WASHINGTON — Arnie Quinn, director of FERC’s Office of Energy Policy and Innovation, had modest hopes for reaching consensus when he moderated a panel on public policy and wholesale markets at the Energy Bar Association’s Mid-Year Energy Forum last week.
The panel included Exelon’s Kathleen Barron, a defender of zero-emission credits for nuclear plants, and NRG Energy’s Peter Fuller, whose company is a harsh critic of the subsidies.
“While I think it might be hard to come up with a consensus about what ultimate landing spot we’d like to get to … at least agreeing on what we’d like to avoid would be helpful,” Quinn said.
Quinn also invoked one unsafe word for the discussion: “MOPR” — minimum offer price rule. “Unfortunately, we’ve got a lot of pending dockets on minimum offer price rules,” Quinn explained.
MOPR was not invoked. But consensus was indeed elusive in the discussion, which included FERC’s May 1-2 technical conference on state policies and wholesale markers and Energy Secretary Rick Perry’s call for price supports for nuclear and coal plants.
Barron, Exelon’s senior vice president for competitive market policy, defended the ZECs approved in New York and Illinois, saying they had a “quite modest” impact on wholesale markets compared to state renewable energy credits and rate-based generation.
“I think we need to take a step back when we launch this conversation to just recognize that even the Eastern markets are not free of intervention,” she said. “By 2025, about 30% of the generation in PJM will either be rate-based — through state cost-of-service regulation — public power or [renewable portfolio standard] programs,” she said.
Even if all of PJM’s nuclear generation — currently 19% of the RTO’s capacity mix — were subsidized, she said, it would still have a smaller impact than state RPS goals. “How many renewable resources would they like to have?” she asked. “25%, 30%, 50% by 2030?”
Moreover, while ZECs are worth $17.54/MWh in New York, that is less than the state’s RECs, which run as high as $23.28, she said. Illinois’ ZECs are $16.50/MWh, while their solar RECs are worth more than $200/MWh. And Maryland will pay $132/MWh for offshore wind RECs. “So we’re talking about relatively small amounts compared to other clean generation programs,” she said of ZECs.
Despite his company’s opposition to ZECs, Fuller did not contest Barron’s claims. Instead he chose to discuss his company’s “four product” vision of the future: renewables, energy storage, controllable demand and fast-ramping gas.
Fuller said that the Department of Energy’s Notice of Proposed Rulemaking had sparked an “extremely important conversation” and that a role for fuel security is an “option to think about.”
But he added, “The solution set, I think, is much broader than what was in the original notice from DOE.”
In a future dominated by zero- or low-marginal cost future, the LMP markets based on fuel costs “breaks down,” he said. “Are we doing locational marginal pricing right? Are we calculating energy prices right? PJM has a proposal to really look at different eligibility for setting energy prices. That would be an important idea. Clearly we need scarcity pricing everywhere to capture the operational realities of the markets.”
Fuller was the only member of the panel — which included Rob Gramlich, of Grid Strategies, and Potomac Economics’ David Patton, whose firm performs market monitoring for MISO, NYISO, ERCOT and ISO-NE — who did not have FERC tenure on his resume.
‘Wacky’ Federal Initiatives and RTO ‘Mission Creep’
Gramlich, a former senior vice president for government and public affairs for the American Wind Energy Association who now consults for AWEA and other clean energy interests, said the DOE NOPR would “upend 25 years of progress toward competitive markets.”
“We’ve had this conversation many times,” said Gramlich who served as senior economic adviser to FERC Chairman Pat Wood III in 2001-2005. “I think there’s one major thing that’s changed from the previous [discussions]. Usually the context is the wise, well intentioned federal authorities or the RTOs trying to clean up or fix what the wacky states are doing. [Now we’re considering] not only wacky state policies but wacky federal policies and see whether we have a regulatory structure that can withstand that,” he said, sparking laughter. “You might say whether it’s resilient, whether it can withstand and bounce back rapidly from narrow political interventions.”
Gramlich said market interventions have caused “mission creep” for RTOs beyond their traditional roles of running the transmission system and wholesale markets. “I’m frankly concerned that the RTO missions are getting extended well beyond those two core things and that a lot of states and utilities will look at these RTOs and say, ‘I’m out.’ Or, ‘I’m in the West and I was thinking of joining. Now I’m not.’”
Gramlich was skeptical of Perry’s call for compensating generation units for having on-site fuel supplies or providing “essential reliability services.”
“We’re seeing all sorts of interests saying their product or their generation type provides this, that or the other thing to the grid. I’m really relying on FERC here to decide: Is that actually needed? Is that actually a service? And if so, can others provide it as well? And let’s create real competitive markets: define the service and then let any and all bidders bid to provide that service.”
Patton said policymakers face an existential question. “You either believe in markets or not. And if you don’t believe in markets then why are we doing this?” he asked.
“This just becomes a giant rent-seeking exercise. I know when I say that to a room full of lawyers, that doesn’t sound terrible,” he added to laughter.
Patton said FERC deserves blame because it has “never articulated any sort of standard on what a just and reasonable capacity market looks like. The closest they’ve ever come is in New York, saying it’s got to produce a price signal that will be sufficient to get an adequate resource mix.”
He noted that capacity markets incent generation investments that are evaluated over a lifespan of 30 or 40 years.
“If every year or two you have dramatic policy shifts that change fundamentally what people’s expectations are about the market revenues they’re going to get, then you get … the worst-case scenario.
“It’s alarming how many times … new [FERC] commissioners have come in and said, ‘I want to revisit whether capacity markets are a good idea. Let’s have a technical conference and determine whether capacity markets are delivering on their objectives.’ Basically, the subtext is we may do away with these things. And they’re delivering roughly half the revenue that the generation needs to break even on a new investment. … It’s like when Congress says, ‘We may not raise the debt ceiling.’ How do you even say that?”
Patton disputed arguments Perry and others have made in defense of price supports.
“When people tell me we’re overly gas-dependent, we don’t have markets that value fuel diversity, [I say] that’s absolutely not true. When people say we don’t have a market that motivates generators to be available and perform, that’s absolutely not true,” he said. “They’re assertions that support doing something and changing the markets. But if you think about what we’re talking about, if you have good shortage pricing and we’re short somewhere because a gas pipeline blew up, then everybody who’s got dual-fuel capability [or is] powered by something other than gas makes an enormous amount of money. Anyone who’s gas-only and didn’t make provisions to be able to run in that scenario loses a lot of money, especially under the New England [Pay-for-]Performance rules that overcompensate performance.”
Patton said the NOPR’s notion of “‘resilience’ is just reliability” for contingencies whose probabilities are so low that grid operators haven’t planned for it.
“And if it happens, our shortage pricing is going to account for it,” he said. “The overriding objective should be to maintain market signals, and there’s only a few of them: There’s energy, ancillary services and capacity. You don’t need 10 products to do that.”
MISO and PJM have withdrawn their support for developing the lone interregional market efficiency project to emerge from the RTOs’ two-year coordinated system plan, stakeholders learned Friday.
The proposed 30-mile, 138-kV line between Northern Indiana Public Service Co.’s Thayer and Morrison substations near the Indiana-Illinois border was expected to cost $61.8 million and be in service by December 2022. NIPSCO’s early estimates pegged the cost at $42.5 million. (See “MISO-PJM Coordinated System Plan Produces One Project,” FERC Conditionally OKs MISO-PJM Targeted Project Plan.)
| MISO and PJM
The project was the only one of eight stakeholder-originated suggestions to initially pass the RTOs’ benefit-cost criteria, but it ultimately failed a joint 5% generation-to-load-distribution factor (GLDF) test, which requires each RTO to show that one of its generators has at least a 5% impact on the affected flowgate. PJM did not meet the threshold.
During an Oct. 20 Interregional Planning Stakeholder Advisory Committee conference call, NIPSCO’s Matt Holtz said the addition of the GLDF test essentially equates to a joint benefit test that FERC ordered the RTOs to eliminate from their “triple hurdle,” which included their separate regional benefit tests. He expressed disappointment that both RTOs would withdraw support from the project when “just using the regional processes showed a lot of economic benefit to MISO and PJM.”
“I’m not sure that we would agree with that analysis,” PJM engineer Alex Worcester responded. “I’m not sure that each RTO’s impact on the model ties to a triple hurdle.”
“The 5% criteria has long been in the [joint operating agreement],” said Chuck Liebold, PJM manager of interregional planning.
Another PJM stakeholder said the GLDF test amounted to a “technicality.” Worcester said PJM is open to examining its test requirement.
To address congestion in the area, local transmission owner Ameren upgraded its transmission ratings, resulting in congestion being shifted away from a nearby 138-kV line to another line in the PJM footprint, Worcester said. The updated ratings cleared up congestion on the PJM side of the seam, compelling the RTO to withdraw its recommendation for the project based on its regional analysis, even if the GDLF test wasn’t an issue.
Wind on the Wires’ Rhonda Peters asked for the reason behind the change in rating to the line.
“We can’t always be perfectly coordinated,” Worcester said, adding that he didn’t know why Ameren upgraded the rating. MISO interregional coordinator Adam Solomon said his RTO could investigate the change.
Worcester said MISO could pursue the Thayer-Morrison project in its separate process. MISO has said it may consider the project for its annual Market Congestion Planning Study next year.
The RTOs’ next interregional market efficiency project proposal window required under FERC Order 1000 opens in November 2018. Stakeholders have until February 2019 to submit project suggestions.
In the meantime, Solomon said both MISO and PJM staff would work together on ways to improve the process behind their coordinated system plan.
