VALLEY FORGE, Pa. — Despite being out of scope for potential rule changes, representatives of state interests last week asked for education sessions on load-related analyses during the first meeting of PJM’s new Summer-Only Demand Response Senior Task Force (SODRSTF).
The task force’s issue charge specifically prohibits proposed changes to loss-of-load expectation (LOLE) studies or business rules, but stakeholders still asked if they can learn about LOLE issues.
“I don’t think the out-of-scope items precludes us from doing any education,” said Greg Carmean, the executive director of the Organization of PJM States Inc. (OPSI), which represents state utility regulators within the RTO’s footprint.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), and EnerNOC’s Katie Guerry supported the request.
PJM staff agreed to education but warned that contemplating any changes based on that education would require seeking a charter amendment from the Markets and Reliability Committee.
James Wilson of Wilson Energy Economics, who consults for several consumer advocates within the PJM footprint, asked about the RTO’s seasonal capacity filing being out of scope for discussion, calling it “the elephant that’s not invited in the room.” Foregoing stakeholder endorsement, PJM last year unilaterally filed for FERC approval of its proposal to aggregate seasonal resources so they can qualify for the year-round rules of PJM’s Capacity Performance capacity construct. The proposal was accepted under delegated authority during FERC’s eight months without a quorum, but Wilson noted that the commissioners could review and reject it at any time.
PJM has far more summer-only seasonal resources than winter, so the aggregation rules left thousands of megawatts of summer-only resources without capacity commitments. In the aggregation filing, PJM agreed to address what to do with them since, as it acknowledged in the task force’s problem statement, “these resources have made investments, and in some instances commitments to state regulators, that will result in their continued operation (primarily as peak shaving resources).”
Calpine’s David “Scarp” Scarpignato asked the group to investigate what operational flexibility DR can provide beyond simply reducing load.
The task force’s next meeting is Jan. 29, when PJM will provide an overview of how it develops its LOLE study including winter resource adequacy, load forecast and installed reserve margin.
VALLEY FORGE, Pa. — Recognizing stakeholder concerns, PJM postponed a planned vote at last week’s Planning Committee meeting on its proposal to adjust the analysis process for market efficiency transmission projects. (See “PJM Seeks Changes to Market Efficiency Process,” PJM Planning and Transmission Expansion Advisory Committee Briefs: Nov. 9, 2017.)
PJM’s Asanga Perera acknowledged questions about the proposed problem statement and issue charge, which would reconsider the timing of market efficiency windows, how projects are selected, modeling and benefit calculation and how rejected projects are reevaluated.
During the meeting, stakeholders posed questions related to their specific interests.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), asked whether resiliency would be factored into project evaluation.
“Any project that we would put into the [Regional Transmission Expansion Plan], we would look at it for resilience as well,” PJM’s Paul McGlynn assured him.
LS Power’s Sharon Segner asked how cost-containment would factor into evaluations. PJM’s Sue Glatz said it’s being discussed.
Ryan Dolan with American Municipal Power asked about treatment of supplemental transmission projects.
“All we’re trying to do is point to issues we’re concerned about,” he said.
The special interest inquiries drove PJM’s Steve Herling to discuss level setting.
“We have to keep some of these things separate in the problem statement,” he said.
Cost-containment in Proposals
PJM unveiled proposed revisions to its Operating Agreement and Manual 14 to include cost-containment provisions and redaction requirements discussed at recent special sessions of the committee. (See PJM Stakeholders Battle over Cost Cap Rules.)
Terms and conditions relative to a cost cap commitment will be public information, though specific supporting information may be eligible for confidential treatment with appropriate explanation. PJM said it plans to limit cost cap evaluation to construction costs because they are the largest and most enforceable component of the overall cost.
Segner noted that other grid operators allow other cost-containment factors, such as annual revenue requirements and return on equity, and asked Poulos what the process would be to propose that PJM evaluate their inclusion in any evaluation.
“As you know, competition is something the [state consumer] advocates have wanted in this process — and even more competition,” Poulos said.
Other market issues requiring attention are piling up quickly, he said, so there has been nothing but discussions among advocates on the idea.
