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August 1, 2024

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Resource Adequacy to Get More Focus at MISO as Coal Plants Fade

By Chris O’Malley

misoCARMEL, Ind. — MISO on Thursday launched the first in a series of stakeholder workshops planned over the next 18 months dedicated to improving resource adequacy as the RTO deals with the retirement of coal-fired generation and the growth of natural gas and renewables.

There’s some urgency: MISO forecasts that its Planning Reserve Margin Requirement, which is peak demand plus the planning reserve margin, could drop below its target as early as 2016.

The RTO last month released a draft white paper, “Issues Statement on Facilitating Resource Adequacy in the MISO Region,” to serve as a framework for reversing its declining margins.

“Basically, we’re going to have smaller reserve margins and we’re going to have different resources in play,” Joseph Gardner, MISO’s vice president of forward markets and operations services, told stakeholders. “We’re trying to have a common understanding [of] what the issues are.”

The white paper notes that MISO’s current processes do not:

  • Ensure transparency across all seasons and all time horizons;
  • Address issues related to resource performance, such as fuel assurance and winterization;
  • Treat a resource consistently as it moves from interconnection to retirement; or
  • Provide applicable incentives for all load-serving entities to ensure adequate resources.

Technically, of course, MISO is not the guarantor of resource adequacy. LSEs and states that regulate them are responsible for assuring adequate resources in their jurisdictions.

MISO is building its efforts to support LSEs and the states around four “strategic goals.”

Better Picture Needed

One goal is “Regional Assessment and Transparency,” based on the survey of LSEs that MISO conducted last year with the Organization of MISO States (OMS). Some stakeholders said OMS needs to improve the survey.

Jeff Beattie, a senior engineer at Consumers Energy, said there’s skepticism about the reliability of the data collected, noting that the OMS survey is not subject to peer review. “How can we get further buy-in?” he asked.

“The nature of the OMS survey has been such that confidentiality is strongly protected and only zonal-level shortfalls have been provided to stakeholders. That greatly limits the value of the survey results,” Consumers said in pre-filed comments ahead of Thursday’s workshop.

Consumers suggests that MISO follow the example of NYISO’s “Gold Book,” which provides details for new generators and proposed and actual unit suspensions and retirements.

“If MISO moved in this direction on transparency, it would be much easier for all parties to accurately evaluate resource adequacy in the MISO footprint,” Consumers said.

MISO traditionally has forecast demand based on individual forecasts performed by LSEs, transmission operators and others. However, it recently hired a consulting firm to conduct independent load forecasts through 2017.

“As reserve margins decline, it is now more critical than ever to have confidence that demand forecasting is consistent and accurate,” the paper says.

Looking Outward

Another of the four goals is “Industry Influence, Monitoring and Coordination,” which deals with issues partly or entirely outside of MISO’s direct control, such as fuel reliability, electric and natural gas coordination and support from neighboring systems.

For example, MISO noted that it has been surveying asset owners as to their confidence about fuel deliveries and inventories. The survey is voluntary, however.

As for support from neighboring systems, Entergy has already weighed in by saying that assuming neighboring systems will provide support toward MISO resource adequacy isn’t sufficient.

“If this is an assumption MISO is relying on for [resource adequacy], a study with neighboring systems to determine the appropriate level of support to assume and contractual agreements may be needed to be put in place,” Sarah McCurdy, an analyst with Entergy, said in pre-filed comments.

Other Topics for Debate

Another goal, titled “Evolving the Resource Adequacy Requirements,” deals with MISO’s resource adequacy construct and issues such as retail choice and seasonal and locational considerations.

Traditionally, the focus has been on meeting the summer peak. But one of the questions raised by MISO staff is whether non-summer risk will increase as capacity is squeezed in the years ahead.

“How much of our footprint is winter-peaking?” wondered Amy Jo Miller, commercial market affairs executive at Ameren.

For example, MISO’s paper contemplates that as reserve margins decline, it may have to dispatch seldom-used capacity. This could include increased use of load-modifying resources — such as factories that can reduce energy use by adjusting production schedules and commercial buildings that can reduce air conditioning.

MISO said it has not called on those resources since 2006.

“Because declared emergency conditions will likely become more prevalent as reserve margins decline, MISO may call on LMRs more extensively going forward,” MISO says.

