The Federal Energy Regulatory Commission last week gave final approval to Critical Infrastructure Protection (CIP) standards that for the first time cover all bulk power system assets according to their impact on the grid.
Version 5 of the CIP cybersecurity standards replace the current “in or out” designations with a tiered approach which classify assets as high, medium or low impact. (See What You Need To Know About CIP Version 5.)
TOP, IRO Standards Remanded
At the same time, FERC issued a notice of proposed rulemaking that remanded to the North American Electric Reliability Corp. its proposed revisions to reliability standards for system monitoring.
NERC’s Transmission Operations (TOP) and Interconnection Reliability Operations and Coordination (IRO) reliability standards go in the right direction – combining similar requirements, clarifying responsibilities and eliminating redundancies – but go too far, FERC said. Commissioners took pains at their public meeting to strike a friendly tone. “We tried to make sure that the remand tone was such that passions would not be inflamed,” Commissioner Philip Moeller said.
Commissioner Cheryl LaFleur said that the proposed revisions wrongly eliminate transmission operators’ current obligation to monitor and operate within all system operating limits. They would exclude from monitoring, for example, certain system operating limits in one operator’s area that affect another operator’s area. Failing to monitor such limits, FERC said, could contribute to outages.
Language Deleted
Although it approved nearly all the Version 5 CIP standards NERC had proposed, FERC deleted language that it identified as a problem when it proposed approval in April: a provision that required CIP standards to be implemented in a way that “identifies, assesses and corrects” deficiencies. That language would cause inconsistencies and difficulties with enforcement, the commission said. Everyone involved “must have a common understanding of the obligations imposed by reliability standards.” LaFleur said in a statement. “Otherwise, we risk creating gaps in reliability, confusion during audits and a compliance backlog that diverts resources away from improving reliability.”
FERC also told NERC to develop objective criteria for evaluating entities’ cyber protection for low-impact assets.
Although some had objected to creating burdens for assets in the lowest rung of impact, the commission reiterated its position that the standard “does not provide those entities with a clear roadmap of what they need to do.” NERC will not have to draw up a set of specific controls, but could take a number of approaches to fulfill the requirement, FERC said.
Standards Retired
In another reliability action, FERC approved NERC’s proposed retirement of 34 requirements in 19 reliability standards that provide little protection or are redundant of other standards. The order also withdraws 41 outstanding commission directives that NERC modify standards that have been addressed in another way or are too broad.
The Federal Energy Regulatory Commission last week approved a rule sought by the solar industry to streamline interconnections for the growing segment of small generators.
1.1 MW Solar Array at University of Toledo (Plug Smart)
The final Small Generator Interconnection Agreements and Procedures rule (Docket #RM13-2) expands the field of projects eligible for a fast-track process from a 2-MW size limit, but does not adopt the notice of proposed rulemaking’s designation of up to 5 MW for eligibility. Instead, it retains the 2-MW threshold for synchronous and induction machines and expands eligibility for inverter-based machines that meet certain system and generator characteristics.
All projects connecting to lines larger than 69 kV will be ineligible for fast-tracking.
While narrowing the scope of eligible projects, the changes maintain fast-tracking for most distributed solar applications, according to the Solar Energy Industries Association. SEIA, renewables companies and utility associations participated in a stakeholder group that developed the changes on eligibility and other matters.
The rule allows interconnecting customers to ask transmission providers for a pre-application report about system conditions at the point of interconnection. There is a fixed $300 fee for the report but providers can seek higher fees with cost justification. PJM had told FERC that the amount was not enough. PJM also had opposed formalizing the report, saying the RTO already does a lot of pre-application engagement and that a report could create “an inflexible box.”
PJM and others did prevail in arguing for more time -— 20 days instead of 10 — for delivery of that report.
They also won a disclaimer that since the report will require only readily available data at the time of request, it will be non-binding.
FERC also agreed with PJM’s request for more time to provide interconnection agreements, increasing it to 10 days from five, because the fast-track reforms could result in more such agreements.
The rule also accounts explicitly for interconnection of storage devices, and it makes clear that only FERC-jurisdictional systems are subject to the requirements.
Transmission providers will have to submit compliance filings within six months. FERC will allow for regional variations, and will give regional transmission organizations such as PJM more flexibility than transmission providers that are also market participants.
Cheryl LaFleur became acting chair of the Federal Energy Regulatory Commission Sunday, succeeding Jon Wellinghoff, who came under pressure to resign after accepting a law firm position in October.
FERC Commissioner Cheryl LaFleur at PJM Grid 20/20
As a sitting commissioner, LaFleur won’t require Senate confirmation. But she would need congressional clearance if she were to continue in the post after her four-year term ends in June.
