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December 21, 2024

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New Requirements for DR Providers OK’d

Demand response (DR) providers will face increased scrutiny and be required to provide additional documentation under changes approved by the Market Implementation Committee March 6.

The new rules require Curtailment Service Providers (CSPs) bidding into the capacity auction to have a company officer sign a certification attesting to the company’s intent to physically deliver MWs.  Bids will be made through an offer template to increase the consistency of information supplied. PJM also will increase its scrutiny of delivery zones in which CSPs’ bids exceed DR penetration thresholds.

Not Specific Enough

PJM’s transmission planners said the information currently provided by CSPs is not specific enough to allow modeling of the quantity and location of DR in reliability planning.

PJM staff also found that DR offered in the 2015/16 Base Residual Auction (BRA) exceeded 20% of the Preliminary Zonal Peak Load Forecast for some zones, raising concerns that DR providers’ bids are overly optimistic.

The MIC considered four proposals and voted to send two to the Markets and Reliability Committee for further consideration.

Zonal Screens

PJM staff’s proposal, which was endorsed by 81% of MIC voters, would “flag” a zone for increased scrutiny based on the higher of the following screens:

  • maximum zonal DR penetration (percentage of zonal peak) as determined based on the “Expanded Business as Usual” scenario in a 2009 FERC study, or the
  • maximum zonal registered DR from past delivery years (expressed as a percentage of zonal peak).

A zone will be flagged if the projected DR resources exceeds the screen. Once identified, zones will remain flagged for at least three years. CSPs bidding in a flagged zone will be required to provide additional information for their end-use customers. (For commercial and industrial customers: name and address, business segment, and electric distribution company account number if known. For residential customers: estimated number of customers, estimated nominated per customer capacity value.)

Overlapping MWs

Overlapping MWs — those offered by more than one CSP — will not clear in the auction unless supported by evidence, such as a letter from the customer.

The other three proposals considered by the MIC differed from PJM’s only on the application of the screen used to flag zones. Two proposals received less than 25% support.

The fourth, by Market Monitor Joseph Bowring, won support from 73% percent of voters and will be a secondary proposal before the MRC. Bowring’s proposal would calculate penetration levels net of megawatts bought back by CSPs or other participants, as determined based on previous auction results. “The idea is to determine megawatts which need to be documented more clearly,” Bowring explained. Megawatts that are bought back “are not going to physical.”

Bowring had offered his proposal as a “friendly” amendment to the PJM plan. PJM rejected the amendment, saying it could make it difficult for CSPs to fulfill their obligations through long term contracts.

PJM Contacts: Joe Callis, Jeff Bastian

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PJM Working on Contingency Plan for Loss of Internet

PJM will suspend its Day Ahead market if it loses Internet service under the outlines of a contingency plan approved by the Market Implementation Committee March 6.

PJM’s Tariff and Operating Agreement do not specify procedures for responding to an extraordinary event, such as an Internet failure, that disables the RTO’s eMKT application. Under the problem statement approved by the MIC, all market settlements would be done in real time in such circumstances.

The plan assumes that PJM’s internal processes are working but that eMKT and other Internet-based services are not functioning, said Stu Bresler, PJM vice president of market operations. Generator dispatch may be based on the most recent offers received by PJM before the loss of the web, Bresler said.

The problem statement will be considered next by the Markets and Reliability and Members committees. Changes to the Tariff and Operating Agreement are expected to be completed by July.

PJM Contact: Ray Fernandez

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Planning Committee Approves Manual Changes

The Planning Committee approved the following manual changes by acclimation March 7. The changes move next to the Markets and Reliability Committee. For more information, contact PJM Member Relations.

Manual 14B: PJM Region Transmission Planning Process

Reason for Change: PJM needed to revise the manual to comply with upcoming changes to NERC Reliability Standard TPL-001-4.