The final goal is “Process Alignment,” which involves identifying and eliminating barriers or inconsistencies within MISO procedures.

One such issue raised by stakeholders is that the current annual construct doesn’t address mid-year retirements and suspensions of generating plants.

Next Meeting

The next workshop meeting is tentatively scheduled for May 15.

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Low-Income Groups Seek Clarification on Utility Ownership in Reforming the Energy Vision

By William Opalka

A coalition of organizations representing low- and moderate-income households in New York has asked for a clarification and rehearing of last month’s Reforming the Energy Vision order to allow greater participation in the program by less affluent residents (14-M-0101).

The New York Public Service Commission set up a framework for the REV process that limits utility ownership of distributed energy resources with a limited number of exceptions, one of the cornerstones of the state’s path-breaking initiatives in the smart grid, distributed energy resources (DER) and energy storage. (See New York PSC Bars Utility Ownership of Distributed Energy Resources).

“While seeking to pay attention to low- and moderate-income residents, the commission continues to view low- and moderate-income households as merely consumers of energy while providing the opportunity for more affluent residents to be more active participants and owners,” according to a Tuesday filing by the Energy Democracy Working Group, a coalition of six organizations from throughout the state.

The REV generally excludes utility ownership of DER assets, but it allows exceptions for the development of DER intended to benefit the less affluent. The REV order noted that consumer advocates expressed concerns during the proceeding that those residents, including renters, would be excluded from REV benefits.

Energy Democracy agreed with the PSC’s assessment that utility investment may be needed but said the order is unclear regarding what types of investments that may mean, and how partnerships with community groups would be organized.

“We seek clarification as to whether ‘investment’ … means ‘ownership’ or whether it means providing access to financing or other support to allow low-income and moderate-income people to own distributed energy resources themselves,” it wrote.

The group also says that the assumption that DER markets will not develop without utility ownership is “premature” and that the “REV proceeding is meant to change the status quo and reduce barriers” for DER.

While the order does not define low or moderate income, Energy Democracy said it assumes standard measures that define “area median income” are used. “We hope the commission does not mean to write off the approximately 50% of New Yorkers who are low- or moderate-income as unreachable by the new REV markets,” the petition states.

“Low- and moderate-income New Yorkers represent a substantial portion of the state’s population and a large portion of the electricity market. This raises the possibility that … the exception … will represent a significant portion of the market,” it adds.

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NYISO Asks if ICAP Order Includes the Lower Hudson Valley

NYISO asked the Federal Energy Regulatory Commission this week if a recent order meant to mitigate market power in the installed capacity market in New York City would apply to its new capacity zone in the Lower Hudson Valley (EL07-39-006). NYISO wants an expedited ruling by Monday because market participants are preparing for the May monthly auction. Enrollment closes on Wednesday.

The order accepted NYISO’s compliance filing with the exception of its proposal to grant a blanket exemption from offer floor calculations for all payments and other benefits to special case resources (SCR) under state programs. An SCR is a demand-side resource that participates as a supplier in NYISO’s capacity market. (See FERC Upholds Most of New York City Market Power Order.)

NYISO said it is clear the order requires revisions to state programs for SCRs in New York City and will be included in determinations under buyer-side capacity market power mitigation rules. “It is not clear whether that revision is also to apply to new SCRs in the Load Zones G, H and I (i.e., those within the G-J Locality) or in any mitigated capacity zones that may be created in the future,” NYISO wrote.

The New York Transmission Owners on Thursday opposed the NYISO petition, saying it was counter to the plain language meaning contained in the FERC order. “The clarification request is, in substance, an untimely motion asking the commission to expand the scope of a March 19, 2015, ruling in this proceeding far beyond that expressly established by the commission and addressed by the parties during the more than seven years that this proceeding has been pending,” it wrote.

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FERC Cuts ITC Transco Adder in Half

By Rich Heidorn Jr.

itcA split Federal Energy Regulatory Commission on Tuesday granted ITC Midwest’s request for an incentive adder but cut the bonus in half, prompting a dissent from Commissioners Philip Moeller and Tony Clark.

ITC had requested an adder of 100 basis points, consistent with what the commission has granted “independent, stand-alone” transmission companies (transcos) since such incentives were authorized by Congress in 2005 to increase transmission spending.

In response to that directive, the commission issued Order 679, concluding that the transco business model responds more rapidly and precisely to market signals and was thus deserving of an incentive.