Wellinghoff, who is joining the Washington office of Portland-based Stoel Rives LLP, announced his departure at the end of Thursday’s commission meeting. Sen. John Barrasso (R-WY) had criticized Wellinghoff’s plans to remain on the commission until the end of the current session of Congress, even though the chairman said he would recuse himself from cases involving Stoel Rives.
Wellinghoff had remained on the commission after his term expired in July while awaiting Senate confirmation of a successor. Colorado regulator Ron Binz withdrew from contention Oct. 1 in the face of opposition from Senate Republicans and coal interests.
Among those floated as potential nominees to the five-member commission are Arkansas Public Service Commission Chair Colette Honorable, who was elected last week as president of the National Association of Regulatory Utility Commissioners; Norman Bay, director of FERC’s Office of Enforcement; Tennessee Valley Authority board member Lynn Evans, and former Nevada regulator Rose McKinney-James. The commission is currently split between Democrats LaFleur and John Norris and Republicans Philip Moeller and Tony Clark.
Wellinghoff was FERC’s longest-serving chair, appointed in March 2009 after about two years as a commissioner.
A Harvard Law School graduate, LaFleur held numerous positions in New England Electric System and its successor, National Grid USA. She was senior vice president and acting CEO when she retired in 2007.
At FERC, LaFleur has concentrated on reliability and grid security issues. She co-chaired the FERC/NARUC Forum on Reliability and the Environment.
In a statement yesterday, LaFleur noted the commission’s role in ensuring reliability as the generation fleet faces retirements due to environmental regulations. “The Commission also has important work ahead in implementing Order No. 1000, setting transmission rates, and ensuring competitive markets work fairly and effectively for consumers,” she said.
Although she has backed the commission’s major initiatives, LaFleur has not agreed with all decisions. In March, for example, she dissented from an order requiring PJM to allocate the costs of large new transmission lines on a broad “postage-stamp” basis. LaFleur had favored a hybrid approach, combining a localized, “distribution factor” calculation and a broader assessment of benefits for postage-stamp allocation. The effect of that decision is limited to projects PJM had approved before February of this year. The grid operator proposed a hybrid method for projects approved after that time; FERC approved it in March.
ORLANDO — MISO officials last week signaled their opposition to PJM’s new limits on generation imports but said they will be capacity buyers in the near term as they face a shortfall that could result in load shedding as early as 2016.
MISO CEO John Bear said officials hope generation plants being built on Marcellus Shale deposits in Pennsylvania will provide relief as the region copes with a potential 5 to 7 GW capacity shortfall in 2016-17 due to the loss of coal-fired generation.
“We’d like capacity to come in this direction,” Bear told a press briefing on the sidelines of the National Association of Regulatory Utility Commissioners here. “In 16-17 we’ll be capacity challenged.”
MISO is completing analysis of a survey to determine the extent of its shortfall, with results due to be released as soon as next month. MISO officials fear their current 15% reserve margin could be reduced by more than half, even with the anticipated import of 1,000 MW of capacity from the south.
MISO currently meets a 1 event in 10-year loss of load expectation. “You’re going to have more events” in the future, Bear said. “We could go to three events a year.”
Asked about predictions of rolling blackouts, Bear responded, “that’s a little strong.” More likely, officials said, are localized load shed events, similar to what PJM experienced in September.
“You could expect more pinched operating days [forcing operators] into emergency operating procedures,” said General Counsel Steve Kozey.
No `Arbitrary Caps’
Officials said they can’t be certain they’ll be able to tap the new generation in PJM. “They’ve got a lot of retirements, so their flows will change,” Bear said. In an apparent swipe at PJM’s new import limits, he added: “We want flows to be dictated by the physics of the system, not any arbitrary caps.”
PJM stakeholders gave final approval Thursday to new methodology that will limit imports from MISO to 3,000 MW in next year’s base capacity auction. The limits do not apply to pseudo-tied generators that are under PJM control and meet other conditions. (See Members Deadlock on DR in Capacity Auctions)
Richard Doying, MISO executive vice president of operations, said PJM’s methodology for determining cross-border transfer capability is unduly conservative. The methodology dispute was the subject of a hearing before the Federal Energy Regulatory Commission in June. (See FERC Likely to Increase Pressure on PJM-MISO Joint Market Talks.)
The two RTOs are attempting to find agreement on a common methodology as part of their Joint and Common Market initiative. If no agreement is reached, said Bear, “FERC will call balls and strikes. They’ve already done that.”