FERC last week accepted NYISO’s proposed Tariff changes establishing a mechanism to recover costs for eligible transmission projects in the ISO’s Comprehensive System Planning Process.
The commission’s order accepted revisions to section 6.10 (Rate Schedule 10) and Attachment Y of NYISO’s Tariff effective Oct. 18 (ER17-2327).
NYISO submitted the proposed revisions in August, arguing that since the commission approved the current Rate Schedule 10 in 2008, it has instituted new planning procedures that created gaps in its ability to fairly allocate transmission cost recovery.
The grid operator said the proposed Tariff revisions would “enhance and expand the applicability of Rate Schedule 10, so that it can be used for all regulated transmission projects in any of the three planning processes (i.e., reliability, economic and public policy-driven.”
The tariff changes replace its existing Reliability Facilities Charge with a new Regulated Transmission Facilities Charge that will allow NYISO to recover from load-serving entities — and pay to transmission developers — the costs associated with any regulated transmission project that is eligible for cost allocation and recovery under its Comprehensive System Planning Process.
While New York transmission owners generally supported NYISO’s filing, they asserted that some language in the proposed revisions might inadvertently modify the abandoned plant costs that a TO or developer is eligible to recover under the state’s reliability planning process.
The commission ruled that the TOs did not explain the basis for their position and, “given the lack of specificity” in their comments, there were no grounds for it to act on their concerns. The commission also said that it already made clear that it would “grant abandoned plant recovery on a case-by-case basis and that Order No. 1000 did not provide a blanket grant of abandoned plant recovery.”
RENO, Nev. — If she had her way, the principal author of the Department of Energy’s August grid study would have written its recommendations a bit differently. And she wouldn’t have attempted to use it as a pretext for price supports for struggling coal and nuclear plants, she said last week.
Alison Silverstein, an independent consultant and former adviser to FERC Chairman Pat Wood III, gave a presentation last week at a joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Board, recommending the protection of wholesale markets and not particular technologies.
She argued that coal units are not good for grid “resilience” and contested their inclusion among so-called “baseload” plants.
“Coal plants that retired recently did not operate as baseload,” she said. “Retired plants were smaller, older, had higher heat rates, and therefore were dispatched less often and ran at lower capacity factors.”
| DOE
The department’s Notice of Proposed Rulemaking to FERC would require RTOs with both energy and capacity markets to compensate generators their full operating costs if they maintain a 90-day supply of on-site fuel.
Silverstein said that most coal plants have on-site inventories of 45 to 70 days, not 90 days as sometimes cited by coal interests.
She recommended that grid planners “identify, define, productize and compensate essential reliability and resilience services to meet multi-hazard threats and scenarios.” She said that “every essential service should be compensated,” but not all should receive market-based compensation, and “some should be conditions of interconnections with value-based compensation.”
She also recommended that renewables and demand response be used for frequency response because they are better at providing those services than conventional generation, if they receive proper incentives.
While the department’s study recommended that FERC consider action similar to the NOPR, the technical portions, of which Silverstein wrote the initial draft, contained little new information or data, citing trends familiar to observers of the markets. Many stakeholders, particularly those in renewable energy, feared that the department would attempt to manipulate the data to support its recommendations. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
Their fears were heightened by the involvement in the study of Travis Fisher, a former FERC economist hired by DOE in January who had written a 2015 report for the conservative Institute for Energy Research that alleged the “single greatest threat to reliable electricity in the U.S. does not come from natural disturbances or human attacks” but federal and state government policies such as renewable subsidies and mandates.
DOE’s ‘Deregulatory Push’
Fisher was also at the conference. He said DOE will soon issue a report on its “deregulatory push” following President Trump’s executive order on reducing regulations. The department is focused on technology and cybersecurity, the latter of which is “a huge issue and a top priority” for Secretary Rick Perry, he said.
He said that the industry needs to work more closely with government, and noted that discussions at the conference had focused on better computer modeling. DOE is doing a lot of work in that area, and “we actually are here to help,” he said.
The meeting also featured a panel on contracting led by Harry Singh, a vice president at Goldman Sachs and chairman of Western Systems Power Pool. What is driving many financial players in the West is “sustainability and renewables” through renewable policies in states such as California, he said.
“Two very exciting things in the West” are the Western Energy Imbalance Market (EIM) and SPP’s move to integrate Mountain West Transmission Group, Singh said. (See SPP, Mountain West Integration Work Goes Public.) Renewable power purchase agreements have expanded in SPP and Texas because of the wind resources there, he said. Singh discussed the impacts of contracting on reliability and other issues surrounding procurement in the West.
California Public Utilities President Michael Picker discussed issues in the state’s electricity planning, and said that by 2022, up to 83% of California load could be served by third-party providers as customers depart for competitive suppliers, community choice aggregators and other programs.
“Essentially, we are seeing deregulation from the bottom up,” Picker said, adding that customer disaggregation is occurring in a number of different forums, “with not necessarily a strategy in mind.” He added that he that “we will have a variety of challenges and “these are things that everybody is going to have to deal with as they see their load disaggregate.”
LITTLE ROCK, Ark. — SPP stakeholders narrowly rejected a Tariff change last week that would have established a 1-MW threshold for reporting behind-the-meter network load, despite having directed a working group to settle the policy debate over the resources’ inclusions and exclusions.
The debate goes on.
“We’ve been working on this for three, four years,” said Southwestern Public Service’s Bill Grant during the Markets and Operations Policy Committee meeting Oct. 17. “If we can’t reach consensus, we should take it to FERC.”
At issue is how members report — or don’t report — the network load, and who has jurisdiction over that reporting.
The Regional Tariff Working Group (RTWG) attempted to settle that issue with a revision request (RTWG-RR241) that expanded the Tariff to govern the inclusion of generation on the load side of a discrete delivery point.
The revision would include in a retail customer’s network load calculation any BTM output at a discrete delivery point and in front of the customer’s meter. The calculation would also include any BTM generator — or combination of generating units — with a nameplate rating greater than 1 MW.
The revision would exclude BTM generation that is used for emergency backup operations and is not synchronized to run in parallel with the grid.
“The way we talked about this years ago, the megawatt exemption would be used and useful behind discrete delivery points, not behind the meter,” said Golden Spread Electric Cooperative’s Mike Wise. “Those of us in the hinterlands end up subsidizing [other entities’ transmission bills] because we don’t have any huge loads. If you’re going to use that [exemption], use the nodal pricing point. It’s really important to have the number of generators out there aggregated up, so you’re not going beyond 1 MW. We believe FERC will see it that way too.”
“If that generation is wholly consumed behind the retail meter, it should not be counted as network load,” said Oklahoma Gas & Electric’s Greg McAuley. “There’s enough diversity in this system where a 1-MW generator or larger somewhere is not going to make that much of a difference. We do not want FERC regulating activity behind the retail meter, period.
“We decided the FERC precedent was pretty clear, that all generation behind a discrete delivery point should be included, but not behind retail meters unless a resource behind that meter is conducting wholesale transactions,” McAuley continued. “We came down on the side that no exclusion [behind wholesale meters] is appropriate, but then this 1-MW behind the retail meter came up.”
OG&E takes the approach that it only reports the generation it owns. The company’s RTO policy director, Jake Langthorn, said the company files an annual report of every megawatt it sells.
“If it’s behind the retail meter, and generated and consumed there, OG&E doesn’t own it,” Langthorn said. “We don’t own it, we’re not going to report it.”
“We’ve been reporting that behind-the-meter generation since Day 1. If I’m reporting the load and you’re not, then that’s a problem for me,” Grant said, offering a different perspective. “You’ve got everyone at the table saying they’re reporting BTMG differently. You can tell this is an issue. I don’t know where to go from here except file a 206 complaint, and that’s a shame.”
The measure failed on a roll call vote, receiving only 54.6% of the votes in favor. When the MOPC in July directed the RTWG to address “inconsistency and uncertainty” over which BTM generation qualifies as network load, it did so by a margin of 0.2%. (See “MOPC Suggests 1-MW Threshold for Network Load,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
OG&E’s David Kays, the RTWG’s chair, shut down a suggestion that RR241 be tabled until the next MOPC meeting. He noted that this was the third time the working group has prepared a revision request, SPP has given its legal opinion, the MOPC has provided direction and the RTWG has codified the language.
“The thing [we’ve] struggled with is that every time we showed up [for a meeting], someone had a different carveout,” he said. “You open it up to a comment period, you’re right back here. I don’t know what 90 days solves.”
After the MOPC meeting, Kays sent an email to MOPC Chair Paul Malone and SPP COO Carl Monroe, the staff secretary, to request a task force be formed to take the next stab at developing a policy that ensures consistency.
Monroe later told the Strategic Planning Committee that staff would draft and share its view of how the issue should be developed.
Stakeholders Try Again with Resource Adequacy Changes
In the wake of FERC’s second rejection of SPP’s proposed resource adequacy requirement (ER17-1098), the working group responsible for the Tariff change will begin the process of drafting a new revision request to address the commission’s denial. (See FERC Again Rejects SPP’s Resource Adequacy Revisions.)
In the meantime, it will be business as usual for the SPP market, according to Municipal Energy Agency of Nebraska’s Brad Hans, chair of the Supply Adequacy Working Group (SAWG). The 10.7% capacity margin, which is equivalent to a 12% planning reserve margin, will remain in effect along with other criteria, and SPP will continue to follow the reporting timeline of the proposed change.
