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June 30, 2024

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MRC OKs Changes to System Restoration Plan

On Feb. 28, the MRC endorsed changes to PJM’s system restoration procedures and methods for selecting black start units.

Reason for changes: The MRC acted in response to anticipated changes in PJM’s roster of black start units, Environmental Protection Agency regulations and a desire to increase cross-zonal coordination. Plant retirements are expected to eliminate one-third of PJM’s black start capacity by the end of 2015. The retirements are being driven by EPA mercury and air toxics (MATS) regulations and New Jersey’s High Electric Demand Day (HEDD) rules. The cost of complying with these environmental rules has undermined the economics of coal-fired generation  at a time of cheap natural gas.

PJM, the Market Monitor and stakeholders in the System Restoration Strategy Senior Task Force agreed on this unified proposal.

Impact: There are several major changes:

  • The critical load definition is changed  to include all generation that can start within four hours. The previous definition was limited to “critical steam units with a hot start time of 8 hours or less.” This will increase the capacity targeted for use of cranking power by 70,000 MW.
  • Potential black start units will be defined as those able to respond within three hours (up from the current 90 minutes), adding 64,000 MW of black start capability. About 2,000 MW of this total could act as black start units without plant modifications.
  • Black start units in one zone will be allowed to help restart generation in neighboring zones, allowing more efficient use of existing resources.
  • PJM will issue an RFP for black start generation every five years (see Manual 14D, Section 10: Black Start Generation Procurement). Minimum length of commitment will remain two years (or longer based on capital recovery time).

The proposal did not include changes in compensation for black start units or allocation of costs across zones, which will require OATT revisions and FERC approval.  A FERC filing is expected in the second quarter of 2013. The five-year request for proposals is expected to be issued in the third quarter, with contracts effective in April 2015.

The proposal was approved with no objections and three abstentions. It includes:

  • Manual 12: Balancing Operations – Section 4.6: Wording edits.  Deleted Section 4.6.8 and 4.6.9 due to elimination of 3 BS unit per plant restriction
  • Manual 14D: Generator Operational Requirements: Addition of five-year selection process
  • Manual 27: Open Access Transmission Tariff Accounting: Updated Section 7 to reflect cost allocation changes and TO Revenue requirements for cranking paths
  • Manual 36: System Restoration:
    • Minor updates to sections 6.2, Cranking Power and 8.1.1 Ascertaining System Status.
    • Created new section 9 on Cross Zonal Coordination.
    • Major edits to Attachment A to reflect changes in critical load, Black Start requirements and the reliability backstop process.
    • Minor changes to Attachment D – Drill Guide

PJM Contact: Chantal Hendrzak

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Demand Response Changes: Baseline Measurements, Information Requirements, Duplicate Registrations

On Feb. 28, the MRC endorsed demand response proposals concerning emergency measurement, information requirements for Curtailment Service Providers (CSP) and procedures for resolving duplicate registrations. The changes were proposed by the Demand Response Subcommittee.

Emergency Measurement and Verification

Reason for change: A study by Kema Energy Consultants found that that the economic method of determining Customer Base Line (CBL) is more accurate than the emergency method. Energy settlement rules were unclear for overlaps between economic and emergency events for the same DR resource. Economic CBL rule included emergency event days in CBL day selection process.

Impact:

  • If a CSP is listed as an economic registration, economic CBL will be used to determine load reduction; otherwise the existing hour before method will be used. (OATT, OA: Emergency Load Response Program changes; Manual 11, section 10.4 changes)
  • Clarify that demand resource dispatched for both economics and emergency conditions will be settled based on emergency energy settlement rules. (OATT, OA: Emergency Load Response Program changes; Manual 11, section 10.4 changes)
  • Selection of Economic CBL days will exclude emergency event days. (OATT, OA: 10.3A.2 changes)

Increased Information Requirements for Curtailment Service Providers

Expands and clarifies information reporting requirements for Curtailment Service Providers on the source of DR capability, business segment and on-site generation attributes.

Reason for change: PJM said reporting requirements were not adequately documented and information was sometimes incomplete.

Impact:

  • Clarify requirements in Manual 11, section 10.2.2
  • Eliminate use of “Other” category to ensure reasonable information is provided
  • Expand on-site generation attributes to include: Generator vintage, retrofit nameplate rating, permit status and permit type.

Most CSPs have already provided updated data.

Resolving Duplicate Registrations

Changes the resolution process used when different Curtailment Service Providers register the same end use customer.

Reason for change: Two CSPs sometimes attempt to register the same end-use customer, potentially creating double payment for the same service.

