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 week’s newsletter for a full report.
3. PJM Manuals (9:15-9:30)
Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance (QA)
Impacts: Defines times when interconnection request information will be exchanged and studied; Reinforces JOA requirements to impose the applicable study criteria; Describes Transmission Service Request studies to be performed.
Impact: Changes section 6.3 to increase penalties for resources that fail to provide assigned amounts of Tier 2 Synchronized Reserve. Changes section 5.2.6 to clarify the requirements that must be satisfied in order for wind resources to be eligible to receive Lost Opportunity Cost (LOC) credits.
4. ENERGY MARKET UPLIFT TASK FORCE (EMUSTF) (9:30-9:40)
Members will be asked to approve revisions to the Energy Market Uplift Senior Task Force charter. The MRC created EMUSTF May 30 to develop ways to minimize energy market up-lift charges and methodologies for allocating make-whole payments (See MRC Approvals 5/30/13.)
The proposed changes would incorporate into the charter the scope originally assigned to an MIC subgroup on Day-Ahead Reliability and Reactive Cost Allocation (DARRCA). The DARRCA group met nine times from December 2012 through October 2013 and was creating solution packages when it decided to combine the issues of the group into EMUSTF.
The volume and magnitude of changes PJM is attempting to impose on demand response raise the question of whether the high-flying sector is still a growth business or one in retreat.
Comverge Inc. sees the industry as under an assault that threatens its growth. “The Commission should not allow PJM to use [shortcomings of the capacity auction] as an excuse to impose anticompetitive measures that will very likely arrest any growth in demand resource participation in its capacity market,” the company told the Federal Energy Regulatory Commission in a Dec. 3 filing.
PJM officials insist they are acting only to ensure reliability, fairness and operational flexibility. Generators echo PJM’s concerns, though their own rivalry with DR cannot be denied: With demand flat, DR market share gains come at generators’ expense.
Whatever the motivations, there’s no doubt that if PJM prevails in its plans, demand response will undergo a dizzying number of changes:
The volume of limited DR clearing in the annual capacity auction could be reduced by as much as two-thirds.
Many resources will be required to dispatch in 30 minutes, down from the current two-hour default.
Curtailment Service Providers will be required to provide more detail to support planned resources (and planned resources could be banned altogether, if some generators get their way).
Emergency energy prices would be cut by as much as 39%.
DR received a boost from Congress in the 2005 Energy Policy Act, which barred “unnecessary barriers” to DR participation in energy, capacity and ancillary service markets. The Federal Energy Regulatory Commission’s Order 745 allowed DR payment of full locational marginal prices beginning in April 2012.
But with its growth raising questions about market saturation, and with low gas prices pinching generator margins, DR has found itself increasingly on the defensive.
Both DR offers and cleared MWs declined in ISO New England and PJM’s capacity auctions this year. DR participation also has declined in NYISO.
Demand resources offered declined 27% (and cleared DR dropped 16%) in PJM’s 2013 base capacity auction versus 2012. The Market Monitor said the decline was the result of low prices, while Comverge blamed it on the “chilling effect” of PJM’s new rules requiring more documentation of planned resources.
Demand response’s participation in ISO New England’s forward capacity market declined this year for the first time ever, with cleared offers dropping 24% from 2012.
UBS Investment Research attributed the reduction to the imposition of ‘must offer’ rules similar to those for generators. Former EnerNOC executive Jim Bride also cites the must-offer rules, along with other changes approved by FERC in January (ER12-1627) — what he called “onerous” data requirements and the elimination of the capacity price floor in 2017.
“Many of the players from several years ago have left the market or substantially pulled back,” Bride, now president of Cambridge-based consulting firm Energy Tariff Experts LLC, wrote. “EnerNOC recently significantly reduced its position in the ISO-NE FCM as the market had become unprofitable for all but the largest customers or those with advanced automation.”
DR had shown steady growth in NYISO until recently. “However, changes in market rules to enhance estimates of providers’ ability to deliver demand response during peak conditions have led to a decline in program participation in recent years,” the ISO said in its annual report. “The increased use of demand response resources may also test the ability — and willingness — of some program participants to sustain their commitments.”
The ISO deployed DR on a record six days during the summer of 2012.
Growth Areas
To be sure, DR is not going away. “Regulators are hard pressed to look past this source of cheap demand reduction,” notes UBS.