“The ratemaking process is where we feel is the appropriate place to take any additional challenges,” Glatz said, effectively punting the issue to FERC.
Alex Stern with Public Service Electric and Gas praised PJM for keeping conversation on the issue constructive.
“A number of [transmission owners] were concerned about the entire process as it went, but PJM ensured it remained … a challenging but collaborative process,” he said. It produced a “negotiated resolution, which I think is a fair direction for how to handle this at this juncture.”
Segner said she wouldn’t “necessarily agree on” Stern’s characterization because the result is a “significant deviation from what every other organized market in the country is doing relative to cost containment.”
One stakeholder chimed in from the phone to ask that because “cost containment is voluntary to start with, why would we put a limit on … that if they offer it?”
Glatz reiterated that PJM’s role doesn’t involve ratemaking and that construction costs are a “firm number,” while “the financing and ratemaking tends to have a lesser impact overall.”
Resilience in Planning
PJM’s Mark Sims told stakeholders to anticipate proposed rule changes in January to address planning for resiliency. Stakeholders requested that the topic be split off into a separate task force to facilitate additional discussion. PJM acknowledged the request. (See “Resilience in Planning,” PJM Planning/TEAC Briefs Oct. 12, 2017.)
Competitive Proposal Fees
The past two years have produced a deficit of $58,119 on evaluating Order 1000 competitive projects, PJM’s Michael Herman said. The numbers aren’t final, he said, but they represent a very good estimate.
Given that the evaluations cost $1.688 million and PJM collected $1.63 million, Herman said, “We think we did a pretty good job estimating the amount of money we would need to perform these analyses.”
With only two years of data to consider, PJM staff see refining the process as a “moving target.”
“Based on that, we feel it isn’t appropriate to make any changes to the process at this point,” Herman said.
The analysis showed this year’s deficit was offset by surplus collections last year. The costs include internal hours spent on evaluations, along with external costs for consulting on constructability and other analyses.
Herman said he’d have to follow up on Segner’s request for a breakdown of internal versus external spending. “While we do have some level of detail as to what variation on what was analyzed … I think it’s a little premature to jump to conclusions about trends,” Glatz said.
Herling acknowledged that “anything that’s outside of our wheelhouse gets expensive” and that “as a general matter, some of the external consultants are the bigger dollar” expenses.
PJM plans to return next year with additional data and draw more conclusions. If a change is needed, the plan would be to file it with FERC in early 2019.
Segner and Dolan expressed concern about supplemental projects being submitted by TOs that compete with projects submitted through competitive bidding.
“There’s no question that the supplemental projects as they’re submitted the way it works right now is problematic,” Segner said.
“People lob in a supplemental project at the 11th hour,” Dolan said. “Something is wrong with the process.” He also asked why a proposal fee shouldn’t also be required for supplemental projects.
2018 Preliminary Load Forecast
The RTO’s preliminary forecast for 2018 is more optimistic about demand than in previous years, PJM’s John Reynolds explained.
The forecast compares predictions for 2021 and 2023 with last year’s forecast. Summer demand during those years decreased slightly from last year’s forecast, but winter demand held steady or increased. The forecast for summer 2021 fell 0.7%, but the forecast for summer 2023 was down 0.1%.
Demand in winter 2020-21 was the same as last year’s forecast but increased 0.4% for 2022-23. Increases in the equipment index, which measures demand for heating, cooling and other uses, was the biggest factor.
Reynolds said that non-retail behind-the-meter generation transitioning to demand response was expected to be a major factor in the forecasts but ended up causing “very small changes” after some generators backed out after learning what would be required to make the transition and others learned they were already treated as DR.
Renewables Can Increase CIRs Through Hybrid
A PJM study found that renewable resources can increase their capacity factors upward of 33% by combining wind and solar into a hybrid generator.
The analysis provides a pathway for increasing capacity injection rights (CIRs), which indicate the threshold at which the RTO can curtail renewable resources injecting power onto the grid. By increasing their CIRs, renewable generators can essentially ensure they can produce more power more often.
