PJM must amend interconnection service agreements (ISAs) to allow two merchant transmission facilities to convert from firm to non-firm service, FERC ruled Friday, the latest reverberation resulting from the cancellation of the Con Ed-PSEG “wheel.”
The commission’s orders could relieve Hudson Transmission Partners (HTP) (EL17-84) and Linden VFT (EL17-90) from hundreds of millions in cost allocations under PJM’s Regional Transmission Expansion Plan.
Linden VFT’s exterior | Joseph Jingoli & Son
The commission said the companies’ ISAs, signed with PJM and transmission owner Public Service Electric and Gas, were unjust and unreasonable because they did not allow the merchants to convert firm transmission withdrawal rights (TWRs) to non-firm TWRs that are subject to curtailment.
HTP owns a 660-MW, 345-kV underwater HVDC line that connects PJM in northern New Jersey and NYISO in New York City. FERC issued a show cause order after PSE&G rejected its request to convert 320 MW of firm TWRs to non-firm. (See Rejecting PJM ‘Wheel’-related Requests, FERC Sets Inquiry.)
Linden VFT’s interior | Energy Initiatives Group
Linden VFT, which operates three 105-MW variable frequency transformers between the PSE&G system and Consolidated Edison, filed a complaint after PSE&G rejected its request to convert 330 MW of firm TWRs to non-firm.
The two merchant projects were part of a decades-old service agreement between PSE&G and Con Ed that the latter terminated in April. The service “wheeled” 1,000 MW from Upstate New York through PSE&G’s facilities in northern New Jersey and into New York City.
Following termination of the wheel, PJM asked FERC to reassign $533 million in costs related to the Bergen-Linden Corridor project to HTP, which the commission approved on April 25.
Under PJM’s Tariff, merchant transmission facilities are assigned the costs of the network upgrades that would not have been incurred “but for” their interconnection request. Merchant facilities also are responsible to pay annually for the costs of any post-interconnection network upgrades needed to support the merchant’s firm TWRs.
“We see no reasonable basis for barring HTP from converting from higher quality firm TWRs to lower quality non-firm TWRs by amending the existing ISA,” FERC said. “HTP already has satisfied the interconnection requirements, and we find that requiring it to maintain such firm TWRs for the life of the merchant transmission facility is unjust and unreasonable in the absence of any operational or reliability basis for doing so.”
The commission dismissed PSE&G’s allegation that reducing the service level would harm reliability.
“Under the existing ISA and PJM’s Tariff, PJM must guarantee that its transmission system is robust enough to permit HTP to use its firm TWRs to export 320 MW of power from its source in PJM across the river to New York at all times. Converting those firm TWRs to non-firm TWRs imposes no additional obligation on PJM and, in fact, is less burdensome in that PJM will no longer have to guarantee that its transmission system can support such use,” the commission said. “In any case, HTP’s line is fully controllable by PJM so that PJM can shut off flows if those flows jeopardize reliability or cause operational problems in New Jersey or elsewhere on the PJM system.”
FERC also rejected PSE&G’s contention that allowing the change would undermine the interconnection process. The commission said PSE&G’s argument that it relied upon the long-term duration of the existing ISAs was “unpersuasive,” noting that the merchants had unilateral rights to terminate the ISAs at any time.
The commission rejected as beyond the scope of the cases a request by PJM’s Independent Market Monitor to change Schedule 12 of the Tariff. The Monitor said the changes were needed to address what it called a discrepancy in the cost responsibility assignments for RTEP projects for merchant transmission providers that hold firm point-to-point transmission service and those that hold firm TWRs.
“Those general concerns with Schedule 12 do not address whether [the merchants] should be permitted to convert” their firm TWRs, FERC said.
The commission ordered PJM to file the revised ISAs in seven days from the Dec. 15 orders. Chairman Kevin McIntyre, who was sworn in Dec. 7, did not participate in the order.
Batteries have the unique potential to provide a broad range of valuable services to the grid. If operators are able to control the battery in a way that simultaneously captures multiple value streams, the resulting “stacked benefits” can amount to significantly more revenue than pursuing any individual stream in isolation. In some cases, those benefits can justify battery investment at today’s costs.
The potential for batteries to provide stacked benefits was challenged in a Dec. 5, 2017, RTO Insidereditorial titled “Grid Batteries & Kool-Aid, Once More with Feeling,” by Steve Huntoon. That article includes a critique of a report that I developed with colleagues at The Brattle Group, in which we quantify the multiple value streams that could be captured from batteries in California.[1]
| The Brattle Group
Huntoon’s article makes four basic points when arguing against the feasibility of stacked benefits. However, there are nuanced conceptual problems with each of those four points.