Interchange Optimization
To optimize real-time interchange energy flows the two regions also are seeking ways to prevent traders from guessing wrong on prices and making uneconomic transactions. PJM stakeholders last month approved creation of a new product, Coordinated Transaction Scheduling, to reduce uneconomic flows with NYISO.
Optimizing flows between MISO and PJM will be more complicated, officials said, because of the higher transaction volume between the two regions.
Entergy Integration
MISO North and South (Source: MISO)
In the short term, MISO officials are focused on completing the integration of “MISO South” — Entergy, Cleco, Lafayette Utilities System, Louisiana Energy and Power Authority, Louisiana Generating and South Mississippi Electric Power Association. Market trials are being conducted now with the cutover scheduled for Dec. 19. The expansion will increase MISO’s peak load from 100,000 MW to 140,000 MW.
MISO lost in the competition for the Western Area Power Administration, Basin Electric and Heartland Consumers Power District, which decided to join the Southwest Power Pool (SPP). “The transmission cost allocation deal with SPP is advantageous to them,” Bear said. “We can’t overcome that.”
Lacking consensus, PJM Thursday dropped plans for a vote on measures to prevent speculation in the capacity auctions, returning the issue to a lower committee.
The Markets and Reliability Committee voted by acclimation to approve PJM’s recommendation to return the issue to the Capacity Senior Task Force.
(Source: Monitoring Analytics)
Because clearing prices in Incremental Auctions (IAs) are usually lower than those in the Base Residual Auction (BRA), participants can profit by selling capacity in the BRA and buying out their commitments in the IAs.
The CSTF voted earlier this month on 11 proposals to remove arbitrage incentives, with PJM’s proposal winning 60% support and the others ranging from 0% to 33%. Two-thirds of voters backed a change in the status quo.
Executive Vice President for Markets Andy Ott said officials hope the delay will allow more members to coalesce around a single proposal, resulting in “less angst” over whether the result will be approved by FERC.
Craig Glazer, vice president for federal government policy, noted that FERC staff raised questions about the issue at a FERC technical conference Nov. 13. Ed Tatum, of Old Dominion Electric Cooperative (ODEC) told the staff at the hearing that one reason for the disparity in prices between the Base and Incremental auctions is that PJM has procured too much capacity in the BRA — imposing excessive costs on load. (See FERC Staff Skeptical on PJM Demand Response Changes.)
Dan Griffiths, director of the Consumer Advocates of PJM States (CAPS), said the MRC would have rejected the staff proposal had it come to a vote. But he was skeptical about the chances of reaching consensus. “I don’t want anyone to think we’re going back to the CSTF to negotiate against ourselves,” he said.
Members spent the first half of yesterday’s CSTF session attempting to narrow their differences on the issue with no apparent breakthrough. Much of the discussion focused on developing penalties — and related credit requirements — tough enough to discourage speculation without creating barriers to entry for small market participants.
Task Force Chair Scott Baker called the delay a “reset … not a reboot,” saying the previous work had provided a “solid foundation” to move forward.
Market Monitor Joe Bowring said the committee needs to develop “clear enforceable rules” to define prohibited speculation. “Right now there’s nothing I can do regarding a participant that I know for a fact is engaging in behavior that we’re concerned about.”
The CSTF has three additional meetings scheduled through January. PJM hopes to win passage of a consensus plan by the end of January in time for a FERC filing in February.
The PJM Board of Managers may seek FERC approval for a plan to change the way demand response clears in capacity auctions despite stakeholders’ rejection of the plan.
That scenario emerged Thursday after a last-ditch compromise to address the RTO’s reliability concerns failed to win members’ endorsement. The proposal by Old Dominion Electric Cooperative won 58% support in a sector-weighted vote by the Members Committee, short of the two-thirds threshold to signal consensus.
After the meeting, Executive Vice President for Markets Andy Ott told RTO Insider that he will recommend the Board seek Federal Energy Regulatory Commission approval of a PJM staff proposal backed by generators. The Board met Friday and is expected to file its plan tomorrow, officials said yesterday.
PJM would be gambling that FERC will find its arguments more persuasive than most members did. The staff proposal, which garnered only 37% support from the Markets and Reliability Committee Nov. 14, did only slightly better at the Members Committee, winning support of nearly 45%.
Other DR, Capacity Initiatives
PJM had more success on a separate proposal that could increase capacity prices as the Members Committee gave final approval to PJM’s methodology for limiting imports.
At the Markets and Reliability Committee meeting earlier Thursday, members also approved a proposal giving PJM more flexibility in the way it dispatches demand response.
