Transmission owners said last week that they will address transparency concerns over their load calculations but insisted the issue be resolved by their committee rather than in the Markets and Reliability Committee.
The MRC approved a problem statement in June after industrial customers complained that two-thirds of PJM’s transmission owners have failed to file FERC-approved tariffs disclosing the methodology their electric distribution companies (EDCs) use to allocate costs to load serving entities (LSEs). (See Industrials Call for Transparency in Transmission Owner Calculations.)
At a special MRC meeting Wednesday, members agreed to delay action on the problem statement to allow a response from transmission owners. Meg Sullivan, of Duquesne Light, chair of the Transmission Owners Agreement Administrative Committee (TOA-AC) told the meeting that the issue was under the jurisdiction of the TO panel and would be on its Nov. 6 meeting agenda.
Proper Forum
“We believe the forum to address the problem statement should be” the TOA-AC, she said. She said the TO panel would seek to “address it to everyone’s satisfaction.”
Attorney Robert Weishaar, who represents the PJM Industrial Customer Coalition, said he was willing to delay further action but not to concede that the TOs’ committee has jurisdiction over calculation of the total hourly energy obligations (THEO), peak load contributions (PLC), and network service peak loads (NSPL).
“I’m certainly willing to have the discussion with the TOs-slash EDCs,” he said, calling it a “practical step forward.
“But some aspects of the problem statement will have to come back to the MRC,” he added.
Weishaar said NSPL calculations are the transmission owners’ jurisdiction, but that other calculations are under MRC’s purview.
Equal Footing
David Scarpignato, representing retail provider Direct Energy, noted that only transmission owners have voting rights within the TOA-AC. “For everyone to have equal footing, it has to be in the stakeholder process,” he said.
But PJM’s Dave Anders, secretary of the MRC, urged a delay in further MRC action to give the TOA-AC “a couple months” to find a solution. He noted that most EDCs are represented in the TOA-AC. “There’s no reason to at least not have that discussion.”
David Pratzon, who represents generators, agreed. “Let’s not have this jurisdictional fight at this time if we don’t need it,” he said.
Weishaar said the lack of transparency undermines accountability, noting that utilities sometimes change methodologies without notice. The calculations are used to allocate energy, capacity, and transmission cost responsibility among LSEs.
Weishaar’s proposal would require Baltimore Gas & Electric, PECO Energy, PPL Electric Utilities, Dominion, Dayton, PEPCO, AEP, Duquesne Light Company, Rockland Electric, and Duke Energy to file Attachments M-1 or M-2 to the PJM OATT disclosing their methodologies. FirstEnergy, Commonwealth Edison, Public Service Electric & Gas, Atlantic City Electric and Delmarva Power & Light have already filed such disclosures, according to Weishaar.
Operators of gas-fired generators could include the costs of ensuring fuel supplies in their energy market offers under changes being considered by stakeholders.
The Markets and Reliability Committee Thursday approved a problem statement authorizing a task force created in March to consider allowing generators to include the cost of firm gas transportation in energy market offers and to reflect gas price changes between day-ahead commitments and real-time operation. PJM already allows dual-fuel generators to reflect the cost of backup fuel in their offers.
The problem statement also will allow the Gas Electric Senior Task Force (GESTF) to consider potential changes to the timing of day-ahead market clearing to align it more closely with the nominating schedules of gas pipelines.
Currently, units must place gas nominations before knowing whether they will be dispatched in the day-ahead market. Thus they may have to sell gas if their offer does not clear or derate during the morning peak if they don’t have enough gas.
The problem statement was approved without opposition, although Howard Haas, of Independent Market Monitor Monitoring Analytics expressed concern that it was “very prescriptive” in its discussion of potential solutions.
Haas noted that dual fuel generators can submit multiple cost offers reflecting gas and oil operation. Before making any changes, Haas said, the task force should consider “What is the nature of the risk, given current market rules, and who should handle the risk?”
The task force was formed to study potential reliability problems resulting from PJM’s increasing reliability on gas-fired generation. (See previous coverage on gas-electric coordination.) The group’s work is expected to continue through the 2016/2017 delivery year, during which PJM expects significant additions of gas-fired generating capacity to replace coal retirements.
Natural gas’ share of PJM’s generation has nearly tripled since 2007, rising to almost 20% of electric production in 2012.
Although PJM does not face any immediate reliability problems, officials say it could take five years to build new generation to respond to potential capacity shortages.