Impact: When two CSPs claim an end-use customer, both will be given five business days to contact the customer to affirm the customer’s selection and notify PJM that they have a valid contract. If only one CSP affirms they have a valid contract that registration will proceed. The registration will be terminated if neither CSP affirms they have a valid contract or both CSPs continue to claim the customer. Changes to Manual 11, section 10.2.

PJM Contact: Pete Langbein

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Capacity Market: Three-year Price Guarantee for New Capacity

The Members Committee and MRC approved changes on Feb. 28 to provide new capacity resources with a mechanism to avoid clearing the capacity auction for one year if they require multi-year price assurance to be a viable project.

Reason for change: New capacity resources currently are guaranteed only one year’s price guarantee – known as New Entry Price Adjustment (NEPA).

Impact: The Members Committee and MRC approved changing two sentences in the Tariff.

New capacity resources seeking the three-year price guarantee must declare their intentions when bidding in the first year and specify whether their offers are contingent upon qualifying for the price adjustment.  Such sell offers will not clear the auction if they don’t qualify for NEPA treatment.

Part of a bigger package of changes being developed by the Capacity Senior Task Force, this change will take effect in time for the May capacity auction. The task force will consider whether additional changes are needed after reviewing results of the May auction.

PJM Contact: Sarah Burlew

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Reliability: Lost Opportunity Costs for Generators

Reason for change: The Market Implementation Committee (MIC) created the Reliability Limited Generator Compensation Task Force (RLGCTF) on Feb. 17, 2012 to determine compensation for generating resources operating outside of their defined reliability limits. The task force focused on what level of Lost Opportunity Cost (LOC) should be compensated.

Impact: The MIC determined that generators will be paid LOC at the lesser of the Economic Maximum or Maximum Facility Output (MFO) of the generator. Schedule 1 of the Operating Agreement is amended, including clarifications of definitions:

  • “Economic Minimum” shall mean the lowest incremental MW output level, submitted to PJM market systems by a Market Participant, that a unit can achieve while following economic dispatch.
  • “Economic Maximum” shall mean the highest incremental MW output level, submitted to PJM market systems by a Market Participant, that a unit can achieve while following economic dispatch.

PJM Contact: Heather Reiter

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Tariff Cleanup

On Feb. 28, the Markets and Reliability Committee endorsed changes to the Open Access Transmission Tariff regarding interconnection procedures. The changes addressed misspellings, typos, incorrect references, and omissions of previously approved changes and clarifications. Also addressed was a discrepancy in the existing interconnection service agreement (ISA) language that references a “Merchant Network Upgrade,” which can only be performed under an Upgrade Construction Service Agreement.

PJM Contacts: David Egan, Jen Tribulski

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East Kentucky Coop to Join PJM

By Rich Heidorn Jr.
PJM Insider

PJM’s footprint is about to grow again with the addition of the 16-member East Kentucky Power Cooperative (EKPC). The Members Committee was briefed Feb. 28 on PJM’s takeover of reliability coordination and transmission operations for the generation and transmission cooperative effective June 1.

East Kentucky, which joined PJM as an Other Supplier in 2005, estimates it will save almost $132 million over the next decade by taking advantage of PJM’s economies of scale and generation diversity.

“Uneventful” Integration Expected

A winter-peaking system (2,500 MW), East Kentucky will increase PJM’s generation capacity by 2.5% and transmission network by 4%. Frank Koza, PJM’s executive director of operations support, told members on a conference call yesterday he expects the integration to be
“uneventful.”

The coop’s move to PJM was approved by the Kentucky Public Service Commission in December and still requires OKs from the Rural Utilities Service (RUS) and Federal Energy Regulatory Commission, according to coop spokesman Nick Comer.

East Kentucky has filed requests with FERC to participate in the PJM Reliability Pricing Model Base Residual Auction for 2016-17 (ER13-414-000) and to submit an out-of-time Fixed Resource Requirement Plan (ER13-478-000).

The Members Committee will be asked Thursday to ratify the coop’s entry with changes to the PJM OATT, Operating Agreement, Reliability Assurance Agreement and Transmission Owners Agreement. PJM expects to file the revisions with FERC in March.

Benefits to Coop

East Kentucky said its move was prompted by increasing transmission constraints with potential counterparties and federal environmental regulations, which made it expensive to continue operating as an independent control area and balancing authority. The coop has interconnections with TVA, Duke Energy, American Electric Power and Louisville Gas and Electric Co./Kentucky Utilities Co. (LG&E/KU).

It gets more than 80% of its power from coal-fired generation and has invested nearly $1.75 billion over the past decade in modern coal generators and environmental retrofits of older units.