PJM’s Jerry Bell said the analysis found that the generating capabilities of wind and solar units are often underutilized because they are operating at different times. Combining them creates a higher capacity factor.
The analysis focused on a 2.5-MW wind turbine combined with a 1-MW solar array, and Bell noted the 2017 results might be higher than normal because it was an above-average wind year.
“It’s feasible that we could … get a reasonably better capacity factor for the hybrid product,” he said.
The hybrid may be more attractive for PJM’s Reliability Pricing Model because it’s “less volatile” than the resources individually.
Gabel Associates’ Travis Stewart asked about studies combining renewables and storage. Bell said some proposals exist.
“I think it comes down to the metering and what’s going on,” Bell said.
VALLEY FORGE, Pa. — PJM’s plan to add several gas pipeline emergency procedures to its manuals was derailed by stakeholders at last week’s Operating Committee meeting.
Staff had included the pipeline contingency plans in revisions to Manuals 3: Transmission Operations Updates and 13: Emergency Operations, two of five manual revisions set for endorsement votes at the meeting. All five were endorsed by acclamation, but not before the pipeline contingencies were stripped out.
The revisions would have added procedures for assessing the impacts of gas contingencies on the grid, including system conditions triggering the assessment; determining applicable gas infrastructure contingencies; and coordination with generation owners and gas pipelines.
PJM is attempting to get rules for a responding to emergencies on the pipeline system documented before the winter season, but stakeholders fear a repeat of the polar vortex conditions in 2014, when gas prices soared past offer caps and generators were left with no mechanism to recoup costs in the aftermath.
Gas generator representatives convened before and during the meeting to orchestrate moving an informational item on system resilience — scheduled for the tail end of the meeting — to the top of the agenda ahead of the votes. During that discussion, Panda Power Funds’ Bob O’Connell proposed adding a waiver to the manuals that would allow gas generators to recoup all expenses incurred if PJM directed them to operate outside of their dispatch schedule during an emergency.
PJM balked at the proposal. Chris O’Hara, PJM’s deputy general counsel, questioned whether stakeholders could vote to require the RTO to include in its Tariff a waiver of its own rules. O’Hara’s input made other stakeholders, including Dave Mabry of the PJM Industrial Customers Coalition and Exelon’s Sharon Midgley, hesitant to support the waiver until they could vet the motion with their organizations. Both expressed willingness to discuss the matter further at the Markets and Reliability Committee.
The meeting took a short break to discuss the situation. When it reconvened, O’Connell withdrew his waiver proposal and instead moved to vote on the manual revisions without the pipeline-contingency sections. The votes passed, and PJM’s Ken Seiler, who chairs the committee, said that a solution would be developed to present to the Dec. 21 MRC meeting.
Owner Transfer Rules Revision
PJM is planning to revise its rules for alerting it to changes in generator owners. The revisions would require notification at least 60 days prior to the date requested for the generation transfer — time for the RTO to review the information and ensure that all required documentation is submitted.
The request would need to be accompanied by 22 pieces of information, including contact information, a fuel-cost policy for applicable units and reactive credits. The fuel-cost policy would need to be submitted within 45 days of the requested effective date. PJM plans to develop a user guide to provide step-by-step directions on how to fill out the necessary information.
VALLEY FORGE, Pa. — PJM is moving to implement three changes to its financial transmission rights market, developed through its FTR Modeling, Performance & Surplus special sessions. All three received endorsement at last week’s Market Implementation Committee meeting.
The first involves changes in long-term FTR modeling to account for future transmission system upgrades, which can impact congestion revenue. PJM is concerned that long-term FTR clearing prices don’t reflect “true future system capability.” FTRs entitle holders to credits based on locational price differences in the day-ahead energy market when the transmission grid is congested. They can be purchased or converted from auction revenue rights, which are allocated to network and firm point-to-point customers.
PJM’s annual ARR/FTR network model includes transmission upgrades that will be in place by the following June 30, and staff proposed expanding that methodology to the long-term FTR network model so that it also looks forward one year. The model would be filtered to only include upgrades that fit a “low-frequency, high-impact” threshold.
