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December 16, 2024

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Outages, Gas Demand Spike Balancing Charges in East

By Rich Heidorn Jr.
PJM Insider

Two unplanned generator outages and high natural gas demand resulted in unusually high Balancing Operating Reserve (BOR) payments in the eastern half of PJM’s footprint in January and February.

BOR payments averaged more than $1 million daily in January and $2 million per day in February, Adam Keech, PJM director of dispatch, told the Market Implementation Committee March 6. That is the higher than any period in recent memory, PJM said.

Balancing Operating Reserves are paid to generators dispatched out-of-merit by PJM that require uplift payments to cover their costs.

The impact of the spike was exacerbated because average daily deviations (in MWh) have declined by almost half in the east over the last three years. We have to spread the costs over fewer MWh,” Keech said.

Discouraging Imports

Member David Pratzon told the Operating Committee that the high BOR charges are discouraging generators outside PJM from exporting power into the RTO.

Keech said a major reason for the increase was the delay in a planned outage as a result of Hurricane Sandy and an equipment failure that shut down a second generator in February.

5-Year High

In addition, spot natural gas prices in Transco Zone 6 were extremely volatile in January and February, spiking far above prices elsewhere in PJM and exceeding $10 per mmBtu for much of the period. Prices hit a five-year high in late January, when the pipeline operator limited supplies with an operational flow order.

Transco Zone 6 supplies not only generators in northern New Jersey but also heating and electric demand in New England and New York. Most of the replacement generators dispatched by PJM were gas-fired units with minimum run times that limit their flexibility.

“If we didn’t have the outages we wouldn’t have needed all the generation …” Keech said. “Maybe the spikes are still there but they’re shorter spikes.”

Other contributing factors are congestion on the Readington-Roseland 230 kV tie line between the Jersey Central Power and Light and Public Service Electric and Gas (PSEG) zones and maintaining the “wheel” between PSEG in northern New Jersey and Consolidated Edison Co. in New York City.

Real-Time Commitments

The additional generation is usually committed in real time as a result of reliability analyses, meaning most of the  charges have been allocated to the BOR. Make-whole payments are allocated to day ahead load and exports RTO-wide if the units are committed day ahead.

Keech said the costs fall sharply with a return to normal gas prices.  The generator down for maintenance is expected back online in June. Spectra Energy’s New Jersey-New York pipeline expansion will add new supply when it becomes operational as soon as November.

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MIC to Investigate Arbitrage in Capacity Market

PJM members may consider changing the rules of the PJM capacity market to eliminate arbitrage opportunities between the Base Residual and Incremental auctions.

The Market Implementation Committee voted March 6 to endorse a problem statement, sponsored by David Pratzon on behalf of Calpine and LS Power, to consider changes.

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.

Monitor’s Report

The Market Monitor reported in December a substantial level of buy outs of BRA positions through IAs and other replacement mechanisms. The monitor said such buyouts could undermine system reliability and suppress the price of other capacity resources – a particular concern of the PJM Power Providers (P3), a group of generation owners that requested that the Monitor study the issue. Although the P3 group asked for a study of only Demand Response (DR) providers’ behavior, the Monitor broadened the study to include all capacity resources.

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

Since the 2009/2010 delivery year, the Monitor found, DR resources were far more likely than generators to replace BRA capacity. DR replacements jumped in 2009, when the formula for computing penalties was changed and reduced deficiency charges. It fell in 2012 with the elimination of the interruptible load product. (See chart.)

FERC Order

About 40% of DR replacement megawatts for the 2012/2013 Delivery Year came from the selling company’s portfolio, suggesting that it was a result of a 2012 FERC order changing measurement and verification methods. Excluding that, replacement capacity represented about 27% of cleared DR capacity, still much higher than that for generation.

In 2012, only seven generation companies, 7% of the total, replaced 50% or more of their commitments. Six DR companies, 13% of the total, replaced half or more of their commitments. In all years studied, more than half of DR replacement capacity came from incremental auctions.

No Evidence

Although the Monitor reported that two DR providers replaced 100% of their BRA capacity in each of the last three years, it said it had no evidence that any CSPs are “are purely financial entities … with no intention of providing a physical resource.”