Members agreed to postpone an MRC vote on a fourth initiative to prevent arbitrage between the Base and Incremental capacity auctions. PJM officials said they wanted to return the issue to the Capacity Senior Task Force to seek revisions that could win broader stakeholder support. (See Arbitrage Fix Returned to Committee)
Need for Changes in DR
PJM says the volume of limited DR clearing in the capacity market must be reduced because 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.
Officials hope to implement the changes in February, when the RTO will set the parameters for its next Base Residual Auction. Representatives of load and DR providers, who said the PJM plan will increase costs and stunt DR, are certain to file interventions opposing the changes.
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%.
Compromise
ODEC described its proposal as a compromise between the PJM proposal and one submitted jointly by Southern Maryland Electric Cooperative and state public advocates which would reduce the 4.8% by only a portion of the 2.5% holdback.
The SMECO/Advocates proposal had been the most popular with members, falling just short of a two-thirds plurality at the MRC Nov. 14. Its support eroded Thursday, when it won only 54% support from the Members Committee.
Susan Bruce, representing the PJM Industrial Customer Coalition, said her group voted to support the ODEC proposal in an effort to craft a compromise. “This is certainly not our litigation position … at FERC,” she said.
Raghu Sudhakara, of Rockland Electric Co., said the ODEC proposal was less costly than PJM’s and “very close” to the PJM plan on reliability.
But ODEC’s plan was opposed by PJM as well as most generators and transmission owners. Stu Bresler, vice president of market operations, said the ODEC proposal might not hurt reliability in the short term but would in the long term by undercutting prices in the capacity auctions.
Jason Barker, of Exelon, said the plan could increase Installed Reserve Margins, ultimately costing customers more. “This is a bad proposal,” Barker said. “As a transmission owner and a generator operator we’re not satisfied with being `very close’ on reliability.”
Market Monitor Joe Bowring also panned the ODEC proposal, saying PJM’s plan was already a compromise from what he believes the RTO should do: eliminating limited DR altogether. Bowring said limited DR is suppressing the capacity market by $3 billion to $4 billion annually.
ODEC’s Ed Tatum said PJM was using “circular logic” in arguing that increased capacity costs under the RTO’s proposal will be counterbalanced by reduced energy prices. The purpose of the capacity market, he noted, is to solve the “missing money” problem — the fact that generators don’t earn enough in energy market revenues to cover their costs.
Late Change to Capacity Limit
The lid on external generation resources would limit imports in next year’s base capacity auction to 6,200 MW, a 17% drop from the volume that cleared in May’s auction. (See Members OK Capacity Import Limit; Prices May Rise.)
The Members Committee approved it with 85% support after a last-minute revision to eliminate a provision related to the requirements for external generators seeking an exemption from the cap.
As amended, the exemption will apply to external generators with firm transmission that commit to providing capacity in future auctions and have pseudo-ties allowing PJM to control their dispatch.
Deleted was a requirement that the generator be dedicated to an identified load in PJM. PJM officials said that the provision was discriminatory because it is not required of internal capacity resources. Bresler said it was also unnecessary because of the “must-offer” requirement.
Several members expressed unhappiness that the issue — which could have led FERC to reject the proposal — hadn’t been flagged earlier by PJM. Bresler said PJM officials learned of the issue several days earlier.
“I’m surprised and disappointed to have this change at the last minute,” said Reem Fahey, of Edison Mission. “I believe it makes the proposal a lot weaker.”
Dynegy’s Jason Cox, however, said PJM had to make the change. “This is one point we will happily protest if it ends up in a FERC filing,” he said.
Slower Transition Rejected
PJM’s initiative to increase the diversity of DR resources won 67.4% support of the MRC in a sector-weighted vote, just enough to clear the two-thirds threshold.
Because it passed the two-thirds hurdle, the committee did not vote on a proposed amendment by David “Scarp” Scarpignato, of Direct Energy, to slow the transition to quicker dispatch requirements.
Current rules require PJM operators to provide two hours’ notice before dispatching DR. Under the new rules, resources will be dispatchable in 30 minutes beginning delivery year 2015/16 unless they can demonstrate physical reasons for a longer dispatch. Curtailment Service Providers will be able to choose among 30-, 60- and 120-minute dispatch for DY 2014/15.
Scarp asked for a slower transition that would impose a 60-minute default in DR 2015/16 and delay the 30-minute requirement until DR 2016/17.
Marji Philips, also of Direct Energy, said a slower transition would avoid having to make changes in the middle of current contracts with customers. “Our contracts allow us to `reg out’ [change terms because of regulatory requirements] but that’s not how we like to work with customers,” she said.
