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November 8, 2024

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MRC MC Preview

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 Insider will 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.

More information:

4. REPLACEMENT CAPACITY / PROSPECTIVE CAPACITY RESOURCE INCENTIVES (10:20-10:50)

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.

  • Percent of Capacity Replaced (Source: Monitoring Analytics)
    (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.

More information:

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.

Previous coverage: PJM: Change Real-Time Pricing

6. REGULATION PERFORMANCE SENIOR TASK FORCE (RPSTF) (11:20-11:30)

The committee will be asked to sunset the Regulation Performance Senior Task Force, which has completed the tasks assigned to it in its charter.

More information: Kermit Study Report – To determine the effectiveness of the AGC in controlling fast and conventional resources in the PJM frequency regulation market

Members Committee

3. MAXIMUM IMPORT LEVEL (1:25-2:10)

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.

Previous coverage: Members OK Capacity Import Limit; Prices May Rise

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).

ODEC Compromise Proposal (Source: Old Dominion Electric Cooperative)
(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.

Previous coverage: PJM Wins One, Loses One on Capacity Market Changes

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Substation Saboteurs ‘No Amateurs’

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.
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.

The shooting prompted the California Independent System Operator to issue an alert asking residents in the region to cut their electricity use. (See Substation Sabotage Raises Concerns over NERC Alerts.)

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.

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PJM Grid Conference Focuses on Storms, Cybersecurity

Storms and cybersecurity were the subjects as PJM held its third annual Grid 20/20 conference in Philadelphia this week.

PJM CEO Terry Boston and Federal Energy Regulatory Commissioner Cheryl LaFleur kicked off the conference Monday night at the Sheraton Society Hill.

Culture of Resiliency

In keeping with the theme of this year’s conference, LaFleur told an audience of about 100 about the need to create a “culture of resiliency.”

“When there is a problem on the grid, very rarely is it the result of one thing. It’s a succession of mistakes where if you had defense in depth it could have been stopped,” she said. “There has to be a line of sight between what people are doing and the bigger issues…These little thing will add up to the big things.”

In response to question about FERC taking a role in directing the construction of natural gas infrastructure, LaFleur said: “I have an open mind to anything that will work.”

But she added, “I take kind of a Hippocratic Oath: Don’t screw up what was working before you got there.”

‘Takes a Licking’

About 180 people gathered for a daylong session Tuesday.

Boston recalled the old Timex watch commercials in explaining his definition of grid resilience: “It takes a licking and keeps on ticking.” (For those of you too young to remember, here’s a link.)

PJM’s goal, Boston said, is to prevent damage to the grid when possible and reduce damage when not.  “We can’t prevent every cascading outage but we certainly are working to do so,” he said.

Former Pennsylvania Governor and Homeland Security Secretary Tom Ridge was the keynote speaker.

Protecting critical infrastructure requires attention from utility CEOs, Ridge said. “Cybersecurity is not an information technology problem, it’s a business risk.”

Scott Aaronson, director of national security policy for the Edison Electric Institute, said government was initially slow to respond to industry requests for help in protecting their assets. “If a plane crashes into a power plant no one would ask you, `where was your Air Force?’” he said.

But he said recent meetings among utility CEOs and senior officials at the Department of Energy, Department of Homeland Security, the FBI and Secret Service have been fruitful. “We did more in the last year than we did in the last six years on government and energy coordination.”

More needs to be done, said Mike Smith, a senior cyber policy advisor at the Department of Energy.

“We can’t continue to issue reports and share PDFs. We’ve got to get to machine-speed” communications.” The concern is not how to get access to more classified information, he said, but how to “share actionable [unclassified] information instantly.”

Hardening Infrastructure

Officials of two utilities talked about their actions to “harden” their systems, which were battered a year ago during Superstorm Sandy.

“It’s a great time to be in the concrete business in New York City,” said John McAvoy, who will take over as president and CEO of Consolidated Edison Inc. in January. “We’re building walls around anything that doesn’t move.”

Frank Czigler, manager of Transmission Strategy & Regional Interface at Public Service Electric & Gas Co. described his company’s proposed $3.9 billion “Energy Strong” storm hardening plan, which is being weighed by the New Jersey Board of Public Utilities.

Miles Keogh, director of grants & research at the National Association of Regulatory Utility Commissioners, said utilities “have a really hard time making a sale” to regulators on the need for such spending. The perception is “it’s just an excuse to raise rates,” he said.

