MISO is taking measures to speed up the initial step in its generator interconnection process through a more efficient application process.
Speaking during a Feb. 11 conference call, Jesse Phillips, MISO manager of resource utilization project management, said the RTO will revise its Tariff to convert its generator interconnection queue application from a print-and-send form to an instant, online submission. The new procedure will go live in April.
Prospective interconnection customers will also be able to upload documents and models with their application. MISO plans to hold a March 9 training session with stakeholders on the new tool. In the meantime, MISO is asking for stakeholders’ written reactions on the new process through Feb. 26.
The RTO has pledged to confirm receipt of online applications within five business days and notify customers of incomplete applications within 15 days. For complete applications, the new process will take about 30 business days.
MISO online GIP application | MISO
The online interconnection request is aimed at streamlining the queue process to save time.
MISO’s interconnection queue peaked at a proposed 101 GW worth of projects in 2019, but the volume has since declined to about 80 GW. Solar projects have become the dominant resource type in the queue at just over 46 GW, more than double proposed wind projects at 19 GW.
“The bottom line is that we’re catching up on the queue,” MISO Executive Director of Resource Planning Patrick Brown said at a Feb. 10 Entergy Regional State Committee meeting. Brown added that MISO plans to introduce more improvements to accelerate project processing and study.
MISO last year began building models in-house for studies required for the queue’s definitive planning phase. Staff at the time said ending the outsourcing of queue modeling work to third parties cut months of delay from the queue timeline. (See MISO Makes Second Attempt at More Rigorous Queue.)
VALLEY FORGE, Pa. — Exelon succeeded Wednesday in its attempt to defer a vote on a quick fix to the synchronous reserve operations and maintenance cost adder in PJM Manual 15.
Some 77% of the Market Implementation Committee agreed with the transmission owner’s motion to delay voting on the Independent Market Monitor’s problem statement and issue charge until the first meeting that occurs seven days after FERC rules on PJM’s energy price formation proposal (EL19-58).
“It doesn’t make sense to approve one portion of the reserve proposal sitting before FERC and not the others,” said Sharon Midgley, Exelon’s director of wholesale market development. “We think it’s better not to leverage the quick fix option to cherry-pick certain items pending before FERC.”
At last month’s MIC meeting, the Monitor said that recently approved maintenance adders to the synchronized reserve calculation allow resources to withhold from the reserve market and increase offers above competitive levels. (See “Synchronized Reserve Calculation Error,” PJM MIC Briefs: Jan. 8. 2020.)
To remedy this, the Monitor’s Catherine Tyler told the committee to set the synchronized reserve operations and maintenance cost included in Manual 15 to zero. Market sellers could still submit alternate O&M cost calculations to PJM and the Monitor for review using an exception procedure outlined in Section 1.8 of the manual.
“We are certainly not cherry-picking items here,” Tyler said Wednesday. “It is something that we see as a cleanup that we identified and that’s why it was rolled in with the other parts of the [energy price formation] proposal. It needs to be cleaned up and it’s a simple change and not any attempt to break up the larger package.”
Adrien Ford of Old Dominion Electric Cooperative and Steve Lieberman of American Municipal Power both pressed Exelon on their hesitance.
“There’s no timeline on which FERC has to act,” Ford said. “If they never act, then we never fix the duplicative nature of this? It seems like if we’ve got duplicative cost recovery, I’m not sure why we would let that sit another year.”
Midgley said that pushing through the change “is not an appropriate use” of PJM’s quick-fix process.
“Our broader concern is that reserves are drastically undervalued in the PJM marketplace,” she said. “We could support what the IMM has put on the table today if it were combined with other comprehensive reserve pricing reforms, but it’s not.”
Pseudo-tie Eligibility Requirements
In an unusual move, PJM dropped its plan to advance revisions to Manual 12 Attachment F that attempted to clarify pseudo-tie eligibility after stakeholders argued some of the revisions conflicted with pending litigation.
PJM’s Tim Horger said that the revisions follow FERC’s approval of the RTO’s external capacity filing in November 2017 and “enhance transparency into the process of what’s currently being done.”
“FERC rules don’t prevent PJM from making any changes to manuals that are subject to complaint proceedings,” he said. “There’s no deadline by which FERC has to act. Should FERC issue an order that disagrees with how we are implementing the rules, we will go back and make the change. Otherwise, it’s business as usual for PJM.”