Capacity market rules do not require sellers to identify the reasons for purchasing replacement capacity. The Monitor noted that while generation has a lead time about equal to the three-year horizon of RPM auctions, DR providers do not receive commitments from new customers until much closer to the delivery year.

Premature

John Farber, public utilities analyst for the Delaware Public Service Commission, said the problem statement “is at best premature” given other changes PJM is considering through its DR Plan Enhancements initiative to address potential abuse.

James Wilson, an economist who represents consumer advocates in several states, said PJM should not make changes that could hurt market efficiency. The Monitor’s report “identified a phenomenon not a problem,” he said.

Scope Too Narrow

Others said the scope of the inquiry was too narrow and should be broadened to include possible market design flaws. “Why are generators willing to accept much lower prices in the IA than BRA? Why is that?” asked Bruce Campbell, director of regulatory affairs for
EnergyConnect, Inc.

Pratzon said the inquiry will not focus on bidders’ intent but on the economic consequences of the buybacks. Although buy outs have not resulted in reliability deficiencies to date, Pratzon said the current capacity surplus could disappear as a result of generator retirements and load growth.

The problem statement was approved with nine objections and 36 abstentions.

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Commenters Blast PJM Plan to Shop for Market Monitor

By Rich Heidorn Jr.
PJM Insider

(March 7, 2013) — The PJM Board of Managers may be headed toward a new showdown with stakeholders over the role of its market monitor.

States, industrial consumers and cooperatives indicated in letters posted Tuesday that they may challenge the PJM Board before the Federal Energy Regulatory Commission if the board carries through with its current plan to shop for a new market monitor.

The commenters praised the performance of Monitoring Analytics, LLC, which has been operating as the market monitor under the terms of a 2007 FERC settlement (EL07-56-000). They said the board’s proposed Request for Proposals (RFP) to select a new monitor would undermine the independence and quality of the monitoring function.

“The character, number and gravity of the deficiencies in the RFP … raises a concern that the RFP process will not be executed in an open, nondiscriminatory and transparent manner,” wrote the Organization of PJM States, Inc., (OPSI). “We are concerned that the Board is reopening the debate as to whether the Market Monitor should play an active role in discussions and formal proceedings related to development of PJM market rules. We regard that role as an essential feature of market monitoring, beneficial to improvement of the PJM market design and required by FERC rules.”

Board Member Jean D. Kinsey, who is leading the search process as chair of the Competitive Markets Committee, told PJM Insider this morning that she had not read the comments. “So I don’t have any response except to say I’m happy to have them and were going to give them every consideration.”

“Generally satisfied”

The coops and industrials said they were “generally satisfied” with Monitoring Analytics’ performance and costs. Consumer advocates from Pennsylvania, Maryland and West Virginia were more effusive, saying Monitoring Analytics “has provided excellent service” and that its “capabilities represent the state of the art among RTO market monitors.”

Monitoring Analytics is headed by Joseph Bowring, a Ph.D. economist who has served as PJM’s market monitor since 1999. In April 2007, Bowring sparked a firestorm at a FERC technical conference when he accused then-PJM President Phil Harris and his allies of attempting to muzzle him by squelching his reports and cutting his budget.

More than a dozen PJM stakeholders, including several of those who filed the letters this week, responded by filing a complaint calling on FERC to take steps to ensure the monitor’s independence.

2007 Settlement

Following an investigation by an independent counsel hired by PJM, Harris resigned and FERC approved a settlement between PJM and Bowring. The settlement called for Bowring to form an independent company, which was awarded a six-year contract as PJM’s market monitor.

Under the settlement, the PJM board was given limited authority over the monitor, specifically the power to review the monitor’s budget and to decide whether to retain or replace the firm at the end of the initial term. The settlement allowed the board to renew Monitoring Analytics’ contract for subsequent terms of three years or seek a replacement through an RFP.

RFP Announcement

Monitoring Analytics’ contract, which is worth about $10 million per year, expires on July 31, 2014. Kinsey announced the board’s decision to issue an RFP rather than renew the contract in a letter Dec. 18.