Because natural gas generation relies on “just-in-time” fuel supplies, the Federal Energy Regulatory Commission has warned that some plants may not be able to operate on the coldest days when gas demand for heating is at its peak.
FERC has held six technical conferences on the relationship between the natural gas and electricity markets since last year (docket #AD12-12-000).
To date, PJM has been working to improve coordination with gas pipelines through information sharing and cross training of dispatch personnel. At FERC’s Oct. 17 meeting, M. Gary Helm, PJM Lead Market Strategist, said PJM’s winter reserve margin — currently about 40% and projected to remain above 30% through 2016/17 — is “more than adequate.”
The Eastern Interconnection Planning Collaborative (EIPC) announced last week the selection of Levitan & Associates, Inc. to lead a Department of Energy-funded study on the ability of gas systems to supply gas-fired generation into the next decade. Levitan, of Boston, was chosen from among six consultants that submitted proposals.
Participating in the study in addition to PJM are ISO-NE, NYISO, MISO, TVA and the Independent Electric System Operator (IESO), which serves Ontario.
Billions are at stake. Vertical demand curves are bad. On that there was agreement at last week’s Markets and Reliability Committee meeting.
Beyond that, however, there was little common ground evident in a first reading of PJM’s proposal to cap the volume of Limited Demand Response that can clear in the capacity auction.
Capacity Payments Dominate DR Revenues (Source: PJM Interconnections, LLC)
PJM’s proposal came to the MRC after winning support of 75% of the voters at the Capacity Senior Task Force. None of three alternatives proposed by states and demand response aggregators won support of more than a quarter of the 182 voters.
Katie Guerry, representing DR aggregator EnerNOC, which proposed one of the alternatives, said she would continue to seek work a consensus before the MRC votes on the issue next month. Some members suggested PJM merge its proposal with “Option B,” proposed by state consumer advocates and Southern Maryland Electric Cooperative (SMECO).
But there was no indication that PJM and the generation owners who strongly back the RTO proposal were willing to give any ground. If PJM is unable to obtain support of two-thirds of stakeholders in a sector-weighted vote of the MRC, the PJM Board of Managers can unilaterally decide to file the proposed changes with the Federal Energy Regulatory Commission.
“Option B just doesn’t do it,” said Andy Ott, PJM executive vice president for markets. “It won’t address the reliability problems we’ve identified.”
Boom-Bust Cycle
PJM says the current rules result in a vertical demand curve that leads to boom-bust cycles in which the system “oscillates” between being long on capacity, with low prices, and being short on capacity with high prices.
PJM wants the new rules in place by February, when the RTO must post planning parameters for the 2014 Base Residual Auction.
Under current rules, 4.8% of PJM’s reliability requirement can be filled with limited demand response, with higher levels possible if excess capacity clears against the sloped Variable Resource Requirement (VRR) demand curve. PJM wants to reduce the 4.8% by all of the 2.5% Short-term Resource Procurement Target (STRPT) for a net of 2.3%.
The SMECO/Public Advocates proposal would reduce the 4.8% by only a portion — to be determined — of the 2.5% holdback.
A simulation found that PJM’s proposal would have increased total costs by $1 billion over actual costs in the 2015/16 auction and $800 million for 2016/17 while reducing the volume of limited DR clearing in the two years by 64%.
The SMECO/Public Advocates’ proposal would have increased costs by less than 1% over the two years while reducing the volume of limited DR by about one-fifth. (See Demand Response Changes Could Cost $1B Annually)
Cheaper Long-Term Solution
PJM officials said their proposal will ultimately save consumers money by ensuring adequate capacity and keeping energy market prices low.
The one-year snapshot provided by the simulation “is not looking at the big picture,” Ott said. “What we’re looking at is the long term low-cost solution.”
Ott said the projected increase in capacity costs “could be looked at as what we’re undervaluing long-term resource adequacy at today.”
Without reforms, Ott said, “we’re going to have a much bigger reliability problem that will be much more expensive to correct because there will be less time.”
CEO Terry Boston, who speaks infrequently at meetings, also weighed in, noting that energy market costs were the lowest in 10 years in 2012. “That’s because we’ve had adequate capacity to call on when we need it,” he said. Through September, load-weighted energy represented almost 78% of costs versus 13% for capacity.
Representatives of Exelon, Duke and AEP strongly backed PJM’s proposal.