“We continue to find that the transco business model provides the benefits that the commission recognized in Order No. 679. However, we note that the commission did not specify the size of the transco adder in Order No. 679,” the commission wrote (ER15-945).

Under current conditions, the commission said, 100 basis points is excessive. “We conclude that 50 basis points is an appropriate size for the transco adder, taking into account the interests of consumers and applicants, as well as current market conditions. Granting this 50-basis-point adder strikes the right balance by appropriately encouraging independent transmission consistent with Order No. 679, while acknowledging protesters’ concerns regarding the rate impacts of such adders.”

The commission said the adder would be applied to a base return on equity within the “zone of reasonableness” determined by an updated discounted cash flow analysis being conducted in docket EL14-12. (See ROE Talks Between MISO Industrials and TOs Collapse.) ITC said it would defer collection of the adder, which became effective April 1, pending the outcome of that proceeding.

Dissent

Moeller and Clark blasted the majority’s ruling, the first time that the commission has reduced a requested transco adder.

“The majority has not provided any guidance as to what showing is necessary to support a 100-basis-point adder moving forward,” they wrote.

“This order also sends the wrong message at a time when new regulations, such as the [Environmental Protection Agency’s] Clean Power Plan, will likely drive the need for more transmission investment.” (See related story, MISO, SPP Stakeholders Developing Trading Plan to Comply with EPA Carbon Rule.)

“We also find it puzzling that the commission would reduce transmission incentives for a transco business model when it is just beginning to see the effects of competitive solicitation under Order No. 1000,” the commissioners continued. “These mixed messages from the commission on the value of innovative business models and transmission investment decrease regulatory certainty at a time when it is most needed.”

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FERC: PJM Demand Response Stop-gap Measure ‘Premature’

By Michael Brooks

The Federal Energy Regulatory Commission on Tuesday rejected PJM’s contingency plan to include demand response in its capacity auctions in the event an appellate court ruling limiting FERC’s jurisdiction over DR is allowed to stand (ER15-852).

FERC called the filing premature, saying it would disrupt the commission’s options in dealing with the aftermath of the Electric Power Supply Association (EPSA) v. Federal Energy Regulatory Commission case.

FERC has asked the Supreme Court to reconsider the 2-1 ruling, which found that Order 745 violated state ratemaking authority by forcing RTOs to pay market-clearing prices to DR resources. While the ruling only directly addressed FERC’s jurisdiction over DR in energy markets, PJM wanted to be prepared in case it were applied to FERC-regulated capacity markets. (See PJM to File Post-EPSA Demand Response Contingency Plan with FERC.)

US-Demand-Response-Forecast,-With-and-Without-FERC-Order-745---2014---2023-(Source-GTM-Research)-for-webPJM’s proposal would have altered its demand curve to reflect actual load by accepting DR bids from any “wholesale entity” in May’s Base Residual Auction, reducing the amount of capacity procured and the price at which it clears.

As a result of FERC’s rejection, PJM said in a statement Wednesday, the BRA for delivery year 2018/19 “will move forward under the existing rules for the participation of demand response.” However, the auction, scheduled for May 11-15, may be delayed as a result of a separate FERC ruling Tuesday that required the RTO to provide additional information on its Capacity Performance proposal. (See related story, FERC: PJM Capacity Performance Filing ‘Deficient’.)

FERC ruled that PJM’s DR idea was good but before its time. “While we recognize that PJM’s goal is to reduce uncertainty surrounding demand response participation in its upcoming BRA, in the present circumstances, it is unavoidable that some uncertainty is inherent in the current stance of the EPSA case,” FERC said.

“Moreover, we are concerned that PJM’s proposal introduces uncertainties that may exceed those it seeks to avoid, particularly with respect to potential unanticipated spillover effects on state programs and private sector arrangements.”

demand response
FERC Commissioner Tony Clark (© RTO Insider)

Commissioner Tony Clark dissented, saying that the commission was sidestepping the merits of PJM’s filing.

“Today’s order unnecessarily delays action and perpetuates system inefficiencies created by the overcompensation of demand response products in wholesale electricity markets,” Clark said. FERC should “seize the opportunity to provide guidance on a functional demand-side product to the betterment of the PJM markets.”