PJM officials opposed the change, saying their proposal already represented a compromise from their preference to implement the 30-minute requirement next year. “We continue to over-call DR and allocate those costs to the members,” Bresler said.
Ott said PJM is concerned about having the flexibility by summer 2015 to address coming generation retirements.
Pepco, Maryland PSC Mollified
Representatives of Pepco Holdings Inc. and the Maryland Public Service Commission, who had earlier expressed concern about the impact of the changes on their “mass market” DR programs for residential and small commercial customers, said they were satisfied that the rules will provide them needed flexibility.
“PJM was very responsive,” said the PSC’s Walter Hall. “We do think we’ve come to a meeting of the minds.”
ORLANDO — Flat load growth and new technologies are challenges but not mortal threats to utilities, NARUC panelists said last week.
Jim Hempstead, Moody’s
Citing utilities’ political clout and outsized role in regional economies, Hempstead said: “We think before it becomes an intractable problem it will be dealt with in some way.”
New rate designs were among the solutions proposed in sessions on the challenges posed to current utility ratemaking and business models.
New Regulatory Models
“There’s no doubt that the regulatory model has to change,” Alan James, chairman of Macquarie Capital’s energy infrastructure group — owner of Duquesne Light Co. — told regulators. “I would ask you to look across the stakeholder groups and not just be focused on the customer.”
Maryland People’s Counsel Paula Carmody
Trackers — direct pass-throughs of costs to customers — are popular with utilities and a “positive” for credit ratings, said Hempstead.
But they face resistance from stakeholders such as Maryland People’s Counsel Paula Carmody, who pronounced herself “not a fan of trackers or forecasted rates.”
Former PSEG executive Anne Hoskins, appointed to the Maryland Public Service Commission in August, said she’d like to find ways to align regulators’ goals with the incentives of utility executives. “What are the metrics that they will respond to in compensation agreements?” she asked.
More Nimble
Other speakers said utilities must become more nimble and capitalize — rather than being victimized by — new technology.
“Allow utilities to invest in these disruptive technologies and they will indeed do so,” said Julien Dumoulin-Smith, a director in UBS Investment Research’s Utilities group.
James and Hempstead said that utilities should embrace commercial-scale solar power, until now the domain of independent developers.
Massachusetts Commissioner David Cash cited a “huge underinvestment” in research and development by utilities compared to similar size companies. “What is the energy app that customers are going to want?” he asked.
Bundling electricity with home security and other services”sounds very compelling to a consumer,” responded Carol Choi, vice president of integrated planning and environmental affairs for Southern California Edison. “But it’s much more challenging to achieve.”
Maryland Commissioner Kelly Speakes-Backman said innovation is difficult for utilities because regulators are risk-averse. “Regulators don’t like unknowns. The way to avoid that is not to allow it.”
Divergent Views
Maryland Public Service Commissioner Anne Hoskins
James predicted utility share prices will come under pressure as the economy improves and investors move away from “defensive” investments.
Other speakers said they saw reason for optimism.
“Zero load growth is a challenge,” acknowledged Choi. “You like to see people using your product.” But she said the electrification of transportation offers growth prospects.
“Resiliency investments are an upside area for utilities if they get it right,” said Dan Bakal, of CERES, a non-profit organization that advocates “sustainability leadership.”
Moody’s Hempstead said utilities are benefiting from reductions in regulatory lag, increases in trackers and improvements in “regulatory tone.” “We’ve got almost the entire industry on review for an upgrade,” he said.
PJM May Seek FERC OK Despite Stakeholder Opposition
The PJM Board of Managers may seek FERC approval for a plan to change the way demand response clears in capacity auctions despite stakeholders’ rejection of the plan.
That scenario emerged yesterday after a last-ditch compromise to address the RTO’s reliability concerns failed to win members’ endorsement. The proposal by Old Dominion Electric Cooperative won 58% support in a sector-weighted vote by the Members Committee, short of the two-thirds threshold to signal consensus.
After the vote, Executive Vice President for Markets Andy Ott told RTO Insider that he will recommend the Board seek Federal Energy Regulatory Commission approval of a PJM staff proposal backed by generators.
A Gamble
PJM would be gambling that FERC will find its arguments more persuasive than most members did. The staff proposal, which garnered only 37% support from the Markets and Reliability Committee Nov. 14, did only slightly better at the Members Committee yesterday, winning support of nearly 45%.
PJM says the changes are needed because 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.
Ott said he expects PJM to file its proposal with FERC before Thanksgiving in the hope of implementing the changes in February, when the RTO will set the parameters for its next Base Residual Auction. Representatives of load and DR providers, who said the PJM plan will increase costs and stunt DR, are certain to file interventions opposing the changes.