That threshold would be defined as the upgrade being a constraint itself or impacting by +/-10% constraints that have contributed at least $5 million to congestion over the past year or any future constraint. For new facilities, the analysis would be based on the line outage distribution factor (LODF), a measure determining how the change in a line’s status affects flows elsewhere in the system. The FTR group would work with PJM’s planning staff to determine which upgrades should be included in the model. PJM included in its presentation an example of how that process would have worked for 2016 and found that three out of 21 upgrades would have been modeled.
PJM would also develop a new long-term residual ARR market to ensure holders maintain priority rights to any incremental capability created by upgrades still to be modeled.
The second set of changes would improve PJM’s ability to finalize and publish FTR auction results on time. Impetus for the solution came after PJM delivered its March auction results late and blamed it on having to simultaneously finish the results for several overlapping FTR auction periods. (See “FTR Lateness Blamed on High-Volume Period,” PJM Market Implementation Committee Briefs.)
PJM proposes to resolve the issue by eliminating some auction periods. PJM’s Brian Chmielewski said the proposal, if endorsed on its current timeline, would be filed with FERC in February to be effective for the June overlapping period.
The third set of changes would allocate any surplus from FTR auctions and day-ahead congestion to ARR holders after FTRs are fully paid to their target allocations. The issue developed after FERC required PJM to revise its methods for allocating ARRs and balancing congestion. (See FERC Accepts PJM’s FTR Plan, Rejects Rehearing Requests.)
MIC members had to vote on two proposals: one developed by a coalition of ARR holders that allocated all surplus to holders, and a second developed by financial traders that allocated FTR surpluses to ARR holders up to their target credits and all day-ahead congestion surpluses to FTR holders.
The MIC endorsed the ARR holder proposal with 90% in favor and rejected the financial traders’ proposal with 34% in favor.
EnerNOC DR Aggregation Solution Questioned, Approved
“We don’t think this is a problem,” Independent Market Monitor Joe Bowring said, adding that “it seems to be presupposing the solution.”
Other stakeholders reiterated previous complaints that PJM’s stakeholder meeting schedule is already overbooked and that examining the issue doesn’t provide enough relative benefits to justify adding to the load.
“If we take issues up where there’s not really a problem, we create extra work for ourselves. I don’t think you can blame PJM for that. We have to blame ourselves,” Calpine’s David “Scarp” Scarpignato said.
EnerNOC argues that the current registration process is inefficient and provides a Capacity Performance value that fails to reflect the full reduction that the aggregated resources could achieve. PJM did not update its customer-registration rules when DR rules were revised to comply with CP requirements, nor did it seek stakeholder endorsement prior to unilaterally filing for approval last year of its seasonal aggregation plan. (See FERC Staff OKs PJM Aggregation, DR Rules; Refunds Possible.)
Unable to work out their differences on how to regulate the market path of energy sales coming into PJM, the Monitor and financial marketers are asking the MIC to resolve the issue. They are presenting three different proposals on the issue.
The Monitor’s proposal would develop a list of “prohibited paths” that could be subject to resettlement. The Monitor would develop a monthly report of activity on those paths and share it with PJM so that either entity could refer use of those paths to FERC for enforcement.
Pierce Atwood partners Ruta Skucas and Jared des Rosiers presented a proposal developed by American Electric Power and the Financial Marketers Coalition. It would entail a change in PJM’s Tariff for the initial list of banned paths and require FERC, PJM and Monitor approval for any additions. It would also develop a “query” where users could seek a preliminary evaluation from PJM on whether a potential path would risk resettlement.
Stephen Kelly of Brookfield Renewable presented another proposal that would allow market participants the opportunity to establish with PJM and the Monitor that a potentially problematic transaction is “legitimate” before it is automatically resettled.
The proposals also differed on what level the activity should be evaluated. The Monitor proposed considering it from the level of the parent corporation, but the others called for analysis on the level of individual companies.
State regulators on Monday called on FERC to change its interpretation of the Public Utility Regulatory Policies Act to “align” the 1978 law “with modern realities.”