Duke’s Ken Jennings said PJM’s baseload coal plants, which clear in the energy market at $40/MWh or less, “will go away” without changes to allow an increase in capacity prices.
Difficult `Value Proposition’
(Source: PJM Interconnection, LLC)
But those representing load were not convinced of the urgency for changes and said PJM’s proposal could damage the growth of demand response.
“We’re struggling to see it in the same way as PJM,” said Susan Bruce, representing the PJM Industrial Customers Coalition. Paying an additional $1 billion annually for capacity, she said, is “a value proposition that’s hard for us to get our hands around.”
“If there’s other, better, data [to counter the simulation estimates] we’d like to see it,” said Walter Hall, of the Maryland Public Service Commission.
Hall said the state has not taken a final position on the issue but is concerned that the capacity market limits and other changes proposed by PJM to allow more flexible deployment of DR threaten the state’s EmPOWER Maryland load-reduction programs, which were authorized by the state legislature.
“We want to see [DR] maximized,” Hall said.
DR gets the vast majority of its revenue from the capacity market. “Without those revenues the programs might not be able to continue and certainly wouldn’t be able to grow,” Hall said.
BGE, Pepco Impact
Baltimore Gas and Electric and Pepco Holdings Inc. have told state regulators that PJM’s proposals to dispatch DR by zip code and with as little as 30 minutes lead time won’t work with residential and small business participants, Hall said.
He said the state would consider “taking this up with FERC if necessary” to prevent restrictions on the program.
Gloria Godson, representing PHI, echoed Hall’s concerns. “We’re going to have significant customer confusion and customer education issues at a minimum,” she said.
Unlike PHI, which has divested its generation, BGE parent Exelon Corp., which owns more than 23,000 MW of generating capacity in PJM, stands to benefit from increases in capacity prices.
Jason Barker, representing Exelon, said reliability is the paramount issue in the current debate. “We shouldn’t lose sight of that in light of the economic interests,” he said. “BGE supports PJM’s proposals on the basis of reliability, comparability and market efficiency,” he added.
Ed Tatum, representing Old Dominion Electric Cooperative, said he agrees with PJM that there must be caps on limited DR. But he said PJM’s proposal “appears to go beyond what is really necessary.”
Eliminating the 2.5% “holdback” will cut the volume of limited DR clearing by half, he said. “That’s a major change … and a big transfer of wealth.”
He urged PJM to modify its proposal to find consensus with representatives of load — to “see if there isn’t something that we as a family can live with.”
‘Fabricated’ Emergency
The sharpest exchange of the more than hour-long debate came when Duke’s Jennings criticized the deployment of demand response, which set prices at $1,800 per MWh in some zones during heat waves in July and September.
Such deployments should be limited to “real emergencies,” he said, “not fabricated emergencies that arise because we decided to drive … generators out of the market.”
Guerry said Jenning’s comment was a “horrible misrepresentation of what happened in September.
“It wasn’t a fabricated emergency. [DR] was the last resource available in the dispatch stack before having to go to load shedding,” she said.
Others in the room shook their heads in disagreement with Guerry’s account. Although PJM did implement limited load shedding in the September event due to local reliability concerns, officials said they had generation in reserve that could have been called upon during the two heat waves. Guerry said later that she was referring specifically to PJM’s dispatch of DR in the ATSI region on Sept. 10 and 11, when it set prices at $1,800/MWh for several hours.
Guerry questioned the foundations of PJM’s proposal. “We continue to have questions about whether the vertical demand curve has been reintroduced,” she said.
She reiterated her call for a delay on the capacity market revisions pending other changes to increase the flexibility of DR. “We’re very concerned that we’re developing limits on a product that we have not finished … redefining,” she said.
Stakeholders will continue the debate at tomorrow’s CSTF meeting.
NRG Energy Inc. will pay $2.64 billion to acquire the assets of bankrupt Edison Mission Energy, adding nearly 8,000 MW coal, gas and wind generation. EME’s assets include four coal-fired plants in Illinois, about 10 gas-fired plants in California and more than 30 wind projects in 11 states. “These aren’t great assets, but they didn’t pay much for them,” said Morningstar analyst Travis Miller.
NRG is also among investors who paid $10 million for a stake in EcoFactor, a contender in the cloud-based home energy services and analytics sector.
Ameren Corp. will sell its Elgin, Grand Tower and Gibson City natural gas plants in Illinois to an affiliate of private equity firm Rockland Capital. Ameren said it expects after-tax proceeds of more than $137.5 million from the transaction.
