for further changes.”
Rules Vague
Comverge insisted in its filing that PJM’s rules are vague and unnecessary and will depress DR’s growth, echoing comments the company’s vice president of regulatory and market strategy, Frank Lacey, made at the hearing.
“PJM has neglected to provide any objective substantive criteria upon which it will determine the adequacy of DR Sell Offer Plans,” the company wrote. Allowing PJM “complete discretion” in accepting or rejecting the DR Sell Offer Plans violates the Federal Power Act’s prior notice requirements, the company said.
Ohio Utilities’ Filing
FirstEnergy and Duke protested the PJM proposal as insufficiently tough in a joint filing in August. For the post-conference comments, the two companies teamed up with DPL and AEP with a joint filing that cited analyses by a former FERC economist and a former PJM manager.
Former PJM transmission planning manager Scott Gass said in an affidavit that the RTO needs resource-specific information to identify locational delivery areas, which are priced as separate regions in the base auction. Gass performed an analysis of the ATSI transmission zone that he said shows that a reliability event that could be solved with 400 MW of targeted DR would require twice as much if the resources’ precise location cannot be identified.
The utilities also filed an affidavit from former FERC economist David Hunger, who analyzed the impact of “non-physical” DR offers on capacity prices. Because of the steepness of the demand curve, Hunger said, “a relatively small increase in the supply due to non-physical supply offers can result in a very large drop in the RPM clearing price.”
PJM’s Proposed Changes
The proposed Tariff changes require that officers of CSPs certify that they have a “reasonable expectation” of delivering the demand resources offered into the base Residual Auction. Comverge said the officer certifications are vague and give PJM too much discretion in enforcement.
The rules also set conditions under which PJM will flag transmission zones in which CSPs are claiming high levels of DR. CSPs offering resources from those zones will have to provide detailed site-specific information.
Comverge said the requirement creates a barrier to entry and is not motivated by reliability concerns. “Clearly, PJM is not basing its tariff changes on reliability concerns, because the changes proposed do not involve any sort of reliability analysis; they just say `X% of Demand Response is too much,’” Comverge said.
Generators have their own complaints about the criteria for flagging zones, saying they are too lenient.
Additional Changes Sought by Generators
The Ohio utilities said the commission should require DR to offer into the day-ahead energy market as is required of generators. The lack of such a requirement obscures the cost of energy in high demand periods, resulting in higher overall production costs and uneconomic dispatch of DR, the utilities said. A must-offer obligation would allow PJM operators to dispatch DR economically rather than as a block.
PSEG said PJM should require customer-specific information for all DR, not just those in flagged zones. The company also said PJM should either “tighten up the proposed DR Sell Offer Plan requirements” or be ordered to “enforce the Tariff provisions that already exist – which would require a contract between the CSP and its customers for the committed load reduction prior to the BRA.”
The Tariff requires that a “Capacity Market Seller may submit a Sell Offer for a Capacity Resource in a Base Residual or Incremental Auction only if such seller owns or has the contractual authority to control the output or load reduction capability of such resource.”
The PJM Power Providers, an organization representing more than a dozen generators and headed by the former chairs of the Pennsylvania and Michigan utility commissions, told FERC that the changes are needed but that “there is more work to be done” and questioned whether PJM should reevaluate “the participation of Planned DR in RPM.”
Market Monitor: Enforce Current Rules
The Market Monitor said PJM has not properly enforced its rules requiring that Planned DR must be a specific, physical resource. “This rule requires identification of a specific customer and a specific site, but does not require a contract,” the Monitor wrote.
“Under the current application of the rules, DR providers may not have identified Planned DR customers, may not have clear plans for implementing DR measures for these customers, and may not receive commitments from new customers until relatively close to the delivery year and well after the RPM BRA is run for that delivery year.
“PJM’s approach would not address the problem as well as the preferred option to enforce the existing rules and modify the existing rules to make explicit the obligation of cleared BRA resources to provide physical resources in the delivery year.”
What Will FERC Do?
The commission will weigh PJM’s filing against Congress’ direction in the 2005 Energy Policy Act that “unnecessary barriers to demand response participation in energy, capacity and ancillary service markets shall be eliminated.”
In ordering the technical conference, the commission said the proposed changes had not been proven just and reasonable and might be discriminatory. FERC staff expressed similar skepticism at the technical conference.
But Republican Commissioners Philip Moeller and Tony Clark have indicated they are leaning in support of PJM’s changes and Comverge’s arguments lacked the amplification the multiple generators provided in PJM’s support.
Comverge’s argument that the requirements are onerous could be undercut by the fact that PJM found “nearly all DR Providers” that offered into the 2013 BRA submitted adequate Sell Offer plans.
The rules will automatically take effect unless FERC rules by March 2 with an order modifying them. Another option is that the commission could delay a ruling in order to evaluate them along with other DR changes making their way through the stakeholder process. (See Members Deadlock on DR in Capacity Auctions.)
Sounds of Silence as Monitor Solicits Feedback
No one spoke up when Market Monitor Joe Bowring opened the floor to stakeholders in the Monitor’s annual Advisory Committee meeting Friday.
No matter. Bowring and his staff took the opportunity to renew their case for eliminating “sham scheduling” and changing PJM rules on opportunity costs.
Opportunity Costs
The Monitor told the more than 20 members and PJM staffers who attended that he will seek Federal Energy Regulatory Commission approval for changes to the opportunity cost calculations because stakeholders have been unable to agree on a solution.
The Monitor says current methods of calculating opportunity costs for some markets and services are “inconsistent and inaccurate” and that there are no Tariff definitions for costs for black start units, reactive services and synchronous condensing.
Bowring said he plans to file proposed changes with FERC next year but is “very much open to discussion” with stakeholders beforehand.
‘Sham Scheduling’
Bowring also reiterated his call for an end to so-called “sham scheduling.” The Market Implementation Committee agreed in April to investigate the Monitor’s concern but the issue hasn’t surfaced since then. (See MIC to Probe “Sham Scheduling”) The MIC’s 2014 work plan shows the issue scheduled for discussion beginning next month.
PJM prices transactions with external balancing authorities based on the source and sink identified on the NERC eTag.
The Monitor said some traders could be manipulating PJM’s interface pricing points by breaking schedules into multiple “back-to-back” transactions that hide the actual source of generation.
Monitoring Analytics’ John Dadourian gave an example of a New York-to-PJM transaction that should result in a settlement of $16. Done by separate transactions through the other regions, the total settlement involved would be $37, Dadourian said.
In another example, a trade from Ontario to MISO, which should result in a net settlement of $5, instead totals $20 after separate transactions involving PJM. Such transactions also have loop-flow impacts of the kind that led the New York ISO to ban certain paths in 2008, Dadourian said.
To stop these transactions, the monitor recommends eliminating the Ontario interface price and requiring scheduling of complete paths, instead of “patching together” transactions with separate eTags.
Priorities
In answer to a stakeholder question at the end of the session, Bowring said the Monitor’s biggest priority is fixing problems with the capacity market — issues now before stakeholders and FERC. He also cited concerns over up-to congestion trades, allocation of uplift charges and scarcity pricing.