Combined Energy and Capacity Value
First, the Huntoon article argues that energy price arbitrage value cannot be added to capacity value, because “a battery cycled daily for energy arbitrage is going to be partially or totally discharged most of the time” and therefore unavailable to provide capacity. This assumes that all reliability events occur instantaneously, with no warning. In fact, system operators commonly provide notice prior to a reliability event and can often anticipate events in advance by tracking and forecasting supply and demand. Such notification would allow the battery operator to charge the battery and fulfill its commitment. Further, in the event that the timing of battery dispatch for energy value is not coincident with reliability needs, the modeling behind our study has accounted for that impact.
Capacity Value
The Huntoon article suggests that batteries cannot provide capacity value because reliability events often last longer than four hours (which was the assumed battery capacity in our study). However, system operators typically establish a performance duration that resources must satisfy in order to qualify as a capacity resource. The required performance duration is only three hours for “peak ramping” and “super peak ramping” resources in CAISO’s “flexibility capacity” products, for instance.
In fact, a battery with even less availability would still have capacity value. For example, the dispatch of two batteries each with two-hour capacity could be staggered in order to provide four hours of discharge. In the U.K., the government recently proposed a novel approach in which batteries are given capacity credit that is a function of their duration. Batteries with four-hour duration would receive the full allowed capacity credit. Batteries with less duration would receive a prorated credit.
To the extent that any individual day would have resource needs that are greater than four consecutive hours, that is accounted for in our study, and the capacity value of the battery was derated accordingly.
Energy Value
Huntoon’s article questions the extent to which battery operators could predict the highest priced hours of each day and discharge the battery during those hours. It is certainly true that battery operators will not have perfect foresight into market prices. However, system operators will schedule batteries in energy markets to minimize system costs. Our modeling is based on a realistic assumption that this dispatch will align reasonably well with high priced hours. Additionally, self-scheduling resources could use day-ahead prices as a guide for bidding into the real-time energy market, and potentially benefit from the higher price volatility in that market.
Frequency Regulation
The Huntoon article points out that frequency regulation is a shallow market with limited need. This is true, and is explicitly acknowledged in our report.[2] At the same time, early movers in many markets have provided significant value by using fast-responding batteries to provide this service. Frequency regulation (and other ancillary services) could become increasingly important in the future as more intermittent renewable resources must be integrated into the power system.
Additionally, in recognition of the current limited need for frequency regulation, we included a sensitivity case that assumed no incremental value from the frequency regulation market. In that case, the stacked value of the battery still exceeded $200/kW-year.
| The Brattle Group
A point that is not raised in the Huntoon article, but which is important to consider when assessing the value of energy storage, is the impact that large quantities of energy storage deployment could have on energy and capacity market prices, thus impacting the incremental value of additional storage resources. Our California study was focused only on the incremental value of 1 MW of storage. However, a study by my Brattle colleagues in the ERCOT market included detailed modeling that accounts for the effect of these market impacts on the stacked value.[3] The study identified a significant amount of economic energy storage potential, as well as a number of barriers to achieving that potential.
Capturing the Potential
Our study in California was intended to illustrate the potential system value of stacked benefit streams from battery storage in the absence of existing barriers. There certainly will be challenges to capturing this potential. To fully tap into this value, market rules may need to change, regulatory constructs may need to be revised, retail rates may need to be redesigned and technical challenges will need to be addressed.
But to paraphrase Theodore Roosevelt, “Nothing worth having comes easy.” In the power industry, initial skepticism about emerging technologies is regularly overcome through technological improvements and market and regulatory adjustments; just ask demand response providers, which have developed significant and valuable wholesale market resources over the past decade. In this case, the potential stacked value of battery storage is real and too significant to simply ignore.
Ryan Hledik is a Principal in The Brattle Group’s London office. He specializes in the economics of policies and technologies that are focused on the energy consumer. Mr. Hledik holds a Master’s Degree in Management Science and Engineering from Stanford University, and a Bachelor’s Degree in Applied Science from the University of Pennsylvania, with minors in Economics and Mathematics.
VALLEY FORGE, Pa. — PJM’s Independent Market Monitor faced a barrage of questions last week at the final stakeholder evaluation of its capacity market proposal ahead of a vote at Thursday’s Markets and Reliability Committee meeting.
Monitor Joe Bowring was absent for the first half of the meeting, leaving his chief counsel, Jeffrey Mayes, to answer whatever he could. Many were technical, however, and had to await Bowring’s arrival.
PJM offered stakeholders no assistance, making it clear from the start that its facilitation of the meeting did not indicate its support of the proposal. The Monitor’s MOPR-Ex proposal was the only one among 10 debated at the Capacity Construct/Public Policy Senior Task Force (CCPPSTF) to receive the task force’s endorsement and automatic consideration at the MRC.