And there are growth opportunities in other regions, including California, Texas and non-RTO markets. In September, ERCOT changed its rules to allow DR participation in its real-time market. EnerNOC, which has operations in Australia, Canada, the United Kingdom and New Zealand, says the international market will be three times the size of the U.S.
But in more mature markets, DR’s growth, if not over, surely has slowed.
In a report last month, UBS said the PJM changes approved and pending “could continue to pressure DR’s market share, as proposed reforms to both aspects of the market would ratchet up participation requirements.”
Bride sees similar challenges in New England. “I’m pretty sure that DR will thrive again in ISO-NE, but for the average commercial or industrial customer, DR will be on hiatus for a couple of years until these issues get worked out,” he said.
Long-term Outlook
UBS says more independent power producers and utilities could enter the DR industry, which could “limit further pressure on DR participation from a regulatory perspective.” NRG Energy acquired Energy Curtailment Specialists in August. Exelon’s Constellation unit owns a demand response business (formerly CPower).
Much will depend on FERC’s stance on the proposed changes. DR lost a strong supporter with the departure of FERC chairman Jon Wellinghoff and his replacement has not been named.
An early indication could come in the commission’s ruling, due by March 2, on PJM’s increased documentation requirements.
Market leader EnerNOC — influenced perhaps by the fact that it is publicly traded and doesn’t want to voice doubts that could hurt the stock — has taken a less alarmist tack than Comverge in response to the PJM proposals.
“New rules are happening all the time in these competitive wholesale markets. DR is under more and more scrutiny,” EnerNOC CEO Timothy Healy told the Credit Suisse analyst conference earlier this month. “Some days we have some good news on that front — Texas was exactly what we were looking for — then a couple weeks later: PJM.”
“This is a very cost effective resource. It’s a flexible resource,” he continued. “Public utility commissions love demand response. This too will fade and we’ll see that demand response continues its steady march in these markets.”
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.
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.
(Source: PJM Interconnection, LLC)
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 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.
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.
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.
(Source: PJM Interconnection, LLC)
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.
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.
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.
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.
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%.
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.
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.
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.
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.
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.
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.
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.
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.
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.
(Source: CT Dept. of Energy & Environmental Protection)
Democratic governors from Maryland, Delaware and six other Eastern states yesterday asked the Environmental Protection Agency to impose controls on coal pollution they say is damaging air quality in their states.
The aggrieved states want EPA to force nine “upwind” states — Illinois, Indiana, Kentucky, Michigan, North Carolina, Ohio, Tennessee, Virginia and West Virginia — to join them as part of the Ozone Transport Region (OTR), which would trigger tougher emission controls.
Three OTR states headed by Republican governors, Pennsylvania, New Jersey and Maine, declined to join in the petition.
The states’ filing came the day before the Obama administration is set to defend its air pollution rules before the Supreme Court and a federal appeals court.
The Supreme Court will hear arguments today on EPA’s 2011 Cross-State Air Pollution Rule (CSAPR), which was struck down last year by the U.S. Court of Appeals for the District of Columbia Circuit.
The D.C. Circuit, meanwhile, is scheduled to hear challenges to EPA’s December 2011 mercury and air toxics standards (MATS) for power plants.
WASHINGTON — The cost of complying with upcoming carbon emission caps will depend on the role of energy efficiency and the choice of “blended” or fuel-specific emission standards, speakers told a high profile forum here last week.
A popular parlor game in Washington these days is debating what the Environmental Protection Agency’s pending greenhouse gas rules on existing power plants should look like. Will it be a rate-based standard limiting emissions per MWh or a mass-based standard, similar to the overall emissions “budget” used by California and the Regional Greenhouse Gas Initiative (RGGI)? Will limits be uniform or recognize states’ varying fuel mix?
About 400 people were in attendance as the Bipartisan Policy Center and the National Association of Regulatory Utility Commissioners turned a conference room at the Marriott Metro Center into a large, web-cast parlor. While there was no consensus on what EPA will do, there were plenty of opinions on what it should do.
Supporters of the mass-based standard said the rate-based alternative could result in uneconomic plant operations due to “seams conflicts” among states with different systems.
Kathy Kinsey
“If you’ve got states with 50 different programs you’ve got seams” said Kathy Kinsey, deputy secretary of the Maryland Department of the Environment. “That gets pretty complicated.”
“State borders are incongruous with energy markets,” said Dallas Burtraw, senior fellow at Resources for the Future, a think tank.