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%.
Compromise
ODEC described its proposal as a compromise between the PJM proposal and one submitted jointly by Southern Maryland Electric Cooperative and state public advocates which would reduce the 4.8% by only a portion of the 2.5% holdback.
The SMECO/Advocates proposal had been the most popular with members, falling just short of a two-thirds plurality at the MRC Nov. 14. Its support eroded Thursday, when it won only 54% support from the Members Committee.
The ODEC plan was opposed by generators, transmission owners and PJM. Stu Bresler, vice president of market operations, said the ODEC proposal might not hurt reliability in the short term but would in the long term by undercutting prices in the capacity auctions.
Market Monitor Joe Bowring also panned the ODEC plan, saying PJM’s proposal was already a compromise from what he believes the RTO should do: eliminating limited DR altogether. Bowring said limited DR is suppressing the capacity market by $3 billion to $4 billion annually.
Other DR, Capacity Initiatives
PJM had more success on a separate proposal that could increase capacity prices as the Members Committee gave final approval to PJM’s methodology for limiting imports. The proposal was approved by 85% of stakeholders.
At the Markets and Reliability Committee meeting earlier Thursday, members also approved a proposal giving PJM more flexibility in the way it dispatches demand response. The plan won 67.4% support in a sector-weighted vote, just enough to clear the two-thirds threshold.
Members agreed to postpone an MRC vote on a fourth initiative to prevent arbitrage between the Base and Incremental capacity auctions. PJM officials said they wanted to return the issue to the Capacity Senior Task Force to seek revisions that could win broader stakeholder support.
The CSTF voted earlier this month on 11 proposals on the arbitrage issue, with PJM’s proposal winning 60% support and the others ranging from 0% to 33%. Two-thirds of voters backed a change in the status quo.
RTO Insider will have an updated report on the capacity market and demand response initiatives — plus other action from the Members and Markets and Reliability committees and highlights from the National Association of Regulatory Utility Commissioners (NARUC) annual meeting in Orlando — in Tuesday’s newsletter.
Below is a summary of the issues scheduled for votes 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 Insiderwill be in Wilmington for all the action and will bring you a complete recap in next week’s newsletter.
Markets and Reliability Committee
2. PJM MANUALS (9:10-9:50)
See details in posted materials on PJM’s calendar.
3. DEMAND RESPONSE AS AN OPERATIONAL CAPACITY RESOURCE (9:50-10:20)
The committee will be asked to endorse PJM’s proposal to change the design and dispatch of DR. PJM called for the changes after heat waves in July and September, which they said illustrated the need to make quicker and more targeted use of the resources. The changes under consideration would reduce DR’s minimum lead and run times as well as expanding use of subzonal dispatch and eliminating the need to declare an emergency before dispatch.
The PJM proposal (Package A) won 81% support in a vote by the Capacity Senior Task Force Nov. 5-12. Five other proposals won only 7% to 35%. All but 5% of voters said they favored a change to the status quo.
During a First Read at last week’s MRC, Bruce Campbell, of demand response aggregator EnergyConnect, said the changes proposed by PJM in this and MRC agenda item #4 amount to a “bait and switch” that will reduce customer participation in load reduction programs while increasing administrative costs.
David “Scarp” Scarpignato, of Direct Energy, said his company might back PJM’s proposal if the RTO agreed to a longer transition period on the provision allowing 30-minute dispatch.
Without such a change, Scarp said, support for the PJM proposal could prove thinner than was apparent in the task force vote. “I think we saw when issues proceed to a sector-weighted vote things don’t pass quite so easily,” he said, referring to the MRC’s rejection of PJM’s proposal on the treatment of limited DR in capacity auctions (see MC agenda item 4 below).
PJM Executive Director for System Operations Mike Bryson said he would be reluctant to accept a slower transition. PJM’s original plan called for a quicker transition than its current proposal, Bryson said.
The PJM proposal would make the following changes to the status quo:
Trigger used to initiate Emergency DR load reduction: PJM would be able to dispatch “Pre-Emergency DR” prior to emergency conditions but continue to dispatch “Emergency DR” under emergency conditions.
Notification lead time: DR could be dispatched as quickly as 30 minutes, down from the currently 1-hour or 2-hour lead time. Resources that are physically incapable of 30-minute dispatch would be remain at a 60- or 120-minute lead time. The change will be phased in, with Curtailment Service Providers choosing their lead times for delivery year 2014/15.
Maximum number of events: Unchanged (10/year or unlimited, based on product type).