“In reaching this decision, the Board was mindful of (i) the critical importance of the services in question and, (ii) its fiduciary obligations and tariff-prescribed role to ensure PJM is procuring the most effective market monitoring services at an appropriate cost,” Kinsey wrote. “The Board concluded that the most responsible course of action available to discharge its duties in this regard was to issue an RFP to explore all options, including the option of continuing its contractual relationship with the incumbent provider, Monitoring Analytics.”

Kinsey said today that she expects the board to make a filing seeking FERC approval of the RFP within two months.

Deficiencies in RFP

In the letters released Tuesday, the commenters said an RFP was unnecessary because Bowring’s company had performed well and at reasonable cost. The commenters noted that the board had not cited any deficiencies in the work of Bowring and his firm and said it risked losing the firm’s extensive knowledge of PJM markets and operations.

“The prospect that PJM and its stakeholders may lose the extensive institutional knowledge and expertise developed by the staff of the existing MMU if the Board decides not to renew its contract with Monitoring Analytics is troubling,” representatives of nine cooperatives and municipal utilities wrote.

If the board insists on issuing the RFP, they said, it should amend it to ensure the selection process is fair and transparent and that the resulting contract ensures the monitor’s independence. Among the commenters’ criticisms:

  • The proposed selection process lacks transparency: There is no provision for stakeholder involvement in the selection nor any description of how the board will evaluate candidates.
  • The RFP needs stronger conflict of interest provisions: As currently drafted, the RFP would not bar submissions from companies that have had prior business relationships with the PJM market participants or require them to disclose any such relationships with the board. “As currently worded, [the RFP] would allow a firm that has recently represented only one market segment to become the IMM,” wrote the PJM Industrial Customer Coalition.
  • The RFP could result in a lower level of services: The RFP does not specify the minimum level of services required. Applicants “might only budget for attending a single PJM stakeholder senior committee meeting a month, deeming that a sufficient level of participation,” wrote the cooperatives and public power commenters.
  • The board is threatening the independence of the monitoring function: The proposed contract requires the monitor to notify the board of any referrals of suspected market violations to FERC. Commenters said this requirement appears to conflict with the 2007 settlement, which requires that such referrals be made in a non-public manner.

A pdf of this article is available for printing: Commenters Blast PJM Plan to Shop for Market Monitor – 2013-03-07

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Facing Opposition, PJM Delays UTC Cap Pending Broader Review

By Rich Heidorn Jr.
PJM Insider

Wilmington – PJM’s proposal to limit Up to Congestion (UTC) bids stalled at the Markets and Reliability Committee Thursday, as members called for a broader review of the bidding technique.

PJM proposed the cap because high bid volumes can make it difficult for the RTO’s day ahead markets software to reach solutions. Although the proposal was supported by financial market players who are the predominant users of UTC, other members balked, calling for a broader review of the impact of UTCs, which have grown in popularity since their creation in 2000.

The committee voted to defer consideration of the cap for two months to allow an in-depth discussion of their impact on the PJM markets.

UTCs were created as a way to hedge the exposure to price differentials from the source to the sink of physical energy deliveries. Trading volumes have increased since late 2010, when PJM eliminated a requirement that UTC bids include transmission reservations. “What started as a hedge for physical transactions has evolved into a virtual product,” said Stu Bresler, PJM vice president of market operations.

The proposed cap would allow PJM to limit a market participant to 3,000 UTC transactions per day when the RTO believes higher volumes would degrade performance of its day ahead software.  PJM already has authority to limit virtual bids but it has never invoked it.

Carol Smoots, counsel to the Financial Marketers Coalition, said her members reluctantly supported the cap to allow PJM flexibility. Smoots said she would oppose UTC changes that shifted costs to her members.

Independent Market Monitor Joseph Bowring, who was among those seeking a delay on the cap, said the review of UTCs should include the subject of cost causation.

Andy Ott, PJM’s senior vice president for markets, supported a brief review to increase members’ understanding of UTCs and how they compare with spread bids. “We don’t see a sense of urgency [for the cap] we saw a couple months ago,” he said, noting that bid volumes had fallen recently.

Ott said PJM needs to have a broader discussion on cost allocation that will include UTCs and virtual transactions and might result in such transactions being allocated a fixed fee. But he said that discussion should be handled separately by the Market Implementation Committee. “We can’t have a 10-month discussion on cost-causation,” before enacting the bid cap, Ott said. “We certainly can take a month or two.”