The company also has received approval from the Federal Energy Regulatory Commission to sell five coal-fired power plants in Illinois — Duck Creek, E.D. Edwards, Coffeen, Newton and Joppa — to Dynegy Inc. Ameren announced in December it would sell its merchant power plants to focus on its regulated utilities in Illinois and Missouri.
Pilot programs in Michigan and Illinois suggest smart meters and variable pricing are changing consumers’ patterns of energy use. “Many of our customers consider it a challenge to see how much they can reduce their rate,” said a spokesman for DTE Energy.
Navigant Research says as many as 5% of customers could eventually adopt variable pricing but that penetration will be less than 1% by 2020 unless utilities act aggressively to eliminate barriers.
The Supreme Court agreed decide whether to block key aspects of the Obama administration’s plan aimed at cutting power plant and factory emissions of gases blamed for global warming. The justices will review a unanimous federal appeals court ruling that upheld the government’s unprecedented regulation of carbon dioxide and five other heat-trapping gases.
The question in the case is whether the Environmental Protection Agency’s authority to regulate automobile emissions of greenhouses gases as air pollutants, which stemmed from a 2007 Supreme Court ruling, also applies to power plants and factories.
The Obama administration’s plans hinge on the high court’s 2007 ruling in Massachusetts v. EPA, which said the EPA has authority under the Clean Air Act, to limit emissions of greenhouse gases from vehicles. Two years later, EPA concluded that the release of carbon dioxide and other heat-trapping gases endangered human health and welfare, a finding the administration has used to extend its authority beyond automobiles to develop national standards for large stationary sources.
An explicit cost on carbon pollution is the best way for countries to reduce emissions, according to new research by the multilateral Organization for Economic Cooperation and Development (OECD).
“Explicit carbon pricing mechanisms, such as carbon taxes and emissions trading systems, are generally more cost-effective than most alternative policy options in creating the incentive for economies to transition towards zero carbon trajectories,” the group said in a new report.
The Northeast is poised to switch from the nation’s largest demand region to a net supply region, and the U.S. Southeast is racing to become a much larger net demand region after being a major supplier to the U.S. gas market, according to a new report from Bentek Energy. The company says Utica shale production will play a major role in changing natural gas flows and price spreads.
The number of safety violations at U.S. nuclear power plants varies dramatically from region to region, suggesting inconsistent enforcement, according to the Government Accountability Office. The GAO report shows that while the West has the fewest reactors, it had the most lower-level violations from 2000 to 2012 — more than 2½ times the Southeast’s rate per reactor.
The Nuclear Regulatory Commission will hear challenges by environmental groups on DTE Energy Co.’s proposal to build a new nuclear reactor in Michigan.
The NRC’s Atomic Safety and Licensing Board will hold a hearing Oct. 30 to review a challenge by environmental groups who say the environmental review of the proposed reactor fails to adequately analyze and discuss impacts on the eastern fox snake at the site. DTE has not yet decided to build the new reactor at its Fermi nuclear plant but said it filed with NRC in order to keep its options open.
Federal officials charged a 37-year-old Jacksonville, Ark. man with committing multiple acts of sabotage on the power grid in central Arkansas since August.
Jason Woodring was arrested after an investigation that began Aug. 21, when a 500 kV power line fell on a nearby railroad track. Officials said a shackle holding the line was severed and 100 bolts securing a support tower had been removed. Authorities also linked the suspect to a Sept. 29 fire that caused more than $2 million in damages at an Entergy switching station in Scott, Arkansas and an Oct. 6 incident near the suspect’s home in which two power poles were cut and one was pulled down.
The Planning Committee will hold the first educational session on the capabilities of advanced electric storage from 1-4 p.m. Oct. 29.
PJM rules currently allow electric storage other than pump hydro to participate in only the frequency regulation market. A problem statement approved by the Markets and Reliability Committee could open the capacity market to batteries, flywheels and other storage technologies.
Katherine Hamilton, policy director for the Electricity Storage Association, provided the Planning Committee a brief introduction to storage technologies Oct. 10.
Steve Herling, PJM vice president of planning, told the committee that PJM staff is conducting research to determine how the RTO estimates the capacity values of all resources.
“We need to understand all the different sets of rules out there and their reasons. There should be consistency in some areas,” Herling said. “In areas where differentiation is appropriate let’s establish that.”