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FERC Staff Skeptical on PJM Demand Response Changes

Federal Energy Regulatory Commission staff signaled Wednesday that the commission may require PJM to change rules requiring demand response providers to provide “sell offer plans” in order to participate in capacity auctions.

At a nearly four-hour technical conference, members of FERC’s Office of Energy Market Regulation (OEMR), Office of General Counsel (OGC) and Office of Energy Policy and Innovation (OEPI) questioned a three-member panel including PJM Executive Vice President of Markets Andy Ott. The subject was the demand response “plan enhancements” approved by stakeholders in June and submitted to FERC in August (ER13-2108). (See PJM Demand Response Providers Decry Scrutiny, “Freight Train” of Changes)

Ott said the offer plans — and a requirement that they be certified by a corporate officer — were needed to prevent DR providers from gaming the capacity market by selling in the Base Residual Auction and buying out their obligations at much lower prices in Incremental Auctions.

Ott was backed by Kenneth Carretta, managing director of power market development for PSEG Energy Resources and Trade, LLC, who represented generators on the panel. Carretta said the officer certifications were similar to those required of generators offering capacity.

But the third member of the panel, Frank Lacey, vice president of regulatory and market strategy at demand response aggregator Comverge Inc., said PJM’s changes are unnecessary and will stunt the development of DR.

Commission Order

The technical conference was ordered by the commission Oct. 1 when it suspended PJM’s proposed changes to its Tariff and Reliability Assurance Agreement for five months pending further investigation. The commission said more investigation was needed to determine whether PJM’s filing cleared the “just and reasonable” threshold.

The commission’s two Republican members, Philip Moeller and Tony Clark concurred in the order but said their “initial assessment is that PJM’s filing represents a balanced approach for resolving its reliability concerns.”

About 50 PJM stakeholders and attorneys listened during Wednesday’s conference, including Market Monitor Joe Bowring and PJM General Counsel Vince Duane. Commissioner Moeller and policy advisor Jason Stanek also attended part of the conference.

Auction-Performance Link

FERC Staffers questioned why PJM could not address its concerns under current rules and pressed for evidence of a linkage between auction behavior and reliability threats.

Ott said some DR aggregators provide PJM only “cursory” one-paragraph assurances of their intent to procure resources to meet their obligations.  They “tend to be the ones that replace a lot” of capacity in the incremental auctions.

“There is no evidence that there’s been a capacity shortfall because of incremental auction purchases,” Lacey said. “…There is no evidence that DR won’t perform.”

Demand response “has consistently delivered,” Ott acknowledged. “It has been there when called.”

Chris Young, of OEPI, questioned whether PJM was being reasonable in the information it seeks to require from DR providers. “You don’t expect generators to purchase steel before” winning a capacity contract, he noted.

Michael Goldenberg, of OGC, asked how PJM could distinguish between good and bad seller plans, wondering why the RTO hadn’t filed “fact-based parameters instead of this kind of reciprocal analysis.”

Certifying Intangibles

Lacey complained that the proposed requirements were speculative and lacked clear definitions.

PJM’s officer certifications for transmission and generation are based on tangibles, such as the percentage of right of way acquired, Lacey said. “That’s an easy certification to make. Either it’s true or it’s not true.”

In contrast, DR providers are being asked to certify plans to acquire customers three years in advance when most customers only sign one-year contracts with their Curtailment Service Providers. “Customers don’t look four years in advance,” he said.

“There’s nothing that says if the rules change we can get out. Or if the economy changes.” Absent such a definition, Lacey said, DR providers risk getting referred to FERC for enforcement action, “and that is a very scary thing,” he said.

“We’re asking for due diligence,” Ott responded. “We’re not asking them to predict the future.”

PJM is intending only to remove the “incentive and opportunity for certain DR providers to speculate,” Ott added. “Then they’re not delivering anything. They’re just taking money out of the market.”

Carretta added: “There’s a lot of rules generators don’t like — that don’t agree with our business models.”

RPM Shortcomings

Ott said the Reliability Pricing Model (RPM) is an “administrative construct” and not a true market. “The IAs simply are not going to be this wonderful liquid market to… discipline behavior,” he said.

Lacey responded: “Does RPM work? If it does let it go” and prices will recover. “If it doesn’t work then we have a much bigger problem.”