Bruce Phillips, director of The NorthBridge Group, said the rate-based alternative could also cause an “emission “rebound” as coal units that reduce their heat rates to comply are dispatched before gas plants, thus extending their operating lives.
Phillips argued for a mass-based approach that sets a “budget” for coal emissions and a separate emission rate for gas plants rather than a “blended” budget for both fuels.
Bruce Phillips
Both mass-based approaches could cut carbon emissions from fossil fuel generation and coal generation by 26% over 2005 levels while increasing gas consumption by 2.7 TCF and boosting Henry Hub gas prices by about 10%, Phillips said.
But while the fuel-specific approach would increase wholesale electric costs by 6%, prices would rise 28% under a blended approach, Phillips said.
Energy Efficiency’s Roles
The forum also featured a debate between the Natural Resources Defense Council and the American Coalition for Clean Coal Electricity (ACCCE) over the role and cost of energy efficiency under the new rules.
The NRDC has proposed a plan that would grant credits to state energy efficiency programs, which generators could purchase to effectively lower their average emissions rates. Dan Lashof, director of NRDC’s climate and clean air program, told the forum its plan could cut CO2 pollution by 26% from 2005 levels by 2020.
The environmental group initially estimated a compliance cost of $4 billion in 2020, which it said would produce environmental benefits of $25 to $60 billion. A revised analysis, incorporating lower demand growth estimates and energy efficiency costs, projects 2020 compliance costs at less than $1 billion.
Sound too good to be true? It is, insisted Paul Bailey, ACCCE’s senior vice president for federal affairs and policy.
Paul Bailey
Bailey presented an analysis “bookending” the NRDC proposal between two scenarios: “Maximum flexibility,” which envisions national emissions trading and credits for end-use efficiency and new renewables and “limited flexibility,” which allows only intra-state trading and no credits for EE or renewables.
Where NRDC sees 210,400 net job gains in 2020, ACCCE says it will cost 75,000 to 214,000 jobs. ACCCE also predicts retail price increases of more than 10% in 13 to 29 states.
Bailey said the main reason for the disparities are differing assumptions regarding energy efficiency costs. NRDC estimated costs of up to 4.6 cents per KWh while ACCCE used an estimate more than twice as high at 11 cents.
Other speakers also split on the role of energy efficiency.
Bruce Braine
“In the future, it’s going to be a challenge” to increase EE further, said Bruce Braine, AEP’s vice president for strategic policy analysis.
Resources for the Future’s Burtraw said a flexible approach allowing emissions rate averaging or trading and reliance on EE could result in a “very small change in electricity prices.”
State Standards
Kinsey said EPA should set uniform carbon intensity standards for all states while giving coal-dependent states time to adjust.
But the NRDC would set different levels. For example, California, which has virtually no coal generation would have a limit of 1,100 lbs./MWh while Kentucky would have a limit of 1,480. “While Kentucky would have a lower standard than California it would have to make a bigger reduction from its starting point,” said Lashof.
Nuclear Power Role
William K. Reilly
Keynote speaker William K. Reilly, EPA administrator from 1989-93, said the rules should allow generators time to recover their investments in emission controls for mercury, sulfur oxides and nitrogen oxides.
Reilly and other speakers also called for a renewed role for nuclear power, saying a reliance on natural gas alone for baseload power would expose the economy to price risk.
Six nuclear plants with a capacity of almost 4,900 MW have recently announced retirements due to flat power demand and low prices.
Kathleen Barron
If that trend continues, the nation will lose one-quarter of its nuclear capacity by 2025 — giving back more than half of the progress to date in meeting 2020 climate goals, said Kathleen Barron, Exelon Corp.’s , senior vice president for federal regulatory affairs and wholesale market policy. “All of these pictures, of course, change if there’s a price on carbon,” she said.
EPA Approach Praised
Speakers praised EPA’s efforts to solicit input from industry and state regulators in formulating the rules. “I’ve seen EPA personnel more than my own family in the last few months,” joked Doug Scott, chairman of the Illinois Commerce Commission.
Among those in attendance were Gregory Carmean, executive director of the Organization of PJM States Inc. (OPSI), and PJM market strategist Gary Helm, Vice President for Federal Government Policy Craig Glazer and Chief Economist Paul Sotkiewicz.
“It’s pretty clear that people are looking for flexibility in what EPA proposes,” Sotkiewicz said after the session. “Flexibility across fuel sources, flexibility across geographic regions, flexibility across time.”