The SAWG plans to bring a new revision request to the RTO’s January leadership meetings. It hopes to make another FERC filing in February.
“It will be a whole new filing,” Monroe said. “We’re trying to work with FERC in order to get these things forward in a way that we will get an approved filing. If we go outside that, we run the risk of getting rejected again.”
FERC said SPP’s proposal was “inadequate,” failed to include a requirement that all power purchase agreements be backed by verifiable capacity to meet the RTO’s resource adequacy requirement (RAR), and omitted provisions to allow the RTO to verify the agreements are backed by capacity.
The commission called SPP’s proposed treatment of firm power purchases and sales in its determination of net peak demand unduly discriminatory, and that it had not supported its proposal to publicly post a list of all load-responsible entities that have not met their RAR.
“The issue is: How do you enforce the [RAR’s] criteria: through a contract enforcement or through a penalty?” said SPP General Counsel Paul Suskie. “The question is how do you enforce it, and that’s at FERC.”
A task force spent more than two years developing the resource adequacy package, which is projected to reduce SPP’s capacity needs by about 900 MW and save members $1.35 billion over 40 years. The board and stakeholders approved the package in January. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)
SPP’s Kelley ‘Undeterred’ by Missouri Projects’ Rejection
Saying he was “undeterred” by FERC’s rejection of a pair of joint projects (ER17-2256, ER17-2257), SPP Director of Interregional Relations David Kelley said he will take another shot at developing an acceptable regional allocation of the projects’ costs.
FERC said SPP’s proposal for regionwide/load-ratio share funding for its portion of two projects with Associated Electric Cooperative Inc. (AECI) and City Utilities of Springfield, Mo., had not shown they were “roughly commensurate with the projects’ benefits.” (See FERC Rejects Cost Allocation for SPP-AECI Seams Project.)
The proposed projects would add a new 345/161-kV transformer at AECI’s Morgan Substation and uprate an existing 161-kV Morgan-to-Brookline transmission line, while also installing a new 345-kV 50-MVAR reactor at City Utilities’ existing Brookline substation. SPP would be responsible for $17.1 million of the projects’ estimated $17.1 million to $18.75 million cost, as the benefits would accrue to the RTO.
“We’ve identified a good project that needs to be constructed. They’re the right projects,” Kelley said. “My goal is to try and bring back another plan of action you guys can consider at the January meeting.”
FERC’s order does not preclude SPP from making additional filings supporting regional funding or proposing a new cost allocation for the projects. Kelley said he will continue conversations with AECI, City Utilities and RTO stakeholders in order to better justify regionwide cost allocation or develop another cost allocation proposal for the projects.
“It’s really a cost allocation issue” on SPP’s side,” Kelley said.
During a separate discussion on proposed adjustments to the 2018 Integrated Transmission Planning Near-Term (ITPNT) assessment, City Utilities’ Jeff Knottek recommended adjusting the scope of the assessment to include the Brookline remedy as a “persistent operational need,” and identify the appropriate solution within the ITPNT portfolio. The motion passed with four abstentions.
The Transmission Working Group in September agreed to rebuild the assessment’s planning models, which will extend the 2018 ITPNT’s completion from April to July 2018.
Separately, the MOPC accepted the Seams Steering Committee’s recommendation of an interregional project with MISO, although the project has since been turned down by the RTO. (See SPP Glum as MISO Axes Last Interregional Project.)
“It takes two to dance, and we don’t have a dance partner,” said American Electric Power’s Jim Jacoby, the SSC Chair. “Without MISO, it’s a dead project.”
Z2 Resettlements Add $6.2M in Net Credits
Staff’s resettlement of Z2 credits for sponsored transmission upgrades has resulted in an additional $5.1 million in total net credits receivable for the March 2008-August 2016 historical period, a 2.5% increase from $203.4 million to $208.5 million.
The September 2016-August 2017 resettlement period resulted in a 1.7% increase, from $64 million to $65.1 million.
The resettlements were necessary because of billing disputes, “minor” software defects and problems in calculating the present value of creditable balances, staff told members in July. (See “More Z2 Woes; SPP to Resettle 9 Years of Data,” SPP Markets and Operations Policy Committee Briefs: July 11-12, 2017.)
Members will only be charged or credited the difference between the resettlements and the initial settlement of the Z2 crediting process.
Individual company results were posted on Oct. 13. Staff said 16 quarterly installments remain on payment plans, with the next invoices going out Nov. 3. Those invoices will include the resettlement net amounts.
Registered Entities Transitioning from SPP RE
SPP Regional Entity President Ron Ciesiel reminded members that applications to join new REs are due at NERC by Oct. 31. As of Oct. 17, he said, the commission had received only 40 applications.
The SPP RE announced its dissolution in July, addressing FERC and NERC concerns over its reliability oversight role. (See SPP to Dissolve Regional Entity.)
That move forced the SPP RE’s 120 registered entities to transition to others, a process NERC is managing. Entities should pick a new RE by Dec. 31, 2018, though Ciesiel hopes to complete the process next summer.
“Every entity should have been contacted by NERC multiple times,” Ciesiel told members.
He reminded members that the SPP RE is still the compliance and enforcement authority for its registered entities. “We’re in business as usual,” he said.
SPP has joined ReliabilityFirst but will also have to register in other REs where it does business.
Generator-Interconnection Task Force Extended for 1 Year
Members approved the Generator Interconnection Improvement Task Force’s (GIITF) request to spend an additional year developing a three-stage study process that would replace SPP’s current process built around feasibility studies, preliminary and then definitive interconnection system impact studies, and facility studies with multiple entry points.
The group is proposing stages devoted to thermal and voltage analysis, stability analysis and a facilities study. The task force’s chair, Sunflower Electric’s Al Tamimi, said the simplified process would be easier for SPP to administer and simpler for customers to understand and navigate.
Tamimi said by tying financial security to upgrade cost allocation, the proposal would encourage customers to weigh the risks of proceeding at an earlier stage and reduce the number of interconnection requests being withdrawn late in the process.
The GIITF also requested a stakeholder group with “appropriate background and expertise” be tasked with re-evaluating the purpose, scope and study requirements of network resource interconnection service to align it more closely with SPP’s current and future market structure. MOPC Chair Malone said he would work with staff to put together a task force.
The MOPC also approved the group’s recommendation to publish study models earlier in the process and eliminate the “standalone” analysis to reduce study costs and improve timeliness. SPP’s Tariff requires each interconnection request be evaluated as if it is the only request in the queue, although binding results are based on cluster evaluations.
The MOPC said goodbye to two veteran representatives: Vice Chair Todd Fridley, who is retiring from Transource Energy but will begin a new career with Public Service Company of New Mexico, and OG&E’s Langthorn, who is retiring at the end of the year.
“I remember when [SPP CEO] Nick Brown was a staff engineer,” Fridley said in thanking the committee and SPP for their support. “That’s how far back I go.”
Langthorn said that while he is ready for retirement, he has always enjoyed his work.
“This is the middle of the country. This is the heart of the country,” he said, referring to SPP’s flyover country footprint. “We really make a difference for people.”
MOPC Clears 8 Revision Requests
The MOPC approved a measure targeting potential gaming related to the regulation deployment adjustment settlements charge type. The revision (MWG-RR243) minimizes credits and maximizes charges related to the charge type, using the lesser of the as-dispatched energy offer curve and mitigated energy offer curve for the regulation-up adjustment, and the greater of the as-dispatched offer curve and mitigated energy offer curve for the regulation-down adjustment.
Keith Collins, executive director of SPP’s Market Monitoring Unit, recommended the change, saying manipulation of regulation-down offers has cost the market more than $1 million in recent years. He said that combined with MWG-RR242, which was on the consent agenda, the change addresses the MMU’s gaming concerns.
The MOPC passed two other Market Working Group revision requests, with a total of five abstentions:
MWG-RR231: Removes locally committed resources from the economic mitigation tests and creates a 10% cap for resources committed for local reliability. Addresses the practice among some resources of “self-mitigating” to pass the conduct threshold test and avoid possible mitigation with by submitting competitive energy offers 10% above the mitigated offer.
MWG-RR239: Allows market participants to incorporate fuel cost uncertainty into their mitigated offers, recovering the difference between forecasted and actual costs.
Members also unanimously approved five RRs on its consent agenda:
MWG-RR235: Corrects RR200, which removed bilateral settlement schedules (BSSs) at hubs and generation settlement locations from the over-collected losses (OCL) distribution calculation. The RR modifies two equations in RR200 to accurately reflect its true intent.
MWG-RR236: Changes the commercial model implementation from a bimonthly process to monthly. Previously implemented on only even-numbered months (February, April, etc.), the process hindered market participants with contracts becoming effective at the beginning of the year from submitting model updates on the remaining odd-numbered months.
MWG-RR242: Adds a fourth criterion, based on a resource’s cleared energy offer, for prioritizing the order in which they are deployed for regulation-up and regulation-down and addressing a potential gaming opportunity. The higher the offer, the less likely a resource will be deployed for regulation-up, and the lower the offer, the less likely it will be deployed for regulation-down.
RTWG-RR238: Addresses the financial exposure to SPP and its market participants stemming from a defaulting transmission customer avoiding responsibility for the full amount owed for the full term of a service agreement. The change also restricts the ability of SPP, transmission owners and transmission customers from recovering attorney’s fees related to performance of a service agreement, and clarifies that each party to an arbitration under the Tariff is responsible for its own fees.