John “Jack” Betkoski III — vice chairman of the Connecticut Public Utilities Regulatory Authority and president of the National Association of Regulatory Utility Commissioners — wrote FERC commissioners a letter saying he was pleased that interim Chairman Neil Chatterjee had pledged that the commission would be pursuing PURPA reform.
“As the primary point of responsibility for PURPA’s on-the-ground implementation, the states have a strong interest in the reform of PURPA’s associated federal administrative regulations, and we hope this reform will continue to be a priority under the leadership of Chairman [Kevin] McIntyre,” Betkoski wrote.
Betkoski cited four changes since PURPA’s enactment in 1978 that he said required a new look from FERC. “These four changes — the rise of wholesale markets, the place of [qualifying facility] technologies as a commonplace source of power, the open-access regulation of the transmission system and the use of competitive methods to select projects throughout the states — suggest that PURPA’s administrative regulations should be aligned to these developments, instead of obstructing them. Despite these changes, many states incur significant transaction costs administering PURPA pursuant to the law’s arcane, 20th century mandates,” Betkoski wrote.
Pa’Tu Wind Farm Construction | PaTu / White Construction Company
He quoted Montana Public Service Commissioner, and former NARUC president, Travis Kavulla, who told the technical conference that PURPA issues consume more than one-quarter of his commission’s time on electric utility regulation. (See Montana PURPA Solar Saga Continues in State Court.)
NARUC proposed three changes, “each of [which] allows FERC to work within existing law to make meaningful changes to PURPA, while remaining committed to the law’s underlying goals of competition and encouragement of QF technologies,” Betkoski said.
NARUC proposed that FERC:
Adopt regulations that move away from the use of administratively determined avoided costs to their measurement through competitive solicitations or market clearing prices. “We propose that in certain circumstances, such as when a QF has both nondiscriminatory access under an [Open Access Transmission Tariff] and exists in a region where public utilities routinely use competitive solicitation processes, such a construct would qualify as wholesale markets under 18 CFR 292.309(a)(3). Making this determination would allow FERC to erase the false dichotomy between RTO/ISOs regions, and those regions without such an RTO/ISO but where each public utility nevertheless has an OATT and where states oversee utility procurement and require the use of competitive solicitations.”
Lower or eliminate the 20-MW threshold for the rebuttable presumption that QFs with a capacity at or below that size do not have nondiscriminatory access to the markets. “In keeping with the goal that FERC should better align PURPA implementation with modern realities, this threshold should be lowered to whatever the minimum capacity requirement is for a resource to participate in an RTO/ISO.”
Making changes to the 1-mile rule to discourage gaming. “There are a number of well-documented incidents where projects have forgone economies of scale to qualify themselves as individual QFs and evade other regulations; for instance, state commissions requirements for competitive solicitations. The commission should not encourage this form of regulatory arbitrage.” NARUC recommended Idaho Public Utilities Commissioner Paul Kjellander’s suggested criteria for determining whether a single project has been disaggregated in order to create multiple QFs under the generation size limit.
Public Service Enterprise Group and Exelon would receive hundreds of millions in subsidies to maintain the profitability of three in-state nuclear plants under legislation introduced in the New Jersey Senate on Friday (S3560).
Two of the sponsors, Sens. Stephen Sweeney and Jeff Van Drew, represent the area of southern New Jersey where the units are located. The third, Sen. Bob Smith, is chair of the Senate Environment and Energy Committee. PSEG has three nuclear reactors between the Salem and Hope Creek facilities; Exelon owns 43% of the Salem units.
Salem & Hope Creek Nuclear Power Plants | Green Delaware
Under the bill, the plants could be compensated through the issue of “nuclear diversity certificates” (NDCs) representing the “environmental and fuel diversity attributes” of 1 MWh produced by an eligible nuclear unit. All utilities in the state would be required to purchase NDCs from the nuclear plants monthly.
Funding for the program would come from a 0.4-cent/kWh charge on all New Jersey retail customers’ bills. The state Board of Public Utilities would have discretion to reduce the charge as it deems appropriate.