Lacey said Comverge both buys and sells capacity in the Incremental Auctions, acknowledging his company had profited by buying out of some obligations in the IAs. “We have obligations to shareholders too,” he said, adding: “We’re not going to buy out of our entire position — that’s our business.”

`Overprocurement’

Several audience members also made comments during the conference.

Ed Tatum, of Old Dominion Electric Cooperative, said 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. The IAs offer load an opportunity to at least “get 20 cents back on the dollar,” he said, addressing the FERC staffers. “I ask you not to take that away.”

Market Monitor Joseph Bowring, however, said “PJM’s not going far enough” in its actions to end arbitrage opportunities.

Post-Conference Comments

Post conference comments in the case are due Nov. 27, with reply comments due a week later on Dec. 4.

The commission must weighing PJM’s filing against Congress’ direction in the 2005 Energy Policy Act that “unnecessary barriers to demand response participation in energy, capacity and ancillary service markets shall be eliminated.”

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Members OK Capacity Import Limit; Prices May Rise

The Markets and Reliability Committee overwhelmingly approved revised methodology that will limit external generation resources in next year’s base capacity auction to 6,200 MW ­– a 17% drop from the volume of imports that cleared in May’s auction.

The proposal, which will also set five import zones with their own limits, won 87% support in a sector-weighted vote, sending it on to the Members Committee for a final vote next week.

Impact Uncertain

The change will put upward pressure on capacity prices. How much it will help generators inside PJM, who have been hurt by the fall in capacity prices resulting from competition from both imports and demand response, is unclear.

In response to a question from Susan Bruce, representing the PJM Industrial Customer Coalition, PJM Executive Vice President for Markets Andy Ott said he believed the import limit will be “smaller magnitude in dollars” than a demand response proposal that members rejected yesterday. The DR proposal would add about $1 billion a year in capacity costs according to PJM’s simulations. (See related story PJM Wins One, Loses One on Capacity Market Changes)

In response to a later question from the Maryland Public Service Commission’s Walter Hall, Ott gave a response that seemed to undercut that certitude, saying “We do not have an estimate, nor could we get an estimate, as to the import limit” impact.

There are a number of variables that could affect future clearing prices, including the strength of the economy and the volume of demand response. DR offers dropped 27% in May from the 2012 auction. A rebound in DR offers next year could at least partially offset the import restriction.

Import Growth

The new methodology grew out of concerns that PJM might lack sufficient transmission capacity to accommodate its growing volume of capacity imports. Cleared imports grew from about 3,000 MW to more than 4,500 MW in 2009-2012 before more than doubling to nearly 7,500 MW this year.

Based on current assumptions for 2018, PJM’s First Contingency Incremental Transfer Capability (FCITC) is 9,700 MW. Because 3,500 MW of the import capability must be reserved for the Capacity Benefit Margin, the cap on imports clearing in the BRA would be 6,200.

The new rules set both overall limits and individual limits for five “external source zones.” Generators in the five zones will compete against each other until the individual caps or the overall limit is hit.

External generators with firm transmission that commit to providing capacity in future auctions and have pseudo-ties allowing PJM to control their dispatch will not count against the limits as long as total imports don’t exceed the total firm service that has been granted for that delivery year.

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PJM Wins One, Loses One on Capacity Market Changes

Members yesterday approved PJM’s methodology for limiting capacity imports but soundly rejected the RTO’s proposal to change the way demand response clears in the annual capacity auction.

The import cap passed easily, with 87% support in a sector-weighted vote of the Markets and Reliability Committee. (See related story Members OK Capacity Import Limit; Prices May Rise.)

But PJM was unable to win support for its view on how demand response should be treated in the auction, as members signaled a preference for an alternative by state consumer advocates and the Southern Maryland Electric Cooperative (SMECO). The alternative fell narrowly short of the two-thirds plurality needed to send it to a final vote by the Members Committee, leaving the issue in limbo.

Load Rebels

Representatives of public power, industrial load, retail marketers and demand response aggregators teamed up in a rebuke to PJM management, which had rejected the SMECO/Advocates proposal as not addressing the RTO’s reliability concerns.

The PJM proposal, which was backed by generation representatives, received only 37% support in the sector-weighted vote, while the alternative won 64%. PJM’s proposal had received support of nearly three-quarters of voters at the Capacity Senior Task Force, with 95% calling for a change in the status quo.