The vote to defer action passed with no opposition and three abstentions. The resolution did not include a reference to exploring cost considerations.

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Members Reject Change to Congestion Fee Allocation

By Rich Heidorn, Jr.
PJM Insider
Wilmington – PJM stakeholders Thursday soundly defeated a proposal to relieve holders of Financial Transmission Rights (FTRs) from responsibility for balancing congestion costs.

The proposal by Steven Lieberman of Old Dominion Electric Cooperative concerned market-to-market (M2M) payments under the Midwest ISO-PJM Joint Operating Agreement. It would have eliminated the balancing congestion account as a source of M2M funds and allocated the costs to the Balancing Operating Reserve (BOR) deviations account. The Members and Reliability Committee (MRC) rejected the proposal on a sector-weighted vote of 1.57-3.43.

The proposal was something of a Hail Mary pass, coming after the MRC failed to reach consensus on two other proposed changes to the funding of balancing congestion.

Supporters of the proposal said the change was needed to eliminate disparities in the allocation of M2M payments. When PJM exceeds limits on a binding MISO flowgate, the cost is assigned to BOR if the constraint is relieved by a PJM generating unit. The cost is assigned to holders of Financial Transmission Rights (FTRs) if a MISO generator relieves the constraint. This allocation method, some say, has contributed to increasing underfunding of FTRs.

Harry Singh, vice president at J. Aron & Co., presented an analysis that showed funding available for FTRs in January was only about 50% of target allocations. In some hours, underfunding reached 100%, Singh said.  Most of the underfunding was the result of construction-related transmission outages, he said.

“People say FTRs were never intended to be a perfect hedge,” Singh said. “I get it. But if you have 100% underfunding it’s no hedge at all.”
Other stakeholders acknowledged concern over FTR underfunding but said the proposal brought to the committee shifted costs without addressing the causes.

“This proposal is to squish the balloon and have it pop out somewhere else,” said David Pratzon, who represents generators.

Walter Hall, an energy market advisor to the Maryland Public Service Commission, noted that Market Monitor Joseph Bowring has questioned whether FTR underfunding is a real problem or the result of improper measurement. “We are concerned about additional charges on end users,“ Hall said.

In December, two other proposals to reallocate the cost of balancing congestion also failed to win consensus. The first option, which would have allocated costs to real time loads and exports, won majority support from only the Other Supplier segment. The Electric Distribution (ED) segment was unanimous in opposition.

A second option, to allocate costs to all FTR MWh, including counter-flow FTRs, also failed despite support from most ED and End Use Customer members. Most Generators, Other Suppliers and Transmission Operators were opposed.

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Manual Change: Senior Subcommittee Voting (M34)

The following change was approved by the Members Committee on Feb. 28, 2013, effective March 1, 2013. For more information, contact PJM Member Relations.

Manual 34: Stakeholder Process – voting by senior subcommittees

Reason for change: Subcommittees reporting to a senior standing committee, such as the Cost Development Subcommittee, were not allowed to conduct voting. Such committees need to conduct votes in order to submit a “Main Motion” to their superior committee.

Impact: The manual was amended with a bullet at the end of Section 7.4 that allows such subcommittees to vote on proposals using the same method as a standing committee as described in section 8.3. Task forces reporting to senior standing committees already had authority to conduct votes.

 PJM Contact: David Anders

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Manual Change: Light Load Analysis (M14B)

Changes to the following PJM manual was approved by the Markets and Reliability Committee on Feb. 28, 2013, effective March 1, 2013. For more information, contact PJM Member Relations.

Manual 14B: PJM Regional Transmission Planning Process – clarification of light load analysis, SOL/IROL definitions

Reason for Change: The light load analysis section and SOL/IROL definitions required clarification. Also responds to a FERC recommendation regarding communication of modeling information between PJM and its member companies.