Several groups, including PJM’s Independent Market Monitor, New Jersey’s Division of Rate Counsel and coalitions of in-state citizen advocates and non-nuclear power generators oppose the plan and have pointed out that PSEG’s plants remain profitable. (See Opponents Assemble as PSEG Seeks NJ Nuke Subsidy.)
The three nuclear units provide about 40% of the state’s power. PSEG has estimated the subsidies could cost $240 million a year, about $31 for an average residential ratepayer. The Division of Rate Counsel put the cost at $320 million, or $41 per customer.
Eligibility Process
Plants would become eligible for NDCs by providing, within 30 days of the law’s enactment, certified three-year forward-looking cost projections that include operations and maintenance, fuel, non-fuel capital, and a valuation of operational and market risks that would be avoided if the plant shut down. The plants also could provide “any other information, financial or otherwise, to demonstrate that the nuclear power plant’s fuel diversity and air quality attributes are at risk of loss because the nuclear power plant is cash negative on an annual basis, or alternatively is not covering its costs including its cost of capital on an annual basis.”
Exelon and PSEG would also have to provide “certification that the nuclear power plant will cease operations within three years unless the nuclear power plant experiences a material financial change, and the certification shall specify the necessary steps required to be completed to cease the nuclear power plant’s operations.”
All information could be supplied confidentially.
The BPU would then have another three months to develop an application process for the plants to receive payment for their NDCs, and the plants would have another month to apply. A plant would have to satisfy five inquiries concerning why it deserves to be in the program and pay an undetermined application fee that could reach $250,000.
Justification
The bill references New Jersey’s plan to secure 70% of its energy needs from “clean energy sources by 2050,” calling nuclear a “critical source of zero-emissions energy.”
If the plants close, the void will be filled with natural gas plants, the bill says, and that “capacity challenges on existing natural gas pipelines combined with the difficulty in siting and constructing new natural gas pipelines, along with competing uses for natural gas, such as building heating, have created supply constraints in the past, and those constraints could impact system reliability.”
Part of the bill’s justification is that “recent severe weather events have demonstrated the need to improve the resilience of the electric power delivery system” and that “the mix of generation resources serving New Jersey residents must be capable of handling high-impact, low probability weather events.”
However, selected plants could be excused from performance in the event of natural disasters or other catastrophic events, such as labor disputes, or if the plant would need more than $40 million in capital expenditures. Plants that stop operating for a reason that isn’t covered would need to pay back all the payments it received since its last eligibility determination.
“Gov. [Chris] Christie is attempting one last robbery of the people and environment of New Jersey before he leaves office in January,” Jeff Tittel, director of the New Jersey Sierra Club, wrote in an op-ed about the bill Monday.
“The bill would give PSEG subsidies for their nuclear plants in New Jersey and simultaneously tie Governor-elect [Phil] Murphy’s hands when it comes to promoting renewable energy. Cheap natural gas combined with nuclear subsidies means renewable energy gets pushed out. Christie is trying to dictate New Jersey’s energy policy for the next 40 years, despite the fact that the people want renewable energy, and this bill undermines that.”
The U.S. Supreme Court last week denied DTE Energy’s petition to review an environmental penalty against one of its Michigan coal plants over increased emissions, but the new tone set by the head of EPA will likely diminish the court’s action.
The court on Tuesday declined to hear the Michigan-based utility’s defense of upgrades it performed on its coal-fired Monroe power plant, clearing the way for EPA enforcement action. (See DTE Initiates Last-Ditch Effort in Clean Air Act Case.)
DTE Energy’s Monroe Power Plant | Port of Monroe
However, the agency has performed an about-face under in the intervening months since DTE filed a writ of certiorari with the court. Administrator Scott Pruitt earlier this month released a policy memo specifically citing DTE’s case and adopting some of its arguments against having to pay penalties for excessive air pollution, making it unlikely the agency will pursue penalties.