Clark, however, said he thought that PJM’s proposal may not have gone far enough and ignored the role its existing Price Responsive Demand product could have played. “Enabling functioning price-responsive demand is the right answer to the conundrum in which we now find ourselves, and it is where the commission should expend the bulk of its efforts,” he said.

PJM had requested the proposal go in effect April 1, in time for the BRA. The RTO argued it was being proactive, and that the changes would only be a temporary measure while FERC developed a more comprehensive solution.

PJM noted that if the Supreme Court granted its writ of certiorari, it would have withdrawn the changes from the Tariff and run the BRA under the previous rules. The court is expected to decide this month whether to take the case.

In its protest to the filing, the Advanced Energy Management Alliance argued that LSEs, curtailment service providers and DR owners would not be able to change their business strategies in time for the BRA. The Illinois Commerce Commission and the Maryland Public Service Commission also argued that in some states, laws and regulations would need to be amended in order to enact the changes.

While not taking a strong position on the merits of PJM’s proposal in its protest, Public Service Enterprise Group argued that if FERC accepted the plan, it should require PJM to keep the changes intact regardless of whether the Supreme Court took the EPSA case, as withdrawing them would create uncertainty in the results of the BRA.

PJM proposed creating two new capacity products:  Whole Load Reductions and Whole Energy Efficiency Load. PJM General Counsel Vince Duane said in December, when the proposal was first presented to stakeholders, that the term “wholesale entity” was left “deliberately vague” to allow load-serving entities and electric distribution companies to submit DR bids.

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FERC: PJM Capacity Performance Filing ‘Deficient’

By Suzanne Herel

PJM’s controversial Capacity Performance plan was turned back Tuesday by the Federal Energy Regulatory Commission, which deemed the filing deficient and gave the RTO 30 days to provide additional information (ER15-623).

FERC’s four-page order questioned 10 areas of the proposal, which was conceived to increase reliability expectations of capacity resources with a “no excuses” policy.

PJM said Wednesday it will respond to FERC’s questions “promptly and seek expedited review” to allow the new rules to be in effect for the Base Residual Auction scheduled for May 11-15.

“We recognize that process may require a delay to conduct an orderly auction process,” Dave Anders, director of stakeholder affairs, said in an email to members. “While PJM clearly would have welcomed approval, we appreciate the FERC’s thoughtful consideration of our proposal and the commission’s demonstrated commitment to reliability and enhanced generator performance.”

Anders said PJM has never delayed a BRA before.

The commission compared aspects of the PJM proposal with ISO-NE’s “pay-for-performance” design, which it approved last year and on which PJM’s proposal was in large part modeled.

PJM’s proposal was expected to result in both larger capacity payments for over-performing participants and higher penalties for non-performers.

FERC asked PJM to explain its derivation of an appropriate competitive clearing price when no new capacity is required in a locational deliverability area (LDA), and to provide more detail on a default offer cap and how it would apply in several situations.

It also requested any analyses the RTO had conducted on expected performance charges and bonus payments under the proposal. The commission asked if it made sense to phase in the penalties — as ISO-NE has — and for ideas of how to provide incentives for resource performance. In addition, it asked PJM how it plans to evaluate the performance of external resources not pseudo-tied to the RTO.

Moeller: Delay Creates Uncertainty

The commission’s order drew a rebuke from Commissioner Philip Moeller. The RTO’s filing “already contains sufficient information to permit the commission to issue an order on the merits of PJM’s proposal in advance of the May 2015 Base Residual Auction,” he said in a statement.

“Markets provide the best prices for both buyers and sellers when participants know the market rules. Regardless of whether the commission ultimately decides to accept or reject PJM’s Capacity Performance proposal, by failing to act, the commission is creating market uncertainty on issues that need clarity now,” he added.

Dynegy and NRG Energy shares fell sharply April 1 on the news of the ruling, with Dynegy down 2.1% and NRG falling 5.6%. Dynegy recaptured its losses April 2 while NRG only partially rebounded.

More than 60 entities filed comments and protests in response to the plan.

States and load-serving entities (LSEs) were skeptical about the need for a major overhaul, while generators split over elements they liked and others they said must be changed. (See States, LSEs Skeptical, Utilities Split Over Capacity Performance.) Many generators complained the penalties were too harsh; others, including Exelon, said the penalties were too lax.