RTWG-RR244: Eliminates credits from new upgrades that do not add transfer capability under Tariff Attachment Z2, and eliminates credits from short-term service under the same attachment, as recommended by the Z2 Task Force. (See “Z2, Two Other Task Forces Expire,” SPP Board of Directors/Members Committee Briefs: July 25, 2017.)
DENVER — SPP and Mountain West Transmission Group representatives worked hard Friday to allay concerns of Colorado regulators who fear they could lose some jurisdictional authority over Mountain West members should the group eventually join the RTO.
The chief argument to sway regulators to support membership? The effectiveness of SPP’s multistate Regional State Committee, which has primary responsibility for cost allocation, financial transmission rights, resource adequacy and remote resources planning within the RTO’s current 14-state footprint.
Sensing apprehension on the part of some Colorado Public Utilities Commissioners, Sam Loudenslager, SPP’s principal regulatory analyst, encouraged the commissioners to join the RSC.
“In my experience, the more participation by [regulatory] staff, the more value they see by participating in the RSC,” he said. “Other states will make decisions that affect you if you’re not at the table.”
Commissioner Wendy Moser asked if that meant out-of-state regulators would be making decisions that would affect Colorado. She also expressed concerns that the PUC’s RSC membership might violate the state’s open meeting laws.
“The [RSC] will not trump [your jurisdiction],” Loudenslager responded. “I’m saying decisions will be made that affect your region, outside the boundaries of Colorado, whether you’re there or not.”
The information session, focused on transmission, governance and regulatory filings, was the third held by the Colorado PUC. The commission has jurisdictional authority over Xcel Energy’s Public Service Company of Colorado (PSCo) and Black Hills Energy, two of the eight Mountain West members seeking to join SPP.
A Separate SPP?
But Mountain West is already asking SPP to make a series of concessions that would preserve consensus decisions its members have already made.
First, the group wants the RTO to expand the RSC to include a group consisting of just the Western states, resulting in a single committee with two regional divisions. The west side of the RSC would provide guidance on regional planning, cost allocation design, congestion cost hedging and resource adequacy.
Second, Mountain West has requested that SPP perform a loss-of-load-expectation (LOLE) analysis for its footprint, which could potentially be used to support establishing a Western regional resource adequacy requirement.
The group has also proposed a Westside Transmission Owners Committee (WestTOC) that would have decision-making authority over cost allocation, zonal changes and transmission revenue requirements.
“I know it sounds like, ‘Geez, you’re just trying to set up a separate RTO in the West and functionally run it differently,’” said Kenna Hagan, Black Hills’ senior manager of planning, policy and strategy. “We’re only asking to change a small percentage of the governing documents. … We would be adopting the majority of everything SPP has.”
Carrie Simpson, Xcel’s senior manager of market operations, said the WestTOC is necessary to protect decisions the members have made over the past four years to eliminate pancake rates and improve their service. Joining an RTO was one of those decisions. (See SPP, Mountain West Integration Work Goes Public.)
“SPP has a member-driven process, and we want to use as much of that as we can, but there are certain things we’ve identified to modify, in order to move forward,” Simpson said, referring to cost allocation and transmission planning. “These are issues we’ve negotiated that we need to preserve in order to make this work.”
Hagan, who said during an Oct. 16 meeting before SPP members in Little Rock that it’s not “all or nothing,” said the WestTOC would allow Western transmission owners to make decisions collectively, “not as individuals with competing interests.”
“We’ve worked so hard to get here, we want to continue going forward,” Hagan said.
Tri-State Generation & Transmission’s Chris Pink told the commissioners that Mountain West is also proposing the creation of separate FERC Order 1000 planning regions that will work with other planning regions in the Eastern and Western Interconnections. The discrete grouping will preserve the importance of local planning and involvement in the Colorado Coordinating Planning Group, he said.
“There will be a regional evaluation of local projects under SPP, but that doesn’t mean the authority of Mountain West owners, stakeholders and other groups collaborating in the planning process goes away,” Pink said. “This will make the process even better.”
“We’re trying to optimize the region for how the system would operate in the market, which would be a single region too,” said Antoine Lucas, SPP’s director of transmission planning. “We would be using the same model sets, the same future assumptions … but outside the East and West, we would be conducting interregional planning with those areas contiguous to us.”
Pink said SPP’s uniform interconnection process will provide one evident change for independent power producers. Within the Mountain West, IPPs follow different processes to connect generation to the grid.
“Under SPP, [the interconnection process] will be same and it will be consistent. I view this as a benefit,” he said. “The key is that there is going to have to be some sort of a transition. How that transition occurs still has to be worked out.”
PUC Chair Jeff Ackermann asked whether there would be a systemwide cost allocation once transmission planning has been completed and projects built.
“No one has a crystal ball for how the system will operate in the future,” said Black Hills’ Dan Kline. “There have been plans, theories and ideas about this super-voltage overlay that could eventually break down the need for DC ties in the middle of the country. Certainly, should the system develop to the point where the DC ties are no longer needed, that would be something we would want to take a look at.”
Cultural Fit
Kline told Ackermann that Mountain West selected SPP as its potential RTO because of the “broad-based discussion and negotiation” among participants.
“Everyone had a different thought as to what the best solution was,” Kline said. “Ultimately, the additional benefits SPP brought to the table with respect to the dispatch across DC ties, [and] their overall culture of responsiveness and collaboration” helped Mountain West members make their choice, Kline said.
“Each company had its own evaluation,” said Xcel’s Joe Taylor, one of the primary leads in Mountain West’s integration efforts. “We got together and said, ‘Who could we reach consensus around?’ SPP was the entity the 10 companies could go forward with.”
SPP Vice President of Engineering Lanny Nickell later told RTO Insider that Kline and Taylor’s comments made him feel proud.
“Our culture is something we have worked hard with our members to develop. We haven’t done it alone,” he said. “It’s something that sets us apart from other RTOs. What we do is not that different from other RTOs, but how we do it is.”
SPP expects to file Tariff revisions with FERC that incorporate changes to the governing documents following RTO board approval, which could come next summer. FERC’s review is expected to take 60-180 days.
Xcel and Black Hills are planning ask the Colorado PUC to approve their integration into SPP and put in place cost-recovery rate mechanisms. The companies will file separately but are flexible about timing their filings with SPP’s FERC filing or 60 days later, allowing for any “deficiencies” to be addressed.
SPP has added a section to its website devoted to Mountain West’s integration to help stakeholders and others keep up with developments.
“I feel like I’m in Niagara Falls drowning,” said Commissioner Frances Koncilja, who facilitated the session.
Koncilja said the PUC will schedule at least three more information sessions, with the hope of getting a FERC commissioner to attend one of them. Later sessions will be devoted to a cost-benefit analysis of integration and Colorado-specific issues.
FERC received more than 300 comments on Energy Secretary Rick Perry’s proposed “resiliency” rulemaking by its Monday deadline, with coal and nuclear interests backing the idea and RTO officials and most other stakeholders roundly rejecting it (RM18-1).
The flood of comments was so heavy that it taxed FERC’s filing system, causing the commission to announce late in the afternoon it would accept comments into Tuesday.
Perry’s Notice of Proposed Rulemaking would require FERC-jurisdictional RTOs and ISOs with capacity markets and day-ahead and real-time energy markets to ensure “full cost recovery” for any generation that can provide “essential energy and ancillary services” and has 90 days of fuel supply on site. Units subject to cost-of-service rate regulation would be excluded.
In its request for comments on the NOPR, FERC asked stakeholders to weigh in on more than 30 questions. Few commenters bothered. But they were effusive in their support — and withering in their criticism.
Those that depend on coal and nuclear generation, including labor unions, shippers and mining companies, heartily endorsed it.
The rule “will produce numerous benefits for all Americans by preserving the continuing viability of critical coal-fired power plants,” said the Kentucky Coal Association (KCA), which represents 120 companies in the No. 4 coal-producing state. “This will not only support a more reliable and resilient power grid but will also have a profound and positive impact in Kentucky and across America by preserving jobs and economic development.”
The Nuclear Energy Institute embraced the cost-of-service compensation as a temporary measure “at least until other market structures are put in place that appropriately value the resiliency attributes that nuclear generation units provide.”
The natural gas, solar and wind industries joined with the Electric Power Supply Association and other industry groups to blast the proposal as “a transparent attempt to prop up uneconomic generation … that is not otherwise needed for reliability.”
RTO officials and their Market Monitors uniformly rejected the idea, with the ISO/RTO Council saying “the negative consequences of the NOPR … are obvious.” PJM, ISO-NE and NYISO also filed their own comments in opposition. (See related story, RTOs Reject NOPR; Say Fuel Risks Exaggerated.)
A bipartisan group of eight former FERC commissioners also blasted the proposal as a repudiation of 25 years of progress toward competitive markets.
Amory Lovins, cofounder of the Rocky Mountain Institute, derided Perry’s proposal as employing “language urgent without evidence, alarmist without cause, and peremptory without authority.”
Given the widespread opposition from all but the coal and nuclear industry — and the myriad questions about how the proposal would be implemented — it appears highly unlikely the commission will act to approve it on the accelerated schedule Perry had demanded, or that it would survive the almost certain legal challenges if it did so.
Perry directed FERC to complete a final rule within 60 days after publication of the NOPR in the Federal Register. The commission, an independent agency, is not required to approve the plan or follow his timeline. (See FERC’s Independence to be Tested by DOE NOPR.)
Below, based on a review of more than 50 comments as of press time, is a summary of the feedback FERC received. Reply comments are due Nov. 7.
Is the Grid at Risk?