Minimum event duration: Reduced from 2 hours to 1 hour.
Performance Metrics (Measurement & Verification): PJM currently measures compliance for full wall-clock hours. Going forward, PJM would measure compliance for all hours when DR is dispatched for more than ½ of the hour.
Maximum event duration: Unchanged (6 hours or 10 hours, depending on product type).
Locational Designation: Current rules allowing PJM to dispatch on a subzonal (zip code) basis if created prior to the operating day will remain unchanged for 2014/15. Beginning in 2015/16, PJM will be able to create and dispatch subzones on the operating day.
Strike Price: Currently $1,000 + 2x reserve penalty factors (effectively $1,800/MWh) for all DR, will differ based on lead time flexibility starting in DY 2014/15.
30 min = $1,000 + penalty factor – $1.00
60 min = $1,000 + (penalty factor/2)
120 min = $1,100
Energy market participation remains voluntary, but the maximum economic offer price would be reduced from the current maximum ($1,000 + 2x reserve penalty factor) to $1,000 + penalty factor – $1.00.
The committee will be asked to endorse a proposal intended to eliminate arbitrage opportunities in capacity auctions. Because clearing prices in Incremental Auctions (IAs) are usually lower than those in the Base Residual Auction (BRA), participants can profit by over-committing in the BRA and buying out their commitments in the IAs.
The CSTF voted on 11 proposals with PJM’s proposal (A1) winning 60% support and the others ranging from 0% to 33%. Two-thirds backed a change in the status quo.
The PJM proposals would make the following changes to the status quo. Changes would be applicable to all future incremental auctions upon FERC approval:
Capacity Resource Deficiency Charge: Would increase to 2 times the Base Residual Auction clearing price (BRA CP) from the current penalty (weighted average clearing price + higher of 20% of clearing price or $20).
PJM release of committed capacity: PJM currently can release capacity in all three Incremental Auctions due to decreases in the reliability requirement. The reliability requirement reduction must be greater than 500 MW or 1% to be considered in 1st and 2nd IA; no threshold in 3rd IA. Under the proposed change, PJM may consider increasing early auction threshold quantities in order to avoid potential for release in one auction and buyback in subsequent auction.
PJM procurement of capacity due: PJM currently can procure capacity due to increases in reliability requirement in all 3 IAs. The reliability requirement increase must be greater than 500 MW or 1% to be considered in 1st and 2nd IA; no threshold in 3rd IA. Going forward PJM would consider increasing early auction threshold quantities in order to avoid potential for buyback in one auction and release in subsequent auction.
PJM Sell Offer Price: PJM currently uses an upward sloping offer curve with the starting price based on the intersection of the updated Variable Resource Requirement (VRR) curve and vertical line at current commitment level. The same procedure would be used in the future but the price would be floored at the BRA resource clearing price.
PJM Buy Bid Price: No change. The procedure would continue to be based on a downward sloping bid curve with the starting bid price based on the intersection of the updated VRR curve and vertical line at current commitment level.
Mitigation: Existing generation capacity is currently subject to same IA mitigation as in BRA; may elect Market Seller Offer Cap (MSOC) of 1.1 times BRA CP for 3rd IA. Under the new rules, existing generation capacity may elect MSOC of greater of 1 times BRA CP or their MSOC in first and second IAs; may elect MSOC of 1.1 times BRA CP for Final IA. Planned generation capacity resources are not subject to offer capping.
(Source: Monitoring Analytics)
Number of Incremental Auctions: The current three IAs would be reduced to two. The first would be conducted between the time of current 1st IA and current 2nd IA; the second IA would occur at the same time as current 3rd IA (after EFORd lock-down).
Allocation of 2.5% Short-term Resource Procurement Target (STRPT) to IAs: Current rules allocate 0.5% each to the first and second IAs and 1.5% to the third. This would change to 1% in the first IA and 1.5% in the last IA.
Incremental Auction Settlement Calculation: Cleared sell offers and buy bids currently settle against IA CP. The PJM proposal would clear sell offers against the IA CP. Cleared buy bids from resources committed in a previous RPM auction will settle against IA CP plus pay the difference between the auction clearing price in which the resource first cleared and the IA CP for cleared buy bid quantity. PJM buy bids will pay the IA CP. If the IA clearing price is greater than the relevant IA or BRA price at which a resource was first committed, there is no settlement adjustment.
Incremental Auction Settlement Timing: Unchanged (paid on daily basis throughout delivery year).