EPA and the Sierra Club have pursued enforcement against DTE since 2010, when the company started a $65 million upgrade to Unit 2 of the 46-year-old Monroe coal plant without installing additional pollution controls. They contended the upgrade violated the Clean Air Act’s New Source Review (NSR) program because DTE ignored its own projections that the renovation would cause emissions to increase by thousands of tons per year. EPA called the project a major overhaul that should have included new pollution controls and sought civil penalties of up to $37,500 per day.
DTE maintained that the higher emissions from the Monroe plant were a product of demand growth and not caused by the improvements. By 2014, DTE had installed four selective catalytic reduction units and four flue gas desulfurization units at the plant at a cost of about $2 billion.
“It is pretty simple. DTE chose to overhaul their dirty coal plant and not install modern pollution control technology at that time even though their own projection showed that pollution would increase after the overhaul,” said Regina Strong, director of the Sierra Club’s Beyond Coal Campaign in Michigan.
DTE contended that enforcement action could not proceed until after an actual pollution increase occurred, an argument that the 6th U.S. Circuit Court of Appeals twice rejected (14-2274, 14-2275).
However, Pruitt’s memo aligns with DTE’s arguments, saying that EPA will no longer bring NSR enforcement against generators until they’ve had the chance to increase pollution, contradicting the preventative nature of the NSR that the 6th Circuit recognized.
Pruitt wrote that EPA does not “presently intend to initiate enforcement … unless post-project actual emissions data indicate that a significant emissions increase … did in fact occur.”
According to the Sierra Club, EPA will now “no longer seek to challenge even obviously faulty or fraudulent projections by a utility that a proposed modification to a coal plant will purportedly not lead to a New Source Review-triggering emissions increase so long as such projection was procedurally done properly.”
“The new Pruitt approach appears to be little more than an attempt to give coal utilities a sense of empowerment to ignore the critical public health protections of the Clean Air Act New Source Review program,” Shannon Fisk, managing attorney with environmental law firm Earthjustice, said in a statement. “Such [an] approach should not stand as it is contrary to law, public health and common sense.”
CARMEL, Ind. — MISO is moving ahead with developing an automatic generation control (AGC) program designed to rapidly deploy 400 MW of fast-ramping resources by regulating either up or down in response to fluctuations in load.
Speaking during a Dec. 14 Market Subcommittee meeting, Pavan Addepalle of MISO’s market engineering group said the RTO is moving from a conceptual design phase to detailed design with a vendor. MISO hopes to implement AGC by late 2019.
Addepalle said MISO will add new real-time market hourly offer parameters to accommodate the faster units but use the RTO’s existing market and settlement rules to clear regulation. Resources must have a minimum 80-MW/minute ramp rate and a regulation limit of 1 MW or more to be eligible to participate in the program.
In response to a question from Northern Indiana Public Service Co.’s Bill SeDoris, MISO staff said resources under AGC will be cleared in the same market as other resources, but that fast- and slow-responding resources will be divided into pools waiting on separate dispatch signals.
“We’re going to have a single energy market but realize that resources have different parameters and constraints … and design a market that is capable of using separate resources differently,” said MISO Executive Director of Market Design Jeff Bladen, adding that the RTO will not follow in PJM’s footsteps in creating a separate regulation market.
ITC Holdings’ Ray Kershaw said the new designation, while amenable for pumped energy storage, is not an ideal use for batteries.
Addepalle said MISO did not approach the proposal with a specific type of generation in mind.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:40)
Members will be asked to endorse the following proposed manual changes:
A. Manual 1: Control Center and Data Exchange Requirements. Revisions developed to update NERC references and procedures related to outages and system-restoration planning. PJM members will be required to send the RTO data on transmission megawatt and MVAR flows and bus voltages at greater than or equal to 100 kV, down from 345 kV.
B. Manual 10: Pre-Scheduling Operations. Revisions developed to comply with NERC standards as part of a periodic review of the manual. Generators will be required to notify PJM of operating conditions that could result in a single contingency causing an outage of multiple generators.
C. Manual 14D: Generator Operational Requirements. Revisions developed as part of a periodic review. Generators will need to be modeled in eDART consistent with the PJM energy management system model.