A study by Charles River Associates estimated East Kentucky will gain almost $132 million (net present value) in the first 10 years after joining PJM.

The biggest savings will come from reduced reserve requirements. East Kentucky maintains a 12% reserve margin (360 MW). By joining the summer-peaking PJM, it will be able to reduce its reserve to 2.8% (70 MW), allowing it to sell the difference in the capacity market.

The integration also will result in more economical generation dispatch, as the coop replaces its higher cost generation with cheaper PJM power.

Potential Retirements

East Kentucky has 1,882 MW of coal-fired capacity at the H.L. Spurlock Station located near Maysville, John Sherman Cooper Station near Somerset and William C. Dale Station near Winchester.

Comer said all four units at Spurlock (two built in the last eight years, two with scrubbers) are well positioned to meet Environmental Protection Agency regulations while 300 MW of capacity — 1950s and 1960s vintage units at Cooper and Dale — may be vulnerable to retirement when EPA’s Mercury and Air Toxics Standards take effect in 2015.

The coop is currently reviewing responses to a request for proposal issued last year to replace the 300 MW.

Impact on KU

Kentucky regulators approved the move after the coop and PJM agreed to a stipulation intended to hold KU harmless from cost increases.

KU serves more than 100 MW of its native load using East Kentucky transmission at cost-based rates. KU feared that the coop’s full membership in PJM would increase its transmission rates.

Under the stipulation, PJM agreed to create a pseudo-tie with KU/LG&E and charge the utility transmission rates applicable to the East Kentucky pricing zone; PJM agreed not to bill KU for any other charges assessed on load in the PJM markets.

Kentucky regulators also expressed concern that the coop’s move to PJM created a risk it will face higher prices for energy due to transmission congestion. The commission required the coop to file an annual report detailing its strategies for hedging congestion risk and for competing in the markets for capacity and energy.

A pdf of this article is available for printing: PJM Insider Members Committee Preview – E KY Power Coop joins PJM – 2013-02-26

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FERC Demand Response Standards Leave Industrials, Bowring Unhappy

By Rich Heidorn Jr.
PJM Insider

WASHINGTON, D.C. (Feb. 22, 2013) – The Federal Energy Regulatory Commission yesterday enacted new standards for measuring demand response and energy efficiency in PJM and other organized markets, rejecting objections from industrial customers who said the rules will hurt their efforts to participate.

PJM Independent Market Monitor Joseph Bowring also had raised concerns about the standards, saying they failed to distinguish between energy and capacity markets and could undermine PJM’s efforts to eliminate “double counting.”

The new rules add definitions and business practices to existing standards while leaving regions flexibility to tailor the specifications. The commission said the new standards, developed by stakeholders through the North American Energy Standards Board (NAESB), will reduce transaction costs and increase incentives for demand response and energy efficiency resources to participate in PJM and other RTO and ISO markets.

Incremental Improvement

The commission order (Order 676-G, Docket # RM05-5-20) acknowledged the new standards represented only an “incremental” improvement over the initial NAESB standards approved by the commission in 2010, and encouraged stakeholders to continue refining the measures.

The measures, built in part on those already in use in PJM and ISO New England, were generally supported by generators and transmission owners, while demand response aggregators told the commission they didn’t go far enough in standardizing rules across regions. Industrial customers complained that that the NAESB process was stacked in favor of generators — which are struggling to maintain revenues in the face of a sluggish economy and low natural gas prices — and against industrials, whose potential to reduce peak demand could pinch revenues even further.

Industrial Customers Object

The PJM Industrial Customer Coalition and the Industrial Energy Consumers of America (IECA) said the rules were appropriate for commercial customers, whose energy use is highly correlated with weather, but not for steel mills, plastics manufacturers and other large energy users whose energy use is driven by production schedules. Given the right incentives, industrials said, such users could delay production during a heat wave, reducing peak demand and prices.

But IECA acknowledged that it had not taken part in the multi-year NAESB drafting process and said that only “a handful” of individual industrials were involved. As a result, NAESB never considered the industrials’ call for adoption of industry-developed coincidence factors in evaluating energy efficiency.

Industrials complained current RTO requirements that coincidence factors be validated for each project created a costly barrier to their participation. IECA said that PJM’s “overly prescriptive” process for verifying energy efficiency projects result in costs that exceed the potential benefits to manufacturers.

The commission rejected the industrials’ request that it order RTOs to consider the industry-developed factors but said NAESB should continue to work on baselines that are more accurate for highly-variable load and consider whether the standards should distinguish between capacity and energy products — a concern raised by Bowring.