Impacts:

  • Adds detailed language to Section D-2.2 Light Load Reliability Analysis Procedure to clarify the application of the criteria. The light load reliability analysis tests the ability of an electrical area to export power during light load conditions. Applied to ensure that generation, including renewable generation, is not “bottled” due to reliability concerns.
  • Amends Attachment F: Determination of System Operating Limits to align definition of System Operating Limits (SOL) and Interconnected Reliability Operating Limits (IROL) with PJM planning practices. SOL includes all Bulk Electric System (BES) facilities and “Reliability and Markets” sub-BES facilities, as listed on the PJM Transmission Facilities pages; IROL definition amended to include lower voltage facilities monitored by PJM Operations. SOL and IROL are used in the transmission planning horizon.
  • Amends Attachment H: Power System Modeling to respond to a FERC recommendation that PJM establish a procedure to communicate interim updates of Regional Transmission Expansion Plan (RTEP) analysis models. PJM will communicate major updates to the RTEP analysis models outside of the annual model update window to Transmission Owners through the Transmission Expansion Advisory Committee (TEAC). PJM also will notify neighboring entities that may be impacted and make the updated affected models available upon request.

PJM Contact: Mark Sims

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Manual Change: Internal Sources and Sinks (M28)

The following PJM manual change was approved by the Markets and Reliability Committee on Feb. 28, 2013, effective March 1, 2013. For more information, contact PJM Member Relations.

Manual 28: Operating Agreement – removal of internal sources and sinks / OASIS Regional Practices document

Reason for change: To address the removal of internal sources and sinks as an option for external Day Ahead and Real Time markets transactions on OASIS. The removal of internal sources and sinks was approved by MRC April 27, 2011 at the recommendation of the Independent Market Monitor.

Impact: Eliminates potential for uncollected congestion charges for Not Willing to Pay Congestion Transactions. Moves charges from explicit to implicit billing line item.

  • Added language in Regional Practices section 1.1 and Manual 28 (Section 2: Interface Pricing) to clarify that source and sink choices on OASIS are limited to the path border point for all products.
  • Exceptions may be granted for:
    • Existing grandfathered transmission service reservations and potential future grandfathered transmission service reservations that may be created with a new transmission owner integration.
    • Reservations for dynamic schedules. Such reservations will explicitly identify the source for a generator or the sink for a load.  OASIS administrators will update the reservation upon confirming the exception.  When ARRs are requested, the customer will indicate the source and sink in the customer comments section of the reservation.

PJM Contacts: Mike Colby; Eric Hsia

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Manual Change: Nuclear Plant Coordination (M39)

The following PJM manual change was approved by the Markets and Reliability Committee on Feb. 28, 2013, effective March 1, 2013. For more information, contact PJM Member Relations.

Manual 39:  Nuclear Plant Interface Coordination – three-year review

Reason for change: NERC Reliability Standard NUC-001 R9.1.3 requires PJM to review Manual 39 every three years, including Nuclear Plant Interface Requirements.

Impact: Changes reflect review by the System Operations Subcommittee, with support from the Nuclear Generators Owners Users Group and individual nuclear plant operators. Updates roles of NERC, FERC, NRC and PJM. Minor edits throughout.

PJM Contact: David Schweizer, manager, generation

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Manual Change: Training and Certification (M40)

The following PJM manual change was approved by the Markets and Reliability Committee on Feb. 28, 2013, effective March 1, 2013. For more information, contact PJM Member Relations.

Manual 40: Training and Certification Requirements – verification of operators performing reliability functions

Reason for Change: FERC Order 742 (issued Nov. 18, 2010) ratified NERC Reliability Standard PER 005 (System Personnel Training) to ensure the qualifications of system operators performing real-time, reliability-related tasks. Most requirements are effective April 1, 2013.

Impact: The changes require that all applicable operators be verified on the reliability-related tasks assigned to them (both common terminal tasks and company-specific functions) before the operator assumes independent shift duties. Creates a Systematic Approach to Training (SAT), as developed by the Dispatcher Training Subcommittee.

  • Operators must be re-verified on any modified tasks within six months of the modifications. Verification may include direct observation in a real-time or simulated environment or completion of relevant training and certification and verbal questioning.
  • All task verifications must be entered into a new Task Tracking Module of the PJM Learning Management System (LMS).
  • The one-year grace period for completion of Initial Training Program was eliminated for TO operators. (A similar provision for certification had already been removed to comply with NERC requirements.) A new initial training program is being created (using SAT). The course can be completed either online or in person.

PJM Contacts: Glen D. Boyle, manager, system operator training; Michael J. Sitarchyk, manager, state and member training.