As has happened in the past, however, proposals that seem to have wide support at the subcommittee level — where utilities with PJM memberships for multiple subsidiaries can dominate voting — can falter when the vote is weighted by sector at the senior committees.

Only generation owners (11-3) and transmission owners (9-3) supported the PJM proposal. End-use customers (0-13) electric distributors (2-29) and other suppliers (6-20) were overwhelmingly opposed. The coalitions were flipped for the SMECO/Advocates proposal. (See vote tally.)

No Members Committee Vote

PJM Executive Vice President for markets Andy Ott, who had flatly rejected the SMECO/Advocates proposal at last month’s MRC meeting (see States, LSEs on Collision Course with PJM over DR Changes), said after the votes that PJM management would not put the issue on the agenda for next week’s Members Committee meeting.

The PJM Board of Managers ­could act unilaterally to send the PJM proposal to the Federal Energy Regulatory Commission for approval. Given the lack of stakeholder support, however, it would do so at the risk of being rejected. FERC has already signaled uneasiness with a previous change to DR that was approved by stakeholders. (See related story on Wednesday’s technical conference on PJM’s DR “plan enhancements.”)

Impact of PJM's Proposed Changes (Source: PJM Interconnection, LLC)
Impact of PJM’s Proposed Changes (Source: PJM Interconnection, LLC)

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.

Failed to Make Reliability Case

Before the vote, several members said PJM officials had failed to make their case: That the current method of clearing DR risked recreating a vertical demand curve that would lead to boom-bust capacity markets and undermine reliability.

“I don’t believe there’s a real issue with the demand curve,” said Bruce Campbell, of demand response aggregator EnergyConnect. Ken Schisler, of DR aggregator EnerNOC, called the proposal a “radical departure.”

Bill Schofield, who represents the PJM Public Power Coalition, said there was a “diversity of opinion” among coalition members but that most thought PJM’s proposal “unnecessarily conservative.”

Compromise Attempt

After the votes, the committee broke for lunch, then returned for first reads on three issues that will be brought to a vote next week. (See next week’s MRC/MC Preview for details.)

At the end of the meeting, Steve Lieberman of Old Dominion Electric Cooperative (ODEC) gave a presentation on what he called a compromise between the PJM and the SMECO/Advocates proposals.

The proposal was greeted skeptically by generation representatives and PJM.

Jason Barker, of Exelon, said it failed to address the problem identified by PJM and was uncompetitive because it values all year-round resources, including annual DR, the same as limited products.

PJM officials said they didn’t understand how the proposal would work without reducing the amount of annual DR. “It’s almost like you’re trying to squeeze a stone,” said Ott.

But PJM’s Jeff Bastian said that PJM might consider incorporating one aspect of the ODEC proposal into PJM’s plan.

Market Monitor Joe Bowring said that would be a mistake. “From our view, the PJM proposal was a compromise that didn’t go far enough. Attempts to move away from that is a move in the wrong direction.”

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MRC Preview

Below is a summary of the issues scheduled to be brought before a special meeting of the Markets and Reliability 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 proceedings and will provide a full report.

ENDORSEMENTS/APPROVALS

2. MAXIMUM IMPORT LEVEL (9:10-10:00)

Members will be asked to approve a methodology for limiting the volume of imports that clear in future capacity auctions. (See Import Cap Approved Capacity Prices May Rise)

3. CLEARING OF LIMITED DEMAND RESPONSE (DR) RESOURCES (10:00-11:00)

Members will be asked to approve PJM’s proposal to cap the volume of Limited Demand Response that can clear in the capacity auction.

PJM’s proposal won support of 75% of the voters at the Capacity Senior Task Force, besting three alternatives proposed by states and demand response aggregators. None of those bids won support of more than a quarter of the 182 voters. (See States, LSEs on Collision Course with PJM over DR Changes.)

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.

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%.

Impact of PJM's proposed changes on clearing of limited DR (Source: PJM Interconnection, LLC)
Impact of PJM’s proposed changes on clearing of limited DR (Source: PJM Interconnection, LLC)

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%.

An alternate proposed by Southern Maryland Electric Cooperative (SMECO) and state 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.)

PJM officials said their proposal will ultimately save consumers money by ensuring adequate capacity and keeping energy market prices low.