Concerns from PJM’s Market Monitor

Bowring told the commission that the NAESB standards were “more likely to create confusion than resolve it” because they do not differentiate metrics appropriate to energy demand from those for capacity.

Bowring said the standards threatened to undermine years of work by PJM stakeholders to eliminate the risk of gaming and “double counting” of demand response efforts.

In Docket No. ER11-3322-000, the commission approved using Peak Load Contribution as the fundamental measurement for evaluating reductions in capacity. Bowring said the NAESB standards “appear to conflict with and undermine the clear recognition of this fundamental metric.”

In its own filing, PJM Interconnection disagreed with Bowring’s concern, saying its existing methodologies “are compatible with the NAESB Standards.” The commission ruled that in the event of any conflicts between NAESB standards and RTO/ISO rules, the regions’ governing documents will take precedence.

The order will take effect 60 days after publication in the Federal Register. The commission said regions must make a tariff filing incorporating the standards by Dec. 31, 2013.

A pdf of this article is available for printing: FERC ruling on demand response verification – 2013-02-22

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FERC Rebuff of Duke Could Mean Closer Ties with PJM

By Rich Heidorn Jr.

WASHINGTON, DC (Feb. 21, 2013) — Duke Energy may be the biggest utility in the U.S., but the Federal Energy Regulatory Commission says it still needs a date to the Order 1000 ball. Could it be PJM?

FERC Chairman Jon Wellinghoff floated that suggestion today after the commission rejected Duke’s attempt to comply with Order 1000 through a transmission planning region covering only Duke, newly acquired Progress Energy and 21 miles of transmission connecting them to Alcoa Power Generating’s Yadkin hydroelectric plant (ER13-83-000).

In 2005, Duke and Progress formed the North Carolina Transmission Planning Collaborative (NCTPC) to comply with FERC Order 890, the predecessor to Order 1000. The July 2012 merger with Progress made Duke the nation’s largest electric utility holding company. Duke argued that its new territory — larger than that of some Regional Transmission Organizations and including parts of North Carolina, South Carolina, Indiana, Ohio, Kentucky and Florida — made it sufficiently large to meet Order 1000’s requirements as a transmission planning region.

But the commission said the size of the region, and the fact that Duke and Progress are treated separately by North Carolina regulators, was irrelevant. “The notion that a compliant transmission planning region can be comprised of two `transmission providers’ that report to the same senior management, board of directors, and shareholders runs counter to Order No. 1000’s requirement that transmission planning occur on a regional rather than on an individual utility level, and would undermine the very reforms the Commission intended to achieve in Order No. 1000,” the order said.

The order, which requires Duke to file a new compliance plan within 90 days, did not suggest where the company might look for regional planning partners who would meet FERC requirements.  In a press conference after the ruling, however, Wellinghoff suggested Duke could look to PJM, along with Southern Company and utilities in South Carolina. “I think there’s plenty of opportunities for them,” Wellinghoff said.

Duke spokesman Dave Scanzoni declined to comment on how the company will respond to FERC’s rebuff.

PJM spokeswoman Paula DuPont-Kidd also declined to comment on the impact of the ruling but added: “Generally, we would welcome the opportunity to enhance our operating and planning efficiencies with any of our neighbors in the Eastern Interconnection.” Separately, PJM is working on development of an interregional planning process with the Midwest ISO and New York ISO with a compliance filing due April 11.

Although six Duke affiliates are members of PJM, and the company trades with the PJM region, the company seems more likely to look to its southern neighbors, which like North Carolina, do not have retail choice or organized wholesale markets.  In its compliance filing, Duke said it could join only the Southeastern Regional Transmission Planning Process (SERTP) or the South Carolina Regional Transmission Planning Process (SCRTP).

Still, Duke and PJM have increased their collaboration over the last several years. PJM and Duke Energy Carolinas have operated under a reliability coordination agreement and a locational interface pricing agreement since 2007. On January 1, 2012, the Duke Energy Ohio/Kentucky region joined the PJM footprint. Independent Market Monitor Joseph Bowring said last fall that PJM should terminate and perhaps renegotiate the 2005 Joint Operating Agreement it signed with Progress Energy Carolinas because the way the Progress generation fleet is dispatched has changed as a result of the Duke-Progress merger.

The Duke order, and a second ruling exempting Maine Public Service Company (ER13-85-000) from the regional planning requirements, were the commission’s first decisions on compliance filings resulting from Order 1000, which seeks to spur new transmission and open competition to independent transmission developers. The commission waived the planning requirements for the small Maine utility because it is connected to the U.S. electric grid only indirectly through Canada.