Perry said the rule was needed to ensure sufficient supplies of “essential reliability services,” which NERC has defined as including voltage support, frequency services, operating reserves and reactive power. Just and reasonable rates for such generators would cover “its fully allocated costs and a fair return on equity,” including operating and fuel expenses and the costs of capital and debt, the NOPR said.
KCA cited “the clear findings in the proposed rule that the nation’s grid is at risk and that rule-secure resources are indispensable.”
“The commission simply cannot carry out its mission without adopting rules that appropriately value fuel-secure generating facilities that are capable of producing electricity when fuel supplies are interrupted or unavailable,” it said.
The Utility Workers Union of America (UWUA) cited a PJM analysis that it said concluded that “even moderate retirements” of coal and nuclear plants “would reduce PJM’s fuel assurance capability by almost 30% if the units were replaced by natural gas.”
“The country is at a crossroads, and urgent commission action is required before the value provided by critical baseload generation capacity is lost forever,” the American Coalition for Clean Coal Electricity (ACCCE) and the National Mining Association said in a joint 64-page filing.
“We should not allow short-term prices to dictate significant changes in our generation fleet that will reduce the nation’s resource diversity and grid resiliency,” argued NEI, which said nuclear generation units have the highest capacity factors of all generating resource types. “Because of these attributes, nuclear power plants provide reliable baseload generation that stabilizes the grid and moderates price volatility.”
The EPSA filing countered by citing a Rhodium Group analysis that concluded “0.00007% of customer-hours lost to outages were caused by fuel supply emergencies between 2012-2016, a period when 32% of the country’s coal fired power units and 6% of its nuclear generating units were retired. The same period also featured two of the coldest winters during the past 30 years in the Eastern United States, including the 2014 polar vortex.
“The vast majority of electric service disruptions in the United States are related to distribution or transmission outages, not unscheduled generation outages,” they continued. “And virtually all of the customer-hours that were lost due to fuel supply disruption between 2012-2016 were related to a single incident involving one coal plant in Northern Minnesota.”
David Patton, whose company performs market monitoring in MISO, NYISO and ISO-NE, acknowledged “there may be fuel supply contingencies or other contingencies that have not been fully considered by RTO planners or [NERC].” But he said, “To turn immediately to an out-of-market compensation scheme without considering the alternatives for addressing these issues through the RTO planning and market framework is both inefficient and ultimately unreasonable.”
Will the Proposal Help Resiliency/Reliability?
Many commenters said the proposal would harm rather than help reliability.
“The NOPR proposal would provide compensation to particular units that may otherwise retire because they are older, less efficient and less reliable than newer units,” the IRC said. “Supplanting newer, efficient units with older, less reliable ones in the markets will threaten reliability and market efficiency. This problem will be exacerbated because the NOPR does not outline any minimum performance standards or criteria for determining whether eligible resources are situated in an optimal location to support future reliability needs (including, particularly local reliability and voltage needs).”
| FERC
Due to rule changes implemented since the 2014 polar vortex, the council said, “ISO-NE, NYISO and PJM have ably maintained reliability in their respective regions.”
Longview Power, operator of a five-year-old, 700-MW supercritical coal-fired plant near Morgantown, W.Va., which claims to be “North America’s most efficient coal fired generator,” said it has been undercompensated in the PJM market.
CEO Jeffery L. Keffer said the plant — which has a heat rate of 8,842 Btu/kWh, a 92% availability factor and emissions at least 70% lower than the U.S. coal fleet — is dispatched by PJM as a baseload unit whenever it is available and been awarded capacity payments through the 2020/21 delivery year. It also receives payments for reactive power and other ancillary services.
“However, the compensation paid to Longview for its reliability contributions and ancillary services is wholly inadequate. During 2016, when Longview’s equivalent availability factor was over 92%, it received an average energy payment of only $27.50/MWh. Similarly, the 2017 average energy price paid to Longview is expected to be $28.63/MWh.”
Patton said, however, that the proposal to guarantee full cost recovery of resources “that may be economic to retire will likely generate costs that vastly exceed any reasonable estimate of” the value of lost load. He questioned the notion that coal units were being forced into “early” retirement, noting that the average age of existing coal-fired plants in 2016 was 38 years, within the 35-50-year life span for those assets.
Impact on Wholesale Markets
Critics said Perry’s call for “full cost recovery” for coal and nuclear units would reverse 25 years of competitive wholesale markets.
The R Street Institute, which promote free markets and limited government, praised the NOPR’s call for market improvements such as improving pricing for reliability and resiliency services. “But the detailed problem statement, factual foundation and proposed policy remedies of the NOPR are inconsistent with empirical evidence and principles of wholesale electricity market design,” said Devin Hartman, electricity policy manager. “Motivations for market reforms should never aim to adjust compensation with a predetermined result — in this case preventing certain power plants from retiring. The rationale for markets is to let competitive forces determine resource allocations, which lowers costs and better manages risk than a pre-determined, centrally planned approach would.”
“Proper valuation of coal baseload generation does not require the commission to abandon or ‘blow up’ the competitive electric markets,” KCA insisted. “KCA and other supporters of a resilient grid and affordable baseload power are simply requesting that the commission ensure that competitive market based rules fairly compensate the benefits of baseload generation sources, which are the most cost-effective way to meet constant electrical demand so as to provide for just and reasonable rates to consumers and generators.”
“Valuing coal and nuclear [electric generating unit] resiliency benefits is consistent with market evolution,” wrote UWUA President D. Michael Langford. “Electricity market constructs can be modified — as they are so frequently to accommodate a variety of purposes — to efficiently operate while compensating for reliability services.”
A bipartisan group of eight former FERC commissioners — including former Chairs Elizabeth Anne (Betsy) Moler, James Hoecker, Pat Wood III, Joseph T. Kelliher and Jon Wellinghoff — filed joint comments saying that Perry’s proposal would be “a significant step backward from the commission’s long and bipartisan evolution to transparent, open, competitive wholesale markets.”
“The commission’s adoption of the published proposal would instead disrupt decades of substantial investment made in the modern electric power system, raise costs for customers and do so in a manner directly counter to the commission’s long experience,” they said.
The former commissioners noted their role in issuing Order 888, which established transmission open access, and Order 2000, which defined the responsibilities of RTOs, saying their “shared collaborative mission across party lines and presidential administrations has been a model of good government.” More than two-thirds of U.S. electric customers are now served by competitive wholesale markets.
“Widely diverse interests have invested tens of billions of dollars in both competitive and regulated infrastructure. Customers and the industry have benefited from lower costs and better, more reliable services. Technological innovation has swept the entire value chain.”
They acknowledged that the markets have been impacted by federal tax subsidies for wind and solar generation, as well as “less overt benefits for oil, gas and coal extraction.”
“The commission cannot ignore these interventions, and in fact, should actively inform legislators how such programs impact market operations. But one step the commission has never taken is to create or authorize on its own the kind of subsidy proposed here.”
The IRC said Perry’s proposed cost recovery “stands in stark contrast to other types of narrowly tailored cost recovery mechanisms like reliability-must-run (RMR) mechanisms.”
“The negative consequences of the NOPR proposal are obvious. By affording certain generators guaranteed, full fixed and variable cost recovery for providing some undefined ‘resiliency’ benefit based on an arbitrary ‘fuel-security’ standard, the NOPR will shield eligible generators from the competitive forces that discipline market bidding behavior and ensure that market dispatch and prices are based on least-cost, security-constrained optimization of the resource portfolio.”
Legal Questions
The Harvard Environmental Policy Initiative and Columbia University’s Sabin Center for Climate Change Law said the NOPR is flawed because it doesn’t prove the preliminary conclusion required by the Federal Power Act that current wholesale rates are not just and reasonable.
“This glaring omission dooms DOE’s proposal under Section 206 of the Federal Power Act and allows the commission to issue a swift rejection without weighing in on the merits,” Harvard’s Ari Peskoe wrote. “The NOPR’s observation that wholesale markets do not price ‘resiliency’ does not substitute for an explicit proposed finding that current rates are unjust and unreasonable. DOE does not define ‘resiliency,’ nor has the commission ever used that word in connection with wholesale rates. DOE’s bare assertion that rates do not account for undefined attributes does not provide adequate notice necessary for meaningful public comments.”
Justin Gundlach, staff attorney for the Sabin Center, agreed. “The commission should recognize [the proposal] as a politically motivated gambit to allocate resources to the support of coal- and nuclear-fired generating capacity,” he said.
The IRC said the proposed requirement that RTOs submit compliance 15 days after the effective date of the final rule — 45 days after the rule is published — “is unreasonable and contrary both to commission policy and past practices.”
The IRC said “the NOPR proposes a drastic redesign of existing competitive market structures but provides very little implementation details and no discussion about acceptable cost allocation for the proposal. Given the dearth of specificity in the NOPR, parties will be left guessing as to what might be an acceptable compliance proposal until such time as the final rule is issued. Giving only 45 days from that point will deny RTOs and ISOs adequate time to craft compliant policies and develop tariff revisions. Equally significantly, a 45-day window from issuance of the final rule to submission of compliance filings provides very little time for RTOs and ISOs to initiate stakeholder discussions, let alone time for the RTOs and ISOs to consider what are very likely to be highly disparate stakeholder views on the RTO/ISO’s compliance proposal.”
ACCCE and NMA asked FERC to find existing RTO tariffs unjust and unreasonable. “It is critical that the commission make such a finding, and direct RTOs and ISOs to modify their tariffs to ensure that existing coal-fired generators are able to fully recover their operating costs,” they said.