PJM is considering five capacity import zones with a combined limit of 8,400 to 11,000 MW, officials told the Planning Committee Friday.
PJM’s initial review indicated the RTO could import 11,000 to 12,000 MW simultaneously. Last week, however, PJM’s Mark Sims told members that the limit will be “slightly lower” than 11,000 and closer to the 8,347 MWs imported on July 16, 2013, the highest import observed in an analysis of three years of historical data.
“It should be around [8,347 MW] or a little higher,” Sims said.
PJM officials said the MISO North zone should have been drawn to include the thumb of Michigan and NIPSCO on the PJM-MISO seam (Source: PJM Interconnection, LLC)
Officials said they are considering modeling five “conceptual import zones”: MISO; MISO North; TVA/Louisville Gas & Electric; VACAR and NYISO.
In response to members’ questions, officials also said they may add a sixth zone to reflect the integration of Entergy’s transmission system into MISO. Entergy is “two hops away” from PJM, said Sims. “I don’t think it will have that much of an impact on the final limit.”
Stu Bresler, PJM vice president of market operations, said PJM is unlikely to accept suggestions that imports have firm transmission before offering into the capacity auction. Bresler said officials fear that the Federal Energy Regulatory Commission would reject such a requirement, which would be analogous to requiring internal resources to have signed interconnection service agreements three years before the delivery year. That, Bresler said “would be a barrier to entry.”
The Planning Committee approved a problem statement on a proposed cap in response to the May Base Residual Auction, in which more than 7,400 MW of imports cleared.
PJM wants to include the new limit in February when it posts the planning parameters for the 2014 base auction.
To meet that schedule, officials plan to present proposed methodology and manual language at the Planning Committee meeting Nov. 7. The MRC will hear first reading on Nov. 14, with a vote scheduled for Nov. 21.
If imports hit the limit, officials said they will clear at lower prices than internal resources, just as resources east of PJM’s west-to-east constraints are often priced higher.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM MANUALS (9:10-9:40)
Manual 3: Transmission Operations – Adds language regarding approval of emergency rating changes; added applicability for individual generators greater than 20 MVA; clarified reference to voltage coordination; revised outdated references.
Manual 10: Pre-Scheduling Operations – Annual Review. Minor updates for clarity; added references to forecasted planned outages and reporting outages on synchronous condensers.
Manual 14D: Generator Operational Requirements – Changes made at RFC request, and for consistency. Includes changes to reactive capability testing; replaces outdated references; requires generators operating or scheduled for PJM to operate to notify PJM prior to attempting a restart following a trip or failure to start.
Manual 14B: PJM Region Transmission Planning Process – Changes to improve the procedure for analyzing and addressing short circuits. PJM currently analyzes short circuit cases for the current year +1 and +5. System modifications are difficult for transmission owners to implement with a one-year lead time. The annual Regional Transmission Expansion Plan will analyze short circuit base cases for the current year +2.
3. GAS/ELECTRIC SENIOR TASK FORCE (GESTF) (9:40-10:10)
The committee will be asked to approve a proposed Problem Statement/Issue Charge to consider changing market rules to allow generators to reflect the cost of firm natural gas service and the timing of the Day-Ahead market clearing.
The potential changes will be evaluated by the Gas Electric Senior Task Force (GESTF), which was formed in March to study potential reliability problems resulting from PJM’s increasing reliability on gas-fired generation. (See previous coverage on gas-electric coordination.)
Under current rules, generators cannot reflect the cost of firm gas transportation in energy market offers. In addition, units must gas nominations before knowing whether they will be dispatched in the day-ahead market. Thus they may have to sell gas if their offer does not clear or derate during the morning peak if they don’t have enough gas.
Under the problem statement, the task force would consider potential changes to the timing of the day-ahead market clearing as well as rule changes that would allow offers to reflect firm gas costs and price changes between day-ahead commitments and real-time operation.
4. 2013 IRM STUDY (10:10-10:30)
The committee will be asked to endorse PJM staff’s recommendation to increase the Installed Reserve Margin (IRM) to 16.2% for delivery year 2014/15 (up from 15.9% in the 2012 analysis). The committee also will be asked to endorse margins of 15.7% for delivery years 2015 through 2018.