PJM wants the new rules in place by February, when the RTO must post planning parameters for the 2014 Base Residual Auction.  If no proposal wins 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.

FIRST READINGS

The MRC also will hear first reads on three other proposals that will be brought to a vote at a second MRC meeting Nov. 21.

4. DEMAND RESPONSE AS AN OPERATIONAL CAPACITY RESOURCE (11:00-1:30)

Members will be presented with the results of a Capacity Senior Task Force votes concluding today on six proposals to change the way DR is dispatched. (See Too Many Choices: DR, Auction Changes Go To Vote.)

5. REPLACEMENT CAPACITY / PROSPECTIVE CAPACITY RESOURCE INCENTIVES (1:30-2:30)

Members will be presented with the results of a Capacity Senior Task Force votes concluding today on 12 proposals to prevent speculation in the capacity auctions. (See Too Many Choices: DR, Auction Changes Go To Vote.)

6. PRICE FORMATION AND RESERVE REQUIREMENTS DURING HOT WEATHER OPERATIONS (2:30-3:30)

PJM will present a proposed problem statement and issue charge to consider increasing reserve requirements under certain circumstances. The revised methodology could increase reserve and real-time energy while reducing uplift. (See PJM: Change RT Pricing)

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MIC Begins Work on Curve-Smoothing, Gen Adders

The Market Implementation Committee began work last week on an initiative to create more accurate capacity market price curves and a recommendation by the Market Monitor to eliminate adders for frequently mitigated units (FMU).

Load Curves

An issue charge proposed by Exelon in June calls for modifying the algorithm used for publishing supply curves from the annual capacity auction.

Exelon and other stakeholders are seeking improvements to the supply curve currently produced by the Market Monitor, which masks individual price-quantity offers. Exelon said the current curves — a compromise intended to balance transparency against disclosure of commercially sensitive data — aren’t accurate enough for use in analysis. (See Capacity Supply Curve Review Gets MIC OK.)

The current method is the result of a Federal Energy Regulatory Commission order in a dispute over PJM’s proposal to publish price-quantity pairs after the 2010 Base Residual Auction.

One generator representative noted that the capacity auction results have far-reaching implications for generators and other market participants. Because the curves are imprecise and not released until several days after the auctions, “we are sometimes at a disadvantage to explain certain outcomes” in the auction, he said.

Anachronistic

The committee also began work on a problem statement and issue statement to consider whether to end extra compensation for generators that frequently run on cost-based offers under market power mitigation rules. (See PJM Reconsiders Adders on Cost-Capped Generators.)

Market Monitor Joe Bowring called for the review, saying the adders are no longer needed because of the introduction of the capacity market in 2007 and changes to scarcity pricing rules in 2012. The adders are “anachronistic” Bowring told the committee Wednesday.

He softened his previous statements somewhat, saying that PJM might need to keep the adders for a few “outliers.”

Less than 1% of megawatts sold last year were offer capped. But because the affected units are concentrated in load pockets they can have more significant local impacts, Bowring said.

Next Meeting

Most of Wednesday’s session was taken up with introductory educational briefings from PJM’s Tom Zadlo on the two issues. The committee will hold its second meeting on the two issues December 4.

More information:

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Planners Choose $1.2B PSEG Short Circuit Fix

PJM planners expect to recommend construction of a $1.2 billion double circuit 345 kV line to address a short circuit problem in the PSEG zone, ruling it less expensive than other alternatives.

The 2012 Regional Transmission Expansion Plan identified several busses where fault currents exceed 80 kA.

Planners evaluated several alternatives, including rebuilding stations to a 90 kA standard, installing current limiting reactors and installing fault current limiters.

PSEG Short Circuit Solution (Source: PJM Interconnection, LLC)
PSEG Short Circuit Solution (Source: PJM Interconnection, LLC)

The solution chosen will isolate the Hudson 230 kV from the 138 kV at Marion and 345 kV at Farragut by converting the 138 kV buses and transmission facilities between Linden and Bergen to a double circuit 345 kV capacity.

It is projected to cost $1.2 billion but will incorporate more than $1 billion in existing baseline projects, resulting in an “avoided cost” of $160 million.

Planners rejected a recent stakeholder proposal to build parallel 700 MW HVDC converter stations. That would have cost $614 million but would not have addressed the reliability problems to be fixed by the other baseline projects.