The EPSA group filing said the proposal would “provide discriminatory compensation” to coal and nuclear generators. “The justification for the proposed payments – resiliency – is not well defined, nor does the DOE NOPR demonstrate that resiliency is lacking in the aforementioned regions,” they said.
It was filed by 20 stakeholders, including the Advanced Energy Economy and trade groups representing competing fuels and alternate resources (American Biogas Council, American Council on Renewable Energy, American Forest & Paper Association, American Petroleum Institute, American Wind Energy Association, Energy Storage Association, Natural Gas Supply Association and the Solar Energy Industries Association).
“This is what a very bad proposal can do,” tweeted EPSA Senior Vice President Nancy Bagot. “Bring people together to save the electricity market!”
90-Day Fuel Supply
| Worldcoal.org
DOE would require a generator receiving “resilience” payments to have a 90-day fuel supply “enabling it to operate during an emergency, extreme weather conditions, or a natural or man-made disaster.”
But commenters said the requirement is arbitrary.
Longview said it keeps 10 to 30 days of coal on hand. “Whether dealing with an extreme weather event, such as a ‘polar vortex’ or a terrorist attack, we see the likelihood of the event extending for 90 days as highly unlikely and particularly unprecedented. An event of this length would likely involve serious damage to the transmission grid, which means electric deliverability, not fuel supply, would be the limiting factor in supplying electricity to end users.”
Monitor Patton said the 90-day supply requirement was indefensible, saying he is unaware of any credible contingency that would support the requirement. “Major pipeline repairs have generally been completed within a few weeks; extreme weather conditions typically last from three to 10 days. … On-site fuel supplies of oil or LNG can often be resupplied within a few weeks,” he said. “To the extent MISO has had long-duration fuel-security issues, the issues have been with coal supply limitations due to railway congestion. … Not one of [the large-scale outages since 1965] was impacted by lack of long-term fuel security.”
Patton also dismissed the NOPR’s effort to tie its concern to “the devastation from Superstorm Sandy and Hurricanes Harvey, Irma and Maria.”
“In general, hurricanes are more likely to damage distribution and transmission systems and cause flooding at power stations, impacting resource types in specific locations rather than certain fuel types,” he said. “In other words, these contingencies will generally affect all resources is certain areas, regardless of fuel type, even the resources that qualify as resilience resources under the NOPR.”
Industry Groups’ Response
The Natural Gas Supply Association said there is “no basis” for the NOPR and its proposed solutions. It said “no fuel source is failsafe,” and that natural gas is a “reliability asset for the power sector,” saying interstate pipelines delivered 99.79% of firm contractual commitments over the last 10 years.
Natural gas pipeline | Ohio Power Siting Board
WIRES, a transmission trade group, said it would oppose any FERC action that “retreats from the market-oriented and technology-neutral regulatory policies that the commission has fostered for a quarter century [or] fails to fully acknowledge the central role that development of robust electric transmission infrastructure must also play in any effort to make the grid more reliable and resilient.”
The Edison Electric Institute asked FERC to clarify whether the rule changes would include only the Eastern RTOs or also CAISO and SPP, which have no capacity markets.
It said the commission “should institute an appropriate process to investigate potential issues related to resilience”
and direct the Eastern RTOs “to evaluate what, if any, steps need to be taken within their markets to define the specific resource attributes and essential reliability services that may need to be valued in their market(s) and whether alternate compensation mechanisms are needed consistent with the market structure in the region.”
Independent power producers were uniformly opposed, with filings by the New England Power Generators Association (NEPGA), the Independent Power Producers Of New York (IPPNY), PJM Public Power Providers and the Independent Power Producers of Ohio, Pennsylvania and West Virginia.
“New England and New York have long histories of developing market mechanisms to meet reliability,” NEPGA and IPPNY said in joint comments.
“PJM has demonstrated that it will make modifications to the market design to address changing reliability needs of customers,” said the IPPs from Pennsylvania, Ohio and West Virginia, citing the Capacity Performance rules enacted after the 2014 polar vortex. “In a perverse irony, the NOPR will likely harm grid reliability by chasing away the very innovation and investment in new generation needed to maintain the long-term integrity of the grid.”
Customers’ Response
The Industrial Energy Consumers of America said the proposal would raise costs for electric-intensive manufacturers, estimating a 1-cent increase in industrial electricity rates would increase its members’ costs by $9 billion to $10 billion annually. “As a large stakeholder who consumes 26% of U.S. electricity and spends approximately $65 billion on electricity each year, the manufacturing sector is very concerned about this rule,” said IECA President Paul Cicio.
In a joint filing, the Industrial Energy Consumers of Pennsylvania and the Pennsylvania Manufacturers Association
said the rule “threatens to dramatically change the economic climate in Pennsylvania by increasing electric prices and undermining the numerous and relatively recent benefits being generated by the booming and prospering Pennsylvania shale gas industry.”
The group noted that Pennsylvania consumers paid more than $12 billion in stranded costs to utilities in its transition to competition. “For many years after the legislation, the wholesale market prices were higher than those that the utilities used to calculate their stranded cost claims. The generation owners kept those additional profits.”
The Kentucky Industrial Utility Customers took no position on whether the proposal should be adopted, but said if it is, FERC should consider a separate capacity market for grid reliability and resiliency resources. It also said the authorized return on equity “should be the minimum necessary to ensure that the fuel-secure generation does not retire prematurely. An ROE in the 2 to 4% range would accomplish that. Any positive return is better than losing money. If the ROE is set too high, then the affected merchant generators would have reduced incentive to seek a more permanent market-based solution.”
Rule Defenders’ Script
Coal state politicians, such as Republican Sen. Shelley Moore Capito and fellow members of the West Virginia congressional delegation, weighed in with support.
The proposal also found some unlikely defenders, such as the Cleveland branch of the NAACP, which said “the continued operation of the baseload coal and nuclear power plants translates into safer and more prosperous communities.”
Several of the coal industry interests — including Camelot Coal, FreightCar America, Campbell Transportation and IBEW Local 50 — included identical language in their comments: “The preservation of certain plants will avoid the need to replace lost generation with imports and the associated construction of infrastructure to facilitate such importation. … Premature plant closures will deplete the stable of highly skilled (and specifically trained and experienced) employees, many of whom have lived in the region for several years and who take great pride in their work. … The baseload generation facilities that may be retired prematurely offer stability and optionality.”
Avon Lake power plant
Many of them raised the threat of layoffs and lost tax revenue from plant closures.
The Utility Workers Union of America, which represents 50,000 electric, gas, water and nuclear industry workers nationwide, focused on the potential impact in Avon Lake, Ohio, where it said closure of a coal plant would result in reduced income and property taxes. A city councilman told Congress in 2012 that the plant’s closure would force a 50% cut in the city’s emergency medical service operating budget and a $4 million cut — 11% — for the local school district, forcing it to cut programs for special needs students.
Michael Kuser, Amanda Durish Cook, Tom Kleckner, Jason Fordney and Rory D. Sweeney contributed to this article.
By Michael Kuser, Tom Kleckner, Rory D. Sweeney, Amanda Durish Cook
RTO officials and their Market Monitors on Monday unilaterally rejected Energy Secretary Rick Perry’s proposal to provide price supports to coal and nuclear plants, calling it expensive, inefficient and counterproductive.
The ISO/RTO Council (IRC) led the opposition, with CAISO, PJM, MISO, ISO-NE and NYISO also filing comments in opposition. Also filing statements opposing the proposal were PJM Market Monitor Joe Bowring; David Patton, Market Monitor for MISO, NYISO and ISO-NE; and Keith Collins, head of SPP’s Market Monitoring Unit.
In a joint filing supporting the rule, the American Coalition for Clean Coal Electricity (ACCCE) and the National Mining Association criticized the RTOs for failing to address trends threatening coal and nuclear generators. (See related story, FERC Flooded with Comments on DOE NOPR.)
They said NERC’s and RTOs’ “confidence in the current state of electric reliability … are based, in large measure, on existing conditions and short-term forecasts, largely ignoring the trend toward premature retirements of baseload coal-fired generating capacity currently available to address reliability and resiliency needs.”
The coal groups acknowledged that some RTOs “have tried to explore measures intended to maintain traditional baseload capacity in the market, and have even taken some halting and less-than-full steps in that direction, a tacit recognition that existing market rules and structures are not properly valuing the reliability, resiliency and long-term price stability benefits that traditional baseload capacity provides.”
But it said “the few revisions to existing RTO/ISO tariffs and related market structures and rules have so far been much too little and far too late. Without action by the commission to remedy these tariffs and market structures, the electric system will devolve to lose the value of fuel diversity and end up overwhelmingly dependent on intermittent renewable and natural gas generation.”
Patton recommendedFERC define the contingencies the Department of Energy seeks to address. “Without first identifying in detail the contingencies and associated reliability risks to the system, there is no way to quantify a resilience requirement,” he said.
He said MISO and ISO-NE have already conducted fuel-security studies.
“MISO’s evaluations of the adequacy of the gas pipeline infrastructure found the MISO North and Central regions to be ‘favorably located at the crossroads of pipeline corridors extending from many supply basins … with more than 20 interstate pipelines and significant gas storage resources.’ Hence, MISO’s potential exposure to natural gas supply contingencies is relatively low, and the need for the payments called for under the [Notice of Proposed Rulemaking] is similarly low.”
Patton acknowledged New York and New England are more vulnerable to natural gas system contingencies than MISO. But, he said, “it is highly unlikely that the proposal in the NOPR is a feasible or reasonable means to address these vulnerabilities,” saying dual-fuel capability “has been the most effective and cost-effective means” to address them.