Impacts: Changes affect the following sections of the manual:

  • R 2.4.1 – Dynamic behavior of loads
  • R 5 – Transient voltage response
  • R 4.3.1.3 – Transient swings cause protection system operation
  • R 4.3.1.1 – High speed reclosing into a fault
  • R 4.1.2 – Tripping of transmission elements due to generator out of step event

PJM Contact: Joe Callis, Applied Solutions

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Planning Committee Votes to Bill Generators for PMUs

The Planning Committee voted March 7 to require new generators to pay for the installation of phasor measurement units (PMUs), rejecting an alternate proposal to have PJM cover the cost.

Reason for change: PMU data can enhance grid reliability for both real-time operations and planning applications (e.g., generation dynamic model calibration and validation, primary frequency response, oscillation monitoring and detection). PJM expects to receive PMU data from 82 substations by the end of 2013 but has none located at generation stations.

Impact: The Interconnection Service Agreement will be changed to require installation of PMUs at new interconnections for generators with nameplate ratings of 100MVA or larger.  Data collected by the PMU must be transmitted to PJM continuously and stored locally for 30 days.

A proposal to bill generators for the capital costs was approved 87-27 with eight abstentions. The alternate proposal — for PJM to recover the cost through the administrative fee paid by members using PJM market or reliability services — was rejected 26-86-11.

PJM will cover the cost of the communication links in the system.

The proposal moves next to the Markets and Reliability Committee.

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Manual Changes Approved by the Operating Committee

The following PJM manual changes were approved by the Operating Committee on March 5, 2013. There were approved by the Markets and Reliability Committee on March 28. For more information, contact PJM Member Relations.

Manual 3: Transmission Operations

Reason for Change: Creates procedure for generation operators seeking exemptions from following a voltage schedule.

Impacts: The changes will be included with the next update of Manual 03.

PJM Contact: David Schweizer, manager, generation department

Manual 14D:  Generator Operational Requirements

Reason for Changes: Changes were made to reflect new names of several PJM departments, address wind power generation and ensure clarity and consistency with other manuals. Several utilities, including AEP, Dominion and Pepco, abstained from the vote to endorse the changes. Additional revisions to M14D are planned in 2013 to update various other sections of the manual.

Impacts: Numerous. See details.

PJM Contact: David Schweizer, manager, generation department

Manual 37:  Reliability Coordination

Reason for Change: The manual is being updated to reflect the integration of the East Kentucky Power Cooperative, the elimination of an out of date section and the addition of a reactive transfer interface.

Impacts:

  • Updated the PJM Reliability Plan in Attachment A for the East Kentucky Power Cooperative integration effective June 1, 2013.
  • Removed Attachment C: Change Control Review Board description, which is out of date. PJM’s change management procedure can be found in PJM DOCs #596201. Attachment D was renamed Attachment C.
  • The ComEd Reactive Transfer Interface was added to a table in Section 3.1, SOL and IROL Limit Determination.

PJM Contact: Chris Pilong, manager, reliability engineering

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MIC OKs Allocation Shifts for M2M Charges with NYISO

Changes to two PJM manuals were approved by the Market Implementation Committee on March 6, 2013. The changes will be considered next by the Markets and Reliability Committee. For more information, contact PJM Member Relations.

Manual 11: Energy & Ancillary Services Market Optns./Manual 28: Operating Agreement Accounting

Reason for Change: Changes were made to comply with a FERC order regarding allocation of costs for PJM’s joint operating agreement with the New York ISO.

Impacts:

  • M28, Section 5 (identical changes in M11, Section 2.13): Day-ahead operating reserve credits for resources scheduled to provide reactive services or transfer interface control will be allocated to PJM members in proportion to their total real-time load in the applicable transmission zone(s). These credits were previously included in the allocation of day ahead operating reserves.
  • Manual 28, Section 8 and 14: Revenues paid to or received from NYISO for market-to-market (M2M) congestion relief will be incorporated in the total transmission congestion charges allocated to FTR holders. This is identical to how M2M charges are treated with the Midwest ISO.
  • Manual 28, Section 4: Footnote added to clarify that diesel generators are treated like combustion turbines based on their similar operating characteristics.

PJM Contact: Eric Hsia

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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.