After a year of meetings at the CCPPSTF, many stakeholders decided they preferred the current capacity design to any of the proposals, but they feared PJM would file its own two-stage repricing proposal in the absence of a clear endorsement by stakeholders. They believed that the RTO’s repricing proposal, which isolated subsidized generation offers from competitive ones by administratively reorganizing auction results, was such a drastic change that it could not be undone once implemented, while the Monitor’s proposal, which would extend the minimum offer price rule (MOPR), was as close to the status quo as possible.
The MOPR-Ex proposal would allow exemptions for many unique circumstances, including public power facilities and generators subsidized through states’ renewable portfolio standards, but it would not include Illinois’ zero-emission credit (ZEC) program. That doesn’t sit well with Exelon, which stands to benefit the most from the ZECs and whose own repricing proposal was rejected by the task force.
Exelon’s Jason Barker peppered the Monitor with questions about revisions to the RPS exemption that were inserted after the CCPPSTF endorsed it. Those revisions will be proposed at the MRC as an alternative to the endorsed version.
He asked Mayes if ZEC programs, designed to curb air emissions like other states’ renewable energy programs, qualify as “renewable” under the proposal. Mayes said no.
“We don’t understand the rationale of that program,” Mayes said. “The definition of ‘renewable’ is not all that complicated.”
The reason for the revisions, he said, was that programs that incented one type of renewable energy, such as wind or solar, are acceptable, but being preferential to a certain type of technology to harness that energy, such as offshore wind or rooftop solar, was not.
“It’s ironic that we’re trying to protect against states picking winners and losers and drafting tariff language that picks winners and losers,” Barker said. “They’d have the same effect on the marketplace, but one would be mitigated and one would not.”
The exemption calls for the inclusion of some programs based on the date of their implementation.
“It’s called ‘grandfathering.’ You’ve never heard of it?” asked Ruth Ann Price, who represents Delaware’s Division of the Public Advocate. “What Jason is trying to do is he’s trying to show some discrimination. I get it.”
Barker and his colleague Sharon Midgley also questioned revisions that prohibited supply from affiliates but allowed public power to overbuild facilities and then have the excess capacity exempted from the MOPR floor price.
Bowring acknowledged some of the concerns and said he would consider ways to address them in a revised final proposal.
The situation is complicated by a ruling from FERC that struck down the MOPR that PJM has been using since 2013 and on which the Monitor based its proposal. (See On Remand, FERC Rejects PJM MOPR Compromise.) The previous iteration of the rule was limited to gas-fired units and included fewer exemptions, and PJM has indicated it’s planning to allow that version to largely go back into effect with enhancements to calculation methods that have been developed since it was implemented.
Bowring, however, was unconcerned.
“I think the MOPR-Ex aligns explicitly with the order,” he said.
“They seemed to pretty emphatic that extending the mitigation period would be more costly,” Barker said, referring to FERC’s denial of an extension of the MOPR mitigation from one year to three years.
Bowring said the mistake was in using a floor price that was designed for a new unit for the subsequent years after the initial mitigation. Had the floor been switched to being based on the units’ net avoidable cost rate, it would have been consistent, he said.
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.”
BOSTON — Developing trust is vital for the project siting process, according to panelists speaking at Raab Associates’ 156th New England Electricity Restructuring Roundtable last week.
“The thing that most undermines a project is when the proponent is seen as not presenting facts, not disclosing things, misrepresenting things,” Conservation Law Foundation President Bradley Campbell told meeting participants. “And it happens more often than you might think.”
Patrick Woodcock, assistant secretary of energy with the Massachusetts Executive Office of Energy and Environmental Affairs, highlighted the region’s progress in reducing emissions over the past decade and his state’s long list of project approvals in the past six months, including electrical transmission, LNG storage and natural gas pipelines.
But Woodcock, formerly Maine Gov. Paul LePage’s principal energy adviser, also pointed out the “natural conflict” that occurs around permitting. “In Maine, the biggest issues were not with natural gas pipelines or transmission lines, but with wind permitting,” he said.
Developers found that about 10% of the turbines represented about 90 to 95% of the controversy in Maine, he said.
“What that does is not only impede those projects that get a lot of media attention, but it creates a controversy for the entire industry, and I think there are parallels with what we see in Massachusetts,” Woodcock said. “When you start to have bad actors, and we have had a few, that causes a public perception over the entire industry.”
Compare and Contrast
Campbell said a developer’s credibility issues are “the most potent weapon” CLF has when it opposes a project. He then compared two potential projects in New England: Northern Pass and the New England Clean Power Link.
Both projects were proposed in July in response to a Massachusetts solicitation for 9.45 TWh/year of hydro and Class I renewables (wind, solar or energy storage), with projects to be selected in January.
Eversource Energy partnered with Hydro-Quebec on Northern Pass, a 192-mile line that would bring 1,090 MW of Canadian hydropower into New England for 20 years starting in December 2020.