“This illustrates the problems that arise when one starts with a very specific answer, rather than starting with a clearly defined issue or objective and allowing the markets to provide the most efficient answer,” he said.
ISO-NE
ISO-NE found fault with what it called the NOPR’s “one-size-fits-all” approach to the region’s risks and said its stakeholder processes were preferable to the NOPR to “develop market-based solutions, if any are needed.”
“The NOPR does not address these risks, and ISO-NE proposes to instead use the time the region has in 2018 and beyond to quantify its fuel-security risks,” the RTO said.
The grid operator said the NOPR would “significantly undermine the efficient and effective wholesale electricity markets,” and that moreover, “New England has no urgent need to rush to a solution, given that the three-year Forward Capacity Market has ensured resource adequacy until at least 2021, and the region has already taken steps to improve operating procedures and generator incentives to secure firm fuel supplies.”
Commenting on the proposed rule’s estimated burden of $291,042 per respondent RTO/ISO to develop and implement new market rules as proposed, including potential software upgrades, ISO-NE said such efforts would “be in the millions of dollars for each RTO.”
The NOPR would undermine New England’s wholesale electricity markets in two ways, the RTO said: “First, these resources may have no incentive to bid their appropriate fuel and operating costs in the energy market … [and] could profitably bid zero. While there are admittedly few coal resources remaining in the region, if these costly units bid zero, it will undermine price formation in the day-ahead and real-time energy market and increase emissions.”
Second, the RTO said, its FCM enables resources to offer to retire if the market does not clear at or above a specific price: “Normally, as units age and their costs rise, new resources will be more economic than retaining aging units that require a higher price. With full cost recovery guaranteed, however, these aging resources will remain, deterring the development of newer, more efficient and more cost-effective generating units.”
ISO-NE also said it has developed new operating procedures to improve information on generator availability during cold weather conditions, such as requiring generators to report their anticipated availability to the grid, including details on their ability to procure fuel.
The RTO said it also has increased market-side efficiency and improved gas-electric coordination to mitigate the supply problems arising from natural gas pipeline constraints.
“For example, the ISO has shifted the day-ahead energy market timeline to better align the electricity and natural gas markets to give generators more time to procure the gas they need to run,” it said.
NYISO
NYISO asked FERC not to adopt the proposal but said if it deemed action necessary, it should give the RTOs at least 180 days from the effective date of any final rule to submit compliance filings.
“[The] deadlines are simply not realistic and attempting to impose them would not be reasoned decision-making,” the ISO said. “The NOPR’s approach would distort, if not destroy, wholesale market signals needed to attract and retain resources required for reliability.”
The ISO called the proposed grid resiliency pricing rule “flawed” for being premised on inaccurate assumptions and statements as they relate to New York.
“The NOPR does not establish that its proposal is appropriate or that ‘grid resiliency’ issues should be addressed the same way in different regions,” said the filing, adding that the grid operator “is not aware of any imminent emergency likely to develop on the wholesale electric system that necessitates drastic and immediate action.”
All resource adequacy criteria have been satisfied in New York and are expected to continue to be satisfied for the foreseeable future, said the ISO. For example, on Jan. 7, 2014, New York set a new record winter peak load of 25,738 MW during the polar vortex, and “NYISO met all reliability criteria and reserves requirements without activating emergency procedures at any time during the winter operating period. It did so despite significant generator capacity derates on some of the coldest days, including generation resources that would appear to qualify under the NOPR as ‘eligible grid and reliability resources.’”
The ISO said it has made improvements to its energy and ancillary service markets and incorporated features into its capacity market rules “that reflect the importance of resiliency to withstand severe weather events,” including basing the downstate installed capacity demand curves on peaking plant designs that include dual-fuel capability.
PJM
PJM agrees there is an issue with maintaining reliability, but not the one suggested by the department.
“The DOE didn’t exactly get it right in the way it attempted to articulate the problem,” Stu Bresler, PJM senior vice president of operations and markets, said Thursday.
During a special conference call to preview the RTO’s plan for responding to FERC’s request for comments on the NOPR, Bresler said that the real issue is energy price formation. PJM has been working on that topic for more than a year to respond to concerns over public-policy initiatives impacting market prices.
CEO Andy Ott made similar observations during a media call on Monday, calling it “a tall order” to implement the proposal “and then expect the competitive market to continue to function effectively.”
“The DOE proposal, which essentially is the cost-of-service type of mechanism, we don’t believe is workable. We don’t believe that that is an appropriate response,” Ott said. “We believe [it] is contrary to law and will not really solve any problems. … A better and least-cost solution would be to do proper valuation of resource attributes through a market construct.”
Ott said the proposal is discriminatory because it is exclusive to certain technologies, rather than the service provided to the grid, and only in RTOs with capacity markets — such as PJM.
“PJM does have an abundance of coal and nuclear plants that are in the merchant category, so … it does look like this is certainly targeted at the PJM region,” he said. “We do say that in our comments that this proposal does seem to be focused on this region.”
Bresler said that the NOPR — which cited natural disasters and the 2014 polar vortex to argue that units with large on-site fuel stockpiles should be subsidized to save them from retirement — misses the mark. (See FERC’s Independence to be Tested by DOE NOPR.)
“The point is that just maintaining a whole lot of resources with a 90-day fuel supply on site would not have relieved the problems with a majority of the outages during the polar vortex,” Bresler said. “While the polar vortex did highlight the need for the markets to ensure that we are signaling the need for resources to be able to operate on peak days, just resources with long-term fuel supplies on site was not the majority of the issue.”
During natural disasters, Bresler said, the main challenge is downed power lines, not generating plants being unable to run.
“Events like that … primarily affect the delivery system from supply to demand, not the supply resources themselves,” he said, noting that some coal plants impacted by Hurricane Harvey this summer weren’t able to run at full capacity because their coal piles were soaked.
“In the interest of framing the right problem, we will point out these things that we feel sort of led DOE down the wrong path as far as what the actual problem is,” he said. “We will say, however, that there is an issue that we do need to address, specifically to the PJM region. And that is the fact that there are some instances in PJM where not all resources are valued appropriately for the fact that they are relied upon to reliably meet the demand. … We are concerned that resources right now may not be offering as much flexibility as they could provide because they don’t have incentive to do it.”
Using competitive markets to “transparently” price needs is “superior” to providing cost-of-service payments to certain unit types, he said.
“One concern we have with the DOE approach is it seems to imply that while we may need to keep some of these resources around to ensure reliability and resilience, so therefore let’s keep them all,” Bresler explained. “That again is, from our standpoint, inefficient from the standpoint of the cost to load. Whereas the markets, we believe, have done a very good job to provide the discipline for what really is necessary and what’s not necessary and thereby not just provide efficient signals for entry, but also provide efficient signals for exit.”
PJM’s comments to FERC included a version of a proposal staff presented at its August meeting of the Markets and Reliability Committee. Bresler said the proposal will be revised and presented again at the Dec. 7 MRC meeting.
Ott acknowledged that PJM’s comments don’t reflect the perspectives of all its members.
“There really was no full vetting of these comments with stakeholders,” he said. “One, there isn’t sufficient time, and second is … PJM’s comments are PJM’s and we do not vet those through stakeholders.”
In his comments to FERC, Monitor Bowring said approving the DOE proposal “would replace regulation through competition with an unworkable hybrid of competitive markets and cost of service regulation. The eventual result would be the demise of competitive markets in the PJM region.”
“If the reliability rules need enhancement,” he continued, “the reliability rules should be enhanced. The DOE proposal should be rejected. The PJM region needs more competition, not less.”
MISO
MISO’s comments urged FERC not to adopt the proposal, saying it fails to identify imminent reliability or resilience issues, and said its footprint currently doesn’t have any such issues that would warrant immediate action “beyond the application of ongoing processes and existing tools that address resource availability and retirement in the MISO region.” [Editor’s Note: An earlier version of this article incorrectly reported that MISO did not file its own response.]
“Instead of proceeding in haste with material changes that could have broad-ranging and potentially adverse impacts, MISO urges the commission to move at a deliberate pace, to work through its existing dockets and to leverage its established processes to initiate a full, thorough and public vetting of the issues raised by the proposal,” the RTO wrote.
SPP told stakeholders Thursday it would will join the IRC filing, pointing to what staff called “some pretty strong comments.”
“The council does a really good job of laying out why this doesn’t work from an RTO perspective,” SPP General Counsel Paul Suskie told the Strategic Planning Committee.
“If you’re a plant under the rule, your costs are totally covered,” Suskie said. “Why would you do anything but bid zero into the market? It will drive costs down further and distort markets further.”
Some stakeholders expressed discomfort with signing onto the IRC comments without seeing the language.
“The basic issue here is the subsidy,” countered SPP Board Chair Jim Eckelberger, saying renewable energy tax credits had led to oversupply. “We don’t want to screw up the market even more. We should take a strong stand here.”
In its call for comments, FERC said the NOPR’s scope applies to commission-approved ISOs and RTOs with capacity markets and day-ahead and real-time energy markets. Noting SPP’s lack of a capacity market, Suskie said while it “appears this rule is not applicable to SPP,” staff will work under the assumption that a final FERC rule could apply to the RTO.
Suskie said the proposed timeline for action is “impractical.”
“Staff would recommend additional time to implement if the final rule applies to SPP,” Suskie said, noting staff would have to compile a list of eligible facilities. “Staff is very concerned. … If you read what the intent appears to be, basically any coal or nuclear plant not [rate-based] within an RTO would have to be fully compensated.”