The increase, which was endorsed by the Planning Committee Oct. 10, is because of the increasing alignment of the RTO’s peak demand with demand outside of the region. (See Increased Installed Reserve Margin OKd for 2014)
Members Committee
2. CONSENT AGENDA (1:20-1:25)
B. Coordinated Transaction Scheduling
The Members Committee will be asked to approve Tariff and Operating Agreement changes to create the Coordinated Transaction Scheduling (CTS) product, designed to reduce uneconomic power flows between PJM and NYISO.
The new product would allow traders to submit “price differential” offers that would clear when the price difference between New York and PJM exceeds a threshold set by the bidder.
The Market Implementation Committee approved the product in September Coordinated Transaction Scheduling product after amending it to address member concerns about the reliability of PJM’s price projection algorithm, on which CTS trades will be based. The Markets and Reliability Committee approved the measure Sept. 26. (See New NYISO Product OKd)
C. Demand Response Registration Process
Members will be asked to approve Tariff and Operating Agreement revisions to simplify the process for registering demand response customers. The changes would remove or modify the role of load serving entities in the emergency and economic registration review process.
Members will be asked to approve increased penalties for under-performing Tier 2 synchronized reserve providers.
The MRC last month approved a proposal introduced by Dave Pratzon of GT Power Group after the Operating Committee selected it over a proposal from PJM and the Market Monitor. Pratzon said his proposal was tougher than the current penalty but less severe than the PJM-Market Monitor proposal, which he called overly punitive. (See OC Hears New Proposal on Synchronized Reserve Penalty; Delays Vote)
The Federal Energy Regulatory Commission last week approved a new reliability standard that will allow PJM and other transmission planners to plan for “non-consequential” load loss following a single contingency.
The rules, part of the North American Electric Reliability Corp.’s Transmission Planning Reliability Standard (TPL-001-4), includes limitations on the maximum amount of load that an entity may plan to shed, a stakeholder process and safeguards to ensure the rules are applied consistently. Use of such load losses “should be rare,” the commission said.
The new standard limits permissible non-consequential load losses to 75 MW. Planned load losses between 25 MW and 75 MW, or any planned loss at the 300 kV level or above would receive greater scrutiny by regulatory authorities and NERC.
In these cases, “the Transmission Planner or Planning Coordinator must ensure that applicable regulatory authorities or governing bodies responsible for retail electric service issues do not object to the use of” the load loss. Planners must also submit the information to NERC, which will determine whether there are any adverse reliability impacts from the plan.
The commission rejected a request from MISO that it define “regulatory authorities” that must be consulted. “Because each state and locality has different entities that are responsible for reliability of retail electric service, we are reluctant to further define who may participate,” the commission wrote.
The commission had rejected NERC’s previous attempts to write rules on the issue, saying they were too vague.
“I am pleased that we are putting behind us one of the most difficult outstanding issues dating from the commission’s March 2010 reliability orders,” Commissioner Cheryl LaFleur said in a statement. “This case was an example in which NERC and the industry proposed an `equally efficient and effective’ alternative solution to address a concern articulated by the commission.”
The Commission required NERC to submit a report based on the first two years of implementation of the new standard.
The new NERC standard also requires annual assessments addressing steady state, short circuit and stability conditions.
The Commission ordered NERC to make two changes to the standard. One modification will address concerns that it could exclude planned maintenance outages of significant facilities from planning assessments. The other will change the TPL-001-4, Requirement R1 Violation Risk Factor from medium to high.
Amid complaints that the issue has not been fully vetted, members of the Capacity Senior Task Force are voting on four proposals to cap the volume of limited demand response that can clear PJM’s base capacity auction. The vote, which was opened last week, closes today.
Katie Guerry, representing demand response aggregator EnerNOC Inc., said the vote should be delayed because changes being considered to increase DR’s flexibility may alleviate some of the concerns that prompted calls for caps. “We’re concerned that we’re putting the cart before the horse,” she told the task force at a meeting last week. “We’re not convinced there’s a problem.”
Walter Hall, of the Maryland Public Service Commission, and John Farber, of the Delaware Public Service Commission, supported Guerry’s call for a delay. Hall said Maryland would like more time to evaluate the impact of the proposed changes on demand response in the state before taking a position.
But PJM’s Scott Baker, chair of the task force, said the schedule was necessary to make changes by February, when the RTO must post planning parameters for the 2014 Base Residual Auction.
Boom-Bust Cycles
PJM says the current rules result in a vertical demand curve that leads to boom-bust cycles where the system “oscillates” between being long on capacity, with low prices, and being short on capacity with high prices.