3. Manuals 3 and 13 Revisions and Gas Pipeline Contingencies (9:40-10:10)
A. Members will be asked to endorse proposed changes to Manual 3: Transmission Operations and Manual 13: Emergency Operations, which include processes for addressing gas pipeline disruptions that affect generator reliability.
B. Members will also be asked to endorse manual revisions proposed by gas-fired generators to document compensation mechanisms for generators directed by PJM to take action related to a pipeline contingency. (See related story, “Gas Generators Block PJM Pipeline Plan,” PJM OC briefs: Dec. 12, 2017.)
Members will be asked to endorse revisions to the Tariff, Manual 28: Operating Agreement Accounting and Manual 6: Financial Transmission Rights resulting from special sessions on FTR issues. The revisions will address changes to long-term FTR modeling for future transmission expansion, streamlining management of overlapping FTR auctions and allocating any surplus funds from day-ahead congestion and FTR auction revenue. (See related story, “FTR Discussions,” PJM MIC briefs: Dec. 13, 2017.)
5. New Service Request Study Methods (10:40-11:00)
Members will be asked to endorse changes to the procedures for the study of transmission service requests and upgrade requests in the new services queue process. (See “Interconnection Study Process to be Rearranged,” PJM Planning/TEAC Briefs Oct. 12, 2017.)
6. Energy Market Price Formation Problem Statement & Issue Charge (11:00-12:00)
Members will be asked to endorse PJM’s proposed problem statement and issue charge to changes price formation in the energy market. The RTO has proposed revisions that would allow inflexible units to set LMPs. The Independent Market Monitor has proposed an alternative problem statement and issue charge that would take up to two years to examine all components of energy market price formation and determine if changes are needed. (See “Questions Remain as PJM Continues Push for Price Formation Revisions,” PJM Markets and Reliability/Members Committees Briefs: Dec. 7, 2017.)
7. Capacity Construct/Public Policy Senior Task Force (CCPPSTF) (12:45-1:45)
Members will be asked to endorse Tariff revisions associated with the Monitor’s “MOPR-Ex” proposal to change the minimum offer price rule. The Monitor is proposing to amend the version endorsed by the Capacity Construct/Public Policy Senior Task Force to revise exemptions for state renewable portfolio standards. (See related story, IMM Battles Exelon on MOPR-Ex Proposal.)
8. Incremental Auction Senior Task Force (IASTF) (1:45-2:00)
Members will be asked to endorse a proposal developed by the Incremental Auction Senior Task Force to address concerns of excess capacity and low clearing prices. Although Proposal A” did not receive enough support at the IASTF to be automatically considered at the MRC, stakeholders moved for an endorsement vote. (See “Stakeholders Move Incremental Auction Proposal,” PJM Markets and Reliability/Members Committees Briefs: Dec. 7, 2017.)
FERC last week set hearing and settlement proceedings for a new Ohio merchant plant, saying it had not provided sufficient backing for its reactive power revenue requirement (ER18-92, EL18-32).
The 747-MW Carroll County Energy combined cycle plant, expected to go in service this month, is seeking compensation for its generator, associated exciter equipment, step-up transformers and other equipment under allocation factors representing their contribution to both reactive service and real power.
Carroll County Energy Plant Schematic | Power Technology
The commission said the plant’s owners had not demonstrated that its proposed revenue requirement was just and reasonable. “CCE’s filing has no underlying support for the costs claimed for this new generation facility, and the balance of plant investment allocator and the accessory electrical equipment allocator may be excessive. We further note that the components of the accessory electrical equipment are not provided,” the commission wrote.
FERC said that, if no settlement is reached, it expects to issue a decision within eight months of the filing of briefs opposing exceptions to the initial decision by an administrative law judge. “If the presiding judge were to issue an initial decision by July 31, 2018, we expect that, if the proceeding does not settle, we would be able to render a decision by May 31, 2019.”
The plant’s owners include TIAA, Chubu Electric Power, Ullico, Prudential Financial and Advanced Power, a Boston-based development company that oversaw construction and will manage the start of commercial operations. Chairman Kevin McIntyre did not participate in the decision.