Suskie asked who would determine a plant’s rate of return and cost of capital.
“Traditionally, those things are decided at the commissions, not RTOs,” he said. “How do you enforce a 90-day coal supply? How do you enforce whether a plant complies with environmental regulations?
“If this is applicable to SPP, it would be a big sea change,” Suskie said.
Keith Collins, executive director of SPP’s MMU, said his group agrees with much of what Suskie said, saying the NOPR is “proposing a solution to a problem that’s not well defined.”
The NOPR “doesn’t define the problem well in a way that’s actionable and measurable,” Collins said. “When you actually read the [recent DOE grid study], it says more work needs to be done to value and define resiliency before you come up with solutions. What’s included, what’s excluded … it’s hard to say.”
Like Suskie, Collins said the 90-day timeline does not allow sufficient time to properly consider the NOPR.
“If there’s a question to be raised, it can be answered over time, but we don’t support what’s going on,” he said. “Competitive forces have been part of policy in the energy and electricity markets over the last 25 years. It will provide new technologies, batteries and the like, that will improve the resiliency for the grid in ways we’re not aware of today.
“What the Energy Policy Act of 1992 did was promote competitive markets and open access,” Collins said. “If someone can provide power cheaper than someone else, they should be able to do that. If I built a plant a while ago that’s unprofitable, that’s a signal. Resources are indicating they are not being able to recover their costs. We see the consequences of a policy like this with our negative pricing.”
In his filing, Collins said “the SPP markets provide insight into the adverse consequences of policies designed to preserve capacity that would otherwise be uneconomic in typical ISO/RTO markets.
“The SPP market, which is dominated by vertically integrated utilities, provides an example of the potential difficulties that will be faced if the Proposed Rule is implemented,” he wrote. “The SPP market has a considerably high capacity margin, currently trending above 40% compared to the 12% minimum requirement in the SPP Tariff. The excess capacity distorts price formation in the competitive market by encouraging price insensitive offer/bid behavior and mutes price signals for others type of generating technologies.”
CAISO
CAISO said the rule would not apply to it because it does not have a capacity market or coal or nuclear resources that would be eligible for the proposed compensation. But it opposed the rule nonetheless, saying “there is no basis for a universal finding that having a 90-day, on-site fuel supply is essential for ISOs and RTOs to maintain grid reliability or resilience.”
ERCOT plans to revise its bylaws after discovering that dozens of members could be construed as affiliates under current rules because of stakes owned by investment funds such as Vanguard Group and Fidelity Management and Research.
The ISO learned of the issue from Vistra Energy, which informed ERCOT in September that Vanguard owns more than 5% of its voting securities — the current threshold for presuming that a shareholder exercises “substantial influence or control.”
Seely | ERCOT
ERCOT General Counsel Chad V. Seely told the board Tuesday that further investigation into Vistra’s letter identified 30 members who could be considered affiliates of each other based on common equity investors and that the number could go as high as one-third of the ISO’s 309 members.
Already, more than a dozen companies, including Calpine, Dynegy, Exelon and NRG Energy, have informed ERCOT they are in a situation like Vistra.
In addition to Vanguard and Fidelity, ERCOT said it has determined that at least five other investment firms may own more than 5% of two or more members: BlackRock, Capital Research Global Investors, Hotchkis & Wiley Capital Management, Oaktree Capital Management and State Street Global Advisors.
“In brief, ERCOT legal believes that this is just the beginning of identifying a longer list of potential members who may be affiliates through common equity ownership by a broader list of institutional investors,” Seely wrote board members in a memo.
Seely said companies deemed to be affiliates could be forced to change their industry segment or lose their voting rights.
His office issued membership applications on Oct. 2 for the year 2018. Corporate members must be registered by Nov. 10 to vote on board members at ERCOT’s Dec. 12 elections.
To address the issue, Seely recommended that the ISO revise the affiliate definition in the bylaws. In the interim, he said ERCOT should issue a “blanket” resolution saying that investment companies that own less than 20% of a member are assumed not to have control of the member.
The higher threshold would apply only to shareholders meeting one of the exclusions from the definition of “affiliate” under Texas’ Public Utility Regulatory Act (PURA) or has been determined to hold ownership interests in the member for investment purposes only. Not eligible for the 20% trigger would be members sharing a common parent or board member or under common influence or control of another entity.
Board Nominees
Walker | ERCOT
Corporate members will vote during the annual meeting Dec. 12 on a second term for unaffiliated board member Peter Cramton, a University of Maryland economics professor. They also will consider a newcomer, Terry J. Bulger, a banking executive specializing in risk management.
Unaffiliated directors, who serve staggered three-year terms, are also subject to approval by the Public Utility Commission of Texas. (Tuesday was the first ERCOT board meeting attended by new PUCT Chair DeAnn Walker.)
Consent Items
The board approved three nodal protocol revision requests (NPRRs) and one system change request (SCR) on the Technical Advisory Committee consent list.
NPRR768 — Revises the categories of ERCOT-initiated actions that trigger the real-time online reliability deployment price adder pricing run to ensure prices reflect current system conditions.
NPRR821 — Eliminates the congestion revenue right (CRR) deration process for resource node to hub or load zone CRRs, an effort to improve CRR funding.
NPRR840 — Synchronizes the implementation of NPRR782 (settlement of infeasible ancillary services due to transmission constraints) by removing the two-hour advance notice period inadvertently left in protocol language when NPRR782 was approved.
SCR791 — Populates unused megawatt and price values in security-constrained economic dispatch (SCED) generation resource data (GRD) energy offer curves with null values rather than zeroes, to improve the usability of the 60-day SCED GRD disclosure report.
Consent, Non-Consent Items OK’d
Shellman | ERCOT
The board also approved three additional NPRRs on individual voice votes:
Director Carolyn Shellman, of the Municipal Market segment, voted against two NPRRs, citing budgetary concerns. NPRR817 created the Panhandle 345-kV trading hub that would be excluded from the ERCOT-wide hub average and bus average calculations at an estimated cost of $150,000 to $200,000. “This would reduce the cost of future hubs,” TAC Vice Chair Bob Helton said.
Shellman also opposed NPRR829, which will allow a qualified scheduling entity to provide data on its net generation to the ERCOT transmission grid from their non-modeled generators so that the output can be considered in the estimate of real-time liability (RTL). The change is expected to cost between $200,000 and $300,000. The members of the Municipal segment opposed the proposal, but ERCOT supported it, saying it will improve the calculation of collateral requirements and transparency into non-modeled generation.
The board unanimously approved NPRR836, which incorporates 11 binding document forms into the protocols as a new Section 23, and allows changes to the forms to be made using the administrative NPRR process. Morgan Stanley, a member of the Independent Power Marketer segment, opposed the proposal at the Protocol Revisions Subcommittee.
Line of Credit
After an executive session, the board briefly reopened the meeting to renew its revolving line of credit with JPMorgan Chase.
PJM agrees there is an issue with maintaining reliability, but not the one suggested by the Department of Energy’s recent call for price supports for coal and nuclear plants.
“The DOE didn’t exactly get it right in the way it attempted to articulate the problem,” Stu Bresler, PJM senior vice president of operations and markets, said Thursday.
During a special conference call to preview the RTO’s plan for responding to FERC’s request for comments on the DOE Notice of Proposed Rulemaking, Bresler said that the real issue is energy price formation. PJM has been working on that topic for more than a year to respond to concerns over public-policy initiatives impacting market prices.
Bresler said that the NOPR — which cited natural disasters and the 2014 cold snap known as the “polar vortex” to argue that units with large on-site fuel stockpiles should be subsidized to save them from retirement — misses the mark. (See FERC’s Independence to be Tested by DOE NOPR.)
“The point is that just maintaining a whole lot of resources with a 90-day fuel supply on site would not have relieved the problems with a majority of the outages during the polar vortex,” Bresler said. “While the polar vortex did highlight the need for the markets to ensure that we are signaling the need for resources to be able to operate on peak days, just resources with long-term fuel supplies on site was not the majority of the issue.”
During natural disasters, Bresler said, the main challenge is downed power lines, not generating plants being unable to run.
“Events like that … primarily affect the delivery system from supply to demand, not the supply resources themselves,” he said, noting that some coal plants impacted by Hurricane Harvey this summer weren’t able to run at full capacity because their coal piles were soaked.
“In the interest of framing the right problem, we will point out these things that we feel sort of led DOE down the wrong path as far as what the actual problem is,” he said. “We will say, however, that there is an issue that we do need to address, specifically to the PJM region. And that is the fact that there are some instances in PJM where not all resources are valued appropriately for the fact that they are relied upon to reliably meet the demand. … We are concerned that resources right now may not be offering as much flexibility as they could provide because they don’t have incentive to do it.”
Using competitive markets to “transparently” price needs is “superior” to providing cost-of-service payments to certain unit types, he said.
“One concern we have with the DOE approach is it seems to imply that while we may need to keep some of these resources around to ensure reliability and resilience, so therefore let’s keep them all,” Bresler explained. “That again is, from our standpoint, inefficient from the standpoint of the cost to load. Whereas the markets, we believe, have done a very good job to provide the discipline for what really is necessary and what’s not necessary and thereby not just provide efficient signals for entry, but also provide efficient signals for exit.”
The response will include a version of a proposal PJM staff presented at its August meeting of the Markets and Reliability Committee. Bresler said the proposal will be revised and presented again at the Dec. 7 MRC meeting.