Under current rules, 4.8% of PJM’s reliability requirement can be filled with limited demand response, with higher levels possible if excess capacity clears against the sloped Variable Resource Requirement (VRR) demand curve. PJM wants to reduce the 4.8% by all of the 2.5% Short-term Resource Procurement Target (STRPT) for a net of 2.3%.
An alternate proposal by Southern Maryland Electric Cooperative and consultant James Wilson on behalf of consumer advocates for Maryland, Delaware and New Jersey would reduce the 4.8% by only a portion — to be determined — of the 2.5% holdback. The proposal would increase the 4.8% base to recognize that DR will increasingly be used as an operational resource.
$1.8 Billion Cost Increase
PJM Proposed Method for Modeling of the Limited & Extended Summer Demand Response Targets (Source: PJM Interconnection, LLC)
PJM’s proposal would have increased total costs by more than $1.8 billion over actual costs for 2015/16 and 2016/17, an increase of 12%, according to a simulation by PJM. It would have reduced the volume of limited DR by 64%.
The SMECO/Public Advocates’ proposal would have increased costs by less than 1% over the two years while reducing the volume of limited DR by about one-fifth.
Wilson, who drafted the public advocates’ proposal, said he was pleased with the results of the analysis. “It allows annual and extended summer to compete to the VRR curve,” he said.
EnerNoc and EnergyConnect, another demand response aggregator, also submitted alternatives, but they came too late for PJM to conduct simulations.
EnerNOC’s proposal would re-institute sloped demand curves for Extended Summer, Annual and Limited DR products. It would use the minimum resource requirements for Annual and Extended Summer resources to create sloped demand curves for those products, in the same manner that the VRR curve is created. The auction would have to clear to the sloped curves instead of the vertical curves before resuming clearing in merit order for all products.
EnergyConnect’s proposal would adopt PJM’s proposal but differs on its handling of extended summer DR. It would continue the current rules capping Extended Summer DR at 10.5%. PJM wants to reduce that limit by the 2.5% holdback to a net of 8%.
The vote asks members whether they can support any of the four proposals and also includes a non-binding poll asking whether they would prefer to keep the status quo. The results will be presented at the Markets and Reliability Committee meeting Thursday.
DR as an Operational Resource
While the task force remained deeply split over the handling of limited DR, members seemed to be coming closer to consensus on two related issues — increasing DR’s flexibility and eliminating arbitrage opportunities between the Base and Incremental auctions — during the day-long meeting.
PJM’s Pete Langbein said the RTO has amended its proposal regarding a must-offer requirement for economic DR in response to stakeholder feedback. Langbein said PJM now wants to drop the must-offer requirement as long as it can dispatch DR with capacity commitments without declaring an emergency.
“These [changes] are really going in the right direction for us,” said Guerry.
Dispatch Time
Bruce Campbell, representing EnergyConnect, said a PJM proposal to require DR resources to prove they cannot be dispatched in 30 minutes could create an “unwieldy administrative construct.” He said proposals to pay quicker-responding DR resources more than slower ones will be sufficient to give PJM the resource diversity it seeks.
If 10% of the 15,000 DR resources seek such waivers, he said, it would result in 1,500 applications. “I think you risk losing a lot of demand response resources, at significant cost to load, if you continue going down this road,” he said.
But Stu Bresler, PJM vice president of market operations, noted that only 5% of DR has voluntarily chosen to be dispatched in one hour, with the remainder choosing two-hour dispatch. “My response to Bruce is, ‘How do I know I’m going to get that stratification?’”
Auction Arbitrage
Members reacted favorably to a new proposal by Gabel Associates to eliminate auction arbitrage opportunities.
PJM has proposed eliminating any profits that resources might receive from clearing at high prices in the BRA and buying out their position at a lower price in the incremental auction.
Gabel’s Michael Borgatti told the task force that PJM’s proposal provides little incentive to develop resources and may still result in resources failing to deliver.
Gabel’s proposal, made on behalf of RC Cape May Holdings, would reduce deficiency penalties for projects that pass development milestones evidencing good faith efforts to meet their commitments. Unlike PJM’s proposal, it would not apply the rules changes retroactively.
The Federal Energy Regulatory Commission has scheduled a technical conference for Nov. 13 to explore the implications of rule changes already proposed by PJM to address arbitrage concerns. The commission conditionally accepted proposed Tariff changes on Oct. 1 (Docket No. ER13-2108).