LSEs feared the product redesign was overkill and would result in unnecessary price increases.

As proposed, the changes would have begun to take effect for the 2016/17 delivery year and be fully implemented in 2020/21.

The details are outlined in nearly 1,300 pages filed in two dockets:

  • EL15-29 contains proposed changes to PJM’s Operating Agreement and Tariff “to correct present deficiencies in those agreements on matters of resource performance and excuses for resource performance.”
  • ER15-623 proposes changes to the Reliability Pricing Model in the Tariff and Reliability Assurance Agreement.
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CEO Crane to DC PSC: Exelon Committed to Jobs, Ratepayers

By Suzanne Herel

exelon
Crane at the DC PSC on Monday.

Exelon would retain Pepco Holdings Inc.’s D.C. headquarters, not forcibly reduce the workforce for at least two years and match any commitments it has made to New Jersey, Delaware and Maryland if it is permitted to buy Pepco in a proposed $6.8 billion deal, CEO Christopher Crane testified Monday before the District’s Public Service Commission.

Those promises include customer bill credits, grid reliability improvements, renewable energy projects, energy efficiency programs, help for low-income consumers and the creation of trails.

D.C. and Maryland are the last holdouts to the transaction, which Crane agreed Monday is an acquisition rather than a merger, given the size of the Chicago-based energy giant. The evidentiary hearings, which are being webcast, continue through April 8 in D.C. and are scheduled for April 15-17 in Maryland.

The direction of questioning followed opening statements delivered by the D.C. Office of People’s Counsel and the D.C. government, who strongly oppose the deal. Crane was grilled on Exelon’s commitment to renewable and distributed energy, protecting ratepayers’ interests over the profitability of its nuclear generators, retaining a true local presence and how Exelon would be held accountable to its promises.

“We hope to, within the District and other districts, to enter settlement negotiations to satisfy stakeholders in the process if we could,” Crane said.

Regarding jobs, Crane said, “There will be no reductions of the utility staff for two years — there’s actually a commitment to hire.”

In part, that’s because about 400 employees are eligible for retirement, he said, and Exelon wants to bring some of the work currently being contracted in-house. While Exelon can’t promise to preserve staff “in perpetuity,” Crane said there was nothing viewable in today’s landscape that would indicate the need for future layoffs.

Crane said Exelon cannot alter its proposal to D.C. without resetting the clock for the decision timeline, but he welcomed additional concessions either through a negotiated settlement or a unilateral decision by the commission.

When asked by People’s Counsel attorney Jason Gray what would be the “tipping point” that would make the acquisition unprofitable, Crane said that to his knowledge, Exelon had not conducted such an analysis.

“You don’t have any concern that applying any of these provisions would put you over the tipping point?” Gray asked.

“I don’t believe any of these do,” Crane responded.

In his opening statement, John Coyle, an attorney representing the D.C. government, noted that the transaction involved a premium of more than 24% over the current market value of Pepco stock, when in essence, he said, “Exelon is proposing $6.8 million for a $4.3 million balance sheet.”

“The mere size of the premium begs the question of why it is being offered,” Coyle said, suggesting that commissioners engage in what he called an old D.C. tradition and “follow the money.” (See Consumer Advocate Seeks Delay in Exelon-Pepco Proceedings.)

Md. County Reps Want More from Deal

exelon
Leggett

Meanwhile, Exelon continues to encounter opposition in Maryland, where the Montgomery County Council has split from County Executive Ike Leggett, arguing that the settlement he reached with Exelon doesn’t go far enough to protect ratepayers and encourage renewable energy.

The nine-member Council on Tuesday unanimously passed a resolution asserting that Leggett’s settlement “does not adequately address the overarching issues that have led the state, the Office of People’s Counsel, the environmental community and other public interest organizations to maintain that the merger is contrary to the public interest.”

Montgomery and Prince George’s counties agreed to support the takeover in return for additional commitments. (See Exelon, Pepco Ink Deal with Md. Counties, but Critics Stand Firm.)

The resolution, spearheaded by energy attorney Roger Berliner, cites fears that Exelon will seek to raise rates to offset losses at its nuclear plants and will favor that generation at the expense of renewable and distributed energy resources.

“If the serious risks the proposed merger poses to the public interest can be mitigated, it can only be mitigated by very strong, verifiable and financially accountable commitments by Exelon to holding down costs and to clean, renewable, distributed energy, including energy efficiency, values at the heart of Maryland’s energy policy,” the resolution states.