Incremental Auction Settlement Allocation: Not specified under current rules. PJM proposal would be based on cleared buy bid quantity x IA CP fund cleared IA supply. Cleared buy bid quantity x (applicable BRA or IA CP – IA CP) allocated to zones proportional to daily share of total reliability charges.
5. PRICE FORMATION AND RESERVE REQUIREMENTS DURING HOT WEATHER OPERATIONS (10:50-11:20)
The committee will be asked to endorse PJM’s proposed problem statement and issue charge to consider changing the real-time pricing mechanism.
PJM said the current methodology is depressing energy and reserve prices. The initiative would allow system operators to increase reserve requirements under certain circumstances, such as when operators are carrying additional resources to cover units at risk of being shut down because of environmental limitations or mechanical problems. Requirements also could be boosted when operators have data quality concerns or are uncertain about load or interchange.
The revised methodology could increase reserve and real-time energy prices while reducing uplift.
The committee will be asked to give final approval to proposed Tariff and Reliability Assurance Agreement (RAA) revisions limiting the volume of capacity that can clear in future capacity auctions. PJM’s proposal was overwhelmingly approved by the MRC last week.
4. CLEARING OF LIMITED DEMAND RESPONSE (DR) RESOURCES (2:10-2:55)
The committee will be asked to approve a proposal by Old Dominion Electric Cooperative (ODEC) to change the way limited DR clears in capacity auctions. ODEC’s Steve Lieberman said it is a compromise between a PJM proposal and one by state consumer advocates and the Southern Maryland Electric Cooperative (SMECO).
(Source: Old Dominion Electric Cooperative)
The PJM proposal was rejected by the MRC last week, winning only 37% support in the sector-weighted vote, while the SMECO/Advocates alternative won 64%, just short of the two-thirds threshold needed to send it to the MC.
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/Advocates proposal would reduce the 4.8% by only a portion — to be determined — of the 2.5% holdback.
The maximum amount of Limited DR that can clear the BRA would be based on saturation analysis (to be revisited post-summer 2014. There would be no limit on the amount of Annual DR that can clear the BRA. Extended DR can compete with Annual resources between the Installed Reserve Margin (aka Reliability Requirement) and VRR Curve.
The Short Term Resource Procurement Target (STRPT) would be allocated to both Limited DR (LDR) and Extended DR (XDR) under allocation ratios:
• Allocation of STRPT to LDR: “LDR Ratio” = Max Limited DR Constraint / Max Extended Summer Constraint.
• Allocation of STRPT to XDR: “XDR Ratio” = STRPT less the STRPT allocated to allocated to Limited DR.
Lieberman said his proposal would allow more LDR to clear in the BRA than PJM’s proposal but less than in the SMECO/Advocates package. That would allow PJM to meet its reliability requirements at a lower cost to load than the PJM proposal, he said.
The saboteurs who shot up a Pacific Gas & Electric Co. substation in April were “very experienced marksmen,” a former PG&E executive told PJM’s Grid 20/20 conference Tuesday.
At least two gunmen were believed involved in the attack on PG&E’s Metcalf 500/230 kV substation near San Jose about 2 a.m. April 16.
Mark Johnson, formerly vice president of transmission operations for PG&E, said the gunmen targeted transformer radiators, firing an estimated 150 rounds. The gunmen hit 10 of 11 banks, causing a “slow bleed” resulting in the loss of 52,000 gallons of cooling oil.
The shooting occurred minutes after the suspects are believed to have cut underground fiber optic cables a half mile from the substation, briefly knocking out phone and 911 service in the area.
Surveillance video shows bullets hitting a chain link fence outside Pacific Gas & Electric Co.’s Metcalf substation during an attack April 16.
“These were not amateurs taking potshots,” Johnson said. “…My personal view is that this was a dress rehearsal” for future attacks.
It took nearly a month to replace the radiators and return the substation to normal operations.
“It clearly demonstrates that a chain link fence is not enough to secure a substation,” Johnson said. “Obviously solid perimeters would be nice but that can be very expensive.”
The incident also indicated a need to reconsider the deployment of security cameras, which are typically aimed down the fence line to spot trespassers. “If we had cameras looking out we might have seen the perpetrators,” he said.
Officials believe more than one person was involved because of the number of shots fired and because of the logistics of getting into the manhole to cut the fiber optic lines, Johnson said.
He declined to say afterward whether the suspects are believed to be present or former utility employees, acknowledging “wide speculation” on that question.
The incident underscored a risk raised last year by Federal Energy Regulatory Commission Chairman Jon Wellinghoff. Wellinghoff told Bloomberg News that he feared saboteurs with guns could target transformers. Transformers are often custom built and can take 18 to 36 months to replace, Wellinghoff said.