Transmission Developers Inc. partnered with Hydro-Quebec on the New England Clean Power Link, which would include a submarine cable under Lake Champlain and an overland section to transmit 1,000 MW of hydropower, solar and wind from Canada. (See Hydro-Quebec Dominates Mass. Clean Energy Bids.)
“There was inadequate public engagement on the Northern Pass side,” Campbell said. “There were many, many points at which Eversource New Hampshire lost credibility with the public by not disclosing or by making representations that later turned out to be inaccurate, and the … process was entirely without significant stakeholder input. As a result of that you have an absolutely oppositional circumstance, which is going to affect the state of the project.”
Even though Northern Pass received a presidential permit on the U.S. side, “that original sin of failing to engage with the public in a credible way stays with them,” Campbell said. “Compare that with TDI, where you have 100% of the line being buried, as mitigation and minimization, as opposed to 30% [with Northern Pass]. Many fewer wetland impacts, many fewer vernal pool impacts. Down the line, a better engagement process and one that, in the case of our initial opposition, resulted in what we think is a robust mitigation package and a piece of transmission infrastructure that would serve the region well and also serve the environment and advance environmental objectives well.”
Lawrence Susskind, director of the MIT-Harvard Public Negotiations Program, said there will always be winners and losers from projects — or people who see themselves that way. The difference between the two, he said, is that a million people in a city who stand to gain $100 from a project have no motivation either way, while just a few people, if they perceive themselves to be big losers, are motivated to oppose.
The key, Susskind said, is to influence the 30 to 40% in the middle who haven’t yet made up their mind. The “guardians,” as Susskind called them, want to be convinced of a project’s merits and will support the opponents if they think that the process is unfair.
Building Trust
Building trust with stakeholders is key, said MU Connections President Mary Usovicz, who works with project developers on strategy.
“Ask, don’t tell. Spend time listening,” Usovicz said. “I recently did a project and the managers came in and said, ‘What are our talking points, what are we going to say, how are we going to pitch this?’ And I said, ‘No, we’re not doing any of that. We’re going to go on a listening tour. We’re going to go and listen to what people have to say. You’re going to introduce yourselves and say, “And what do you think about this project? How would you do this?”’”
That client spent two months just meeting stakeholders and listening, and that leaves a sense of trust, she said.
“That’s how you build trust,” Usovicz said. “When you listen to what people say, acknowledge what they have to say and actually incorporate it. So they changed their entire campaign after they did this listening tour — that builds up trust. Also it allows you to know what are those gains that Professor Susskind spoke about.”
When they go on such listening tours, developers can sometimes be shocked about what is important to people, she said.
“One lady said, ‘I’ll let you build that pipeline if, with all the trees you have to cut down, you stack them as firewood for me,’” Usovicz said. “That was her ask. I was like, ‘Oh yeah, we’ll stack it. I’ll have my husband come and stack it.’ It’s amazing what is important to people, but if you don’t listen and ask, you’re going to jump to conclusions.”
For one LNG project in Connecticut, Usovicz’s polling and research determined that community members trusted first responders more than the developer, the utility and the mayor. Knowing that the project to expand an LNG facility would remove gas tanker trucks from the roads, she took that information to first responders, who wrote a letter in support of the project because of improved community safety.
“And then [first responders] became the point of reference for the project,” Usovicz said.
Andrew Weinstein, legal adviser to FERC Commissioner Cheryl LaFleur, spoke on behalf of his boss, who couldn’t attend the meeting because of family matter.
Weinstein read notes from LaFleur’s speech highlighting issues of the coming years, such as “how energy pricing evolves in the face of so many new technologies and services. We’ve talked for years about non-volumetric energy pricing based on attributes provided, rather than just fuel burned, and it’s closer than it’s ever been.”
ISO-NE CEO Gordon van Welie addressed what he said are the two most important issues facing the region: integrating markets and public policy, and fuel security issues, namely natural gas supply constraints in winter.
Van Welie pondered the issue of state support for renewable resources through contracting: “So the real philosophical challenge is how do you make a competitive market work if one set of resources in that market are going to get cost of service and the rest of the resources are merchant and have to live on the revenues in that wholesale market?”
If one stands back from the details, he said, the question is, “Should the market lean in the direction of creating certainty for the states in terms of the entry of their resources into the capacity market, or should we lean in the direction of ensuring price formation? And I think what you’ll see is the ISO leans a little bit in the direction of price formation, knowing that we’ve got a big, three-decade transition ahead of us.”
Van Welie also noted that the RTO has done a study on fuel security and will wait until issues are settled around the U.S. Energy Department’s Notice of Proposed Rulemaking to subsidize uneconomic coal and nuclear before releasing the report. (See ISO-NE Plans for Hybrid Grid, Flat Loads, More Gas.)
“We’ve got more gas-fired capacity than we need in the winter, but we don’t have enough fuel to supply it,” he said.