Patrick Lacefield, a spokesman for Leggett, told Bethesda Now that the executive took the council’s position into account before signing the settlement with Exelon.

“The alternative to this settlement is not necessarily something better. The alternative could well be no deal at all. … We made this decision in the public interest to change the status quo. It is an executive decision.”

The Maryland Public Service Commission is set to finish reviewing the takeover on May 8.

The acquisition has been approved by the New Jersey Board of Public Utilities, the Federal Energy Regulatory Commission, the Virginia State Corporation Commission and the staff of the Delaware Public Service Commission.

Exelon hopes to close the deal in the second or third quarter of this year.

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Mercury and Air Toxics Standards: 25 Years in the Making

mercuryThe Mercury and Air Toxics Standards (MATS) at issue before the U.S. Supreme Court last week are the result of a quarter century of legislation, regulation and litigation that began with the 1990 amendments to the Clean Air Act.

Congress amended the act to give the Environmental Protection Agency the authority to regulate 189 hazardous air pollutants (HAPS), including mercury, arsenic and cadmium that had not been previously controlled.

The law, signed by President George H.W. Bush, required EPA to develop emission standards for the pollutants, and then identify, categorize and regulate the sources that emitted them in large amounts.

The act expressly forbade EPA from considering cost when deciding whether to regulate sources other than electric generating plants; cost would only come into play in setting the level of regulation.

Other provisions of the 1990 amendments specifically targeted power plants, including the acid rain program, which required regulations on sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions from the largest coal-fired generators.

Appropriate and Necessary

Congress ordered EPA to perform a study evaluating whether the acid rain and other programs had addressed all public health concerns from generators. It ordered EPA to develop additional regulations if the agency determined it was “appropriate and necessary.”

EPA submitted the required utility study in 1998, concluding that the acid rain program would not significantly reduce HAPS emissions. In 2000, EPA announced it would regulate mercury, other metals and acid gases, noting that power plants were the biggest source of mercury emissions in the U.S.

EPA said mercury is a health hazard because it enters the food stream through fish and shellfish. Mercury can impair neurological development for fetuses, infants and children.

Reversal by Bush Administration

In 2005, however, the George W. Bush administration attempted to withdraw the listing, a decision that was voided by the D.C. Circuit Court of Appeals. The court said the government hadn’t met the criteria for delisting.

The Obama administration reaffirmed the decision to regulate mercury in 2012, saying it was necessary because other Clean Air Act regulations would not eliminate the health hazards posed. EPA said it interpreted Congress’ instructions in section 112 of the act as prohibiting the consideration of cost when it made the “necessary and appropriate” determination.

The MATS rulemaking sparked numerous challenges. While all parties agreed that section 112 was silent on the issue of costs, they disagreed on how that silence should be interpreted.

Last April, the D.C. Circuit upheld the MATS rulemaking in a 2-1 decision, with Judge Judith Rogers writing that section 112 “neither requires EPA to consider costs nor prohibits EPA from doing so.”

Judge Brett Kavanagh provided the ammunition for challengers to appeal to the Supreme Court, writing that the term “appropriate” required a cost-benefit consideration.

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DPL Protests Dominion Project over New Cost Allocation

By Suzanne Herel

dominionDayton Power & Light is protesting a $106 million transmission project by Dominion Resources under PJM’s 2015 Regional Transmission Expansion Plan because of a change in how the project’s costs will be allocated (ER15-1344).

The 500-kV Cunningham-Elmont end-of-life project (Project b2582) initially was designated a supplemental proposal, for which Dominion, as the incumbent utility, would bear the full cost.

“That was the correct designation for this project because it is simply a replacement for an existing transmission line for which Dominion has always had 100% cost responsibility,” DP&L said in a March 24 filing with the Federal Energy Regulatory Commission.

But after changing its local planning criteria last year, Dominion asked PJM to study the need for the project and received permission to change its designation to baseline, categorizing it as a new line and allowing Dominion to export more than half of its expense.

The new allocation scheme will charge DP&L about $1 million, the Ohio utility said, noting that larger PJM stakeholders such as Commonwealth Edison and American Electric Power will be expected to pay six to seven times that much. While AEP has filed a motion to intervene in the case, DP&L is the only entity to have submitted a protest.