As a result, the double circuit project “is significantly less expensive than the HVDC alternative,” PJM’s Paul McGlynn told the Transmission Expansion Advisory Committee Thursday.

An independent consultant, Burns & Roe, will validate costs and schedules and identify risk areas in the project before planners recommend it to the PJM Board of Managers.

The project, which will be constructed by PSEG, will take about four years and will require acquisition of additional underground and underwater rights of way and land acquisitions for expansion of several substations.

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Pay Hike for Black Start Generators?

Payments to black start generators could increase by 27% to more than 500% under proposals scheduled to go to a stakeholder vote today.

The System Restoration Strategy Task Force will vote through Nov. 20 on up to four alternatives to the current compensation method for black start units.

An analysis presented to the task force in October showed the annual operations and maintenance compensation for a 20 MW combustion turbine would increase from the current $51,000 to more than $312,000 under NRG Energy’s market based “Proxy” formula. The PJM-Market Monitor “Modified Incentive” would boost compensation to $65,000, while Dayton Power & Light Co.’s “Minimum Incentive” would set compensation at $71,000.

While the increases could be large compared to current compensation, the overall impact on prices would be limited. Black start charges were responsible for only $0.03 of the $35.23/MWh total price of wholesale electricity in 2012 (0.1%), according to Monitoring Analytics’ State of the Market Report.

The Proxy proposal was based on a review of practices in New York and New England as well as cost figures provided by more than 50 generators that responded to PJM’s recent solicitation for black start resources. It would increase capital compensation more than six-fold and payments for fuel storage more than eight-fold.

Old Dominion Electric Cooperative (ODEC) proposed a “cost allocation” alternative that would allow increased compensation but seek to spread the costs beyond load to external generators that clear in the annual capacity auction and internal generators that neither provide black start service nor offer to do so.

“We would be willing to consider increasing compensation, but without [broader] cost allocation we remain troubled by this,” ODEC representative Steve Lieberman said at the task force’s most recent meeting last Tuesday.

Generator representatives reacted coolly to Lieberman’s request to negotiate a consensus with load-serving entities, with one calling it “worse than a zero-sum game” for generators relative to the status quo.

Black start units must be capable of starting without an outside electrical supply, maintaining frequency and voltage under varying load, and maintaining rated output for a specified time, typically 16 hours.

Proposed Changes

Black Start Annual Revenue Comparison for 20 MW CT (Source: System Restoration Strategy Task Force)
(Source: System Restoration Strategy Task Force)

The following changes are included in one or more packages to be considered by the task force:

  • Increasing the incentive factor — currently 10% of black start costs for units using base formula rates to determine O&M cost recovery — to the greater of 10% or $25,000.
  • Adding incentives based on unit availability, start times and fuel diversity.
  • Reducing the frequency of reviews of cost components from annual to once every five years.
  • Allowing compensation for NERC compliance insurance.
  • Allowing automatic load rejection (ALR) units to recover NERC Compliance costs as part of their variable operations and maintenance costs, as currently allowed for other black start units. ALR units can remain operating after disconnecting themselves from the grid during a disturbance.

Black Start Pool Increased

On Sept. 6, the Federal Energy Regulatory Commission approved tariff revisions that PJM said will increase the pool of potential black start generators by 64,000 MW (ER13-1911).

PJM initiated the changes over concern that it will lose much of its existing capacity by 2015 due to coal plant retirements. The RTO told FERC in its tariff filing that about 42% of its current black start capacity “may be impacted by environmental regulations.”

The changes included a broadened definition of units eligible to provide black start service and a provision allowing units in one zone to help restart generation in neighboring zones.

Revised Charter

In April, stakeholders expanded the task force’s charter to allow consideration of changes to black start cost allocation and compensation.

The Maryland Public Service Commission expressed concern with the expanded charter, telling FERC that the cost of black start service had doubled in recent years. The commission said there was a “need for cost controls given that black start service has rarely, if ever, been used.”

The task force’s expanded charter also included consideration of “back stop” options if response to PJM’s voluntary request for resources leaves gaps in coverage. However, PJM officials said last month they were pleased with the response to their recent request for additional black start resources.

PJM Executive VP Mike Kormos said the response indicated “a large pool of viable units, both proposed and existing.” Officials said it will take months to select their fleet of black start resources from among current resources and the new bidders.