The Dominion project was described as a supplemental project in a reliability analysis update at PJM’s July 10, 2013, Transmission Expansion Advisory Committee.

The criteria PJM used to redefine the transmission project, DP&L said, “was not developed by PJM for consistent application across PJM, but was instead based solely on ‘Dominion Planning Criteria.’ In other words, Dominion’s unilateral change of its own criteria for construction within its own zone has resulted in a recharacterization of this project from a supplemental project for which it would bear 100% of the costs to a baseline project for which about 52% of costs are exported to other zones.”

DP&L is asking FERC to reject the project or defer consideration to allow PJM transmission owners time to revise the Tariff to prevent them from unilaterally revising local planning criteria to secure baseline status for their projects.

DP&L said Dominion is exploiting what it called a loophole resulting from an Order 1000-related filing by PJM TOs that permits a portion of the costs of new 500-kV baseline projects to be shared by load-serving entities throughout the RTO.

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PJM Markets and Reliability Committee Members Committee Briefs

WILMINGTON, Del. — The MRC endorsed the following Thursday:

  • Manual 11: Energy & Ancillary Services Market Operations — Updates manual to include a method for screening of demand bids by load-serving entities, as approved by the Federal Energy Regulatory Commission in November (ER14-2976). Bids are limited to the LSE’s calculated zonal peak demand reference point for the day plus whichever value is more, 30% of the reference point or 10 MW. PJM said the need for such limits was illustrated by the default of a retail provider in January 2014 after it mistakenly entered a demand bid about 100 times its actual load. (See MIC Briefs.)

Marji Phillips of Direct Energy said the change is requiring her company to confirm its loads daily by phone with Pepco Holdings Inc. because of problems with Pepco’s electronic system. “Every day, we have no idea whether we will be able to meet the obligations we have to meet,” she said. “It is killing all the LSEs in the Pepco area — Delaware, New Jersey, D.C. It’s a tremendous problem.”

  • Manual 12: Balancing Operations — Revisions describe the required regulation range, specifying that resources are required to symmetrically provide the total amount of regulation assigned. The changes also detail how performance evaluations are conducted and further define the basepoint around which the resource will be regulating.
  • Non-substantive revisions regarding financial transmission rights. The changes concern clearing deadlines, bilateral trades and Tariff references.
  • A change to demand response modeling assumptions used in load deliverability analyses for the Regional Transmission Expansion Plan. The new method would use the average of the last three years of committed DR for each zone. (See Change Proposed in PJM Demand Response Modeling.)

Revisions to Manual 18 Address Capacity Performance

The MRC discussed manual changes needed to implement PJM’s Capacity Performance proposal, which is pending before FERC (EL15-29). The proposal would penalize underperforming units and reward those that over-perform. (See PJM Defends Capacity Performance Proposal; Drops Change for LSEs.)

The revisions, which affect Manual 18: PJM Capacity Market, would allow capacity resources to avoid performance penalties by requesting approval of retroactive replacement transactions within three business days after a delivery day that includes a performance assessment hour.

That would allow a participant with over-performing uncommitted capacity to replace underperforming committed capacity in the same account, Vice President of Market Operations Stu Bresler said.

Market Monitor Joe Bowring said the changes present an opportunity for economic withholding. “It is an incentive to withhold, and that is one of our concerns,” he said.

Members will be asked to endorse the revisions at the next MRC meeting if FERC has approved the proposal by then.

Members Committee

CTS Product, Fee for $20M-plus Projects Approved

The Members and Markets and Reliability committees endorsed a $30,000 non-refundable fee for studying proposed transmission improvements with estimated costs of $20 million or more. The fee, which PJM would evaluate for two years, would apply to both greenfield projects and upgrades by incumbent transmission operators. FERC last month rejected an earlier proposal to exempt transmission upgrades from the study fee. (See FERC Rejects Fee on Greenfield Transmission Projects.)

The MC also endorsed Tariff and Operating Agreement revisions to implement Coordinated Transaction Scheduling (CTS) with MISO. The objective is to improve interchange scheduling efficiency by aligning energy scheduling with interface prices and adding the option for market participants to schedule energy transactions using an interface bid. (See PJM, MISO Reach Agreement on New Interchange Product.)

 — Suzanne Herel