Jeff Whitehead of GT Power Group challenged PJM’s logic, the first in a wave of complaints that the revisions were premature.
“Do we really want to make these kind of changes until we hear back from FERC in these proceedings?” he said. “The meaning of the words ‘eligible coordinated flowgate’ are the subject of litigation.”
“There’s quite a bit of complaints before FERC on this very topic,” Lieberman said. “There are words that may not seem all that important but have quite a bit of significance. The words ‘eligible’ and ‘actually’ in terms of market to market flowgate tests, those have some real significance.”
“We agree 100%; we think these changes are premature,” said Steve Kelly of Brookfield Energy Marketing.
States, Advocates Unsure of Black Start Fuel Assurance
States and consumer advocates expressed concern about the cost of requiring black start resources to become 100% fuel assured under proposed new guidelines pending before both the MIC and the Operating Committee.
“We are not convinced that PJM has demonstrated there’s a level of benefits associated with this level of costs customers are being asked to bear,” said Greg Carmean, executive director of the Organization of PJM States Inc. “These are new incremental expenditures to provide fuel assurance for black start.”
Carmean’s comments came in response to the three packages that PJM presented from the OC/MIC special session that would create black start requirements RTO-wide. In plans authored by PJM and the Monitor — which earned 58% and 15% support, respectively, in a nonbinding poll — resources would be required to become 100% fuel assured. The mandate would cost approximately $513 million, with increases in annual revenue requirement ranging between $67 million and $81 million.
PJM said it’s “confident” in its estimates because it collected the data during a 2018 request for proposals window that asked units to extrapolate the costs of becoming black-start eligible. The Monitor said the costs will vary greatly zone to zone, however, while Calpine pointed out that PJM’s estimates are a cap and would likely come in much lower.
A third plan, offered by the D.C. Office of the People’s Counsel that garnered 34% support, would cut the fuel assurance requirement in half for an estimated cost of $13 million with a $2.3 million ARR.
Exelon offered to meet the D.C. OPC “in the middle” with a proposed amendment that would determine the level of fuel assurance after coordination with the TO and PJM.
“We just really felt that the 50% was limiting, particularly if a level of 55% would result in drastically improved restoration times,” Exelon’s Midgley said. “Why would we limit ourselves?”
Erik Heinle of the D.C. OPC said he was open to considering the idea.
“I’d like to look at it and see how it works with our package,” he said. “We certainly want additional feedback and if there are things we can do to make the package work for a broader group of stakeholders, we certainly want that.”
PJM scheduled a live voting session for members on the MIC and OC roster to commence prior to the start of the March 11 MIC meeting.
PJM to Retire Opportunity Cost Calculator
After months of debate, PJM said it will retire its opportunity cost calculator as of June 1, leaving stakeholders to use the Monitor’s calculator.
The decision comes two months after the Markets and Reliability Committee deferred voting on a joint package from Panda Power Funds and Dominion Energy that would streamline PJM’s calculator to more closely resemble the Monitor’s tool. (See “Comparative Cost Framework, Opportunity Cost Calculator in Flux,” PJM MIC Briefs: Sept. 11, 2019.)
In the end, PJM decided the low usage rate for its calculator was reason enough to retire it and eliminate any compliance concerns raised by stakeholders.
Stakeholders Wary of PJM’s Interpretation of MOPR ‘Death Penalty’
PJM’s legal department told the committee that it believes the “death penalty” provision contained within FERC’s Dec. 19 minimum offer price rule (MOPR) decision applies on a yearly basis, allowing resources with an approved competitive exemption to claim subsidies in subsequent delivery years.
The phrase refers to the provision in the ruling that penalizes a resource for taking the competitive exemption but then also taking a subsidy, even though it promised it wouldn’t in order to obtain the exemption.
The issue came up during PJM’s explanation of how its upcoming compliance filing would handle voluntary renewable energy credit (REC) transactions. Resources with these sorts of deals could theoretically apply for the competitive exemption under the expanded MOPR, which requires those resources to forgo all subsidies.
The Monitor, along with other stakeholders, believe the ruling intended that should a resource qualify for a competitive exemption in one year and then claim subsidies in subsequent years, that market participant could face a lifetime ban from the capacity market.
“It’s not obviously correct,” Monitor Joe Bowring said. “In our view, it applies if you take a subsidy in any year of the life of the asset. You entered under false pretenses and the rule applies. I don’t think it’s unambiguously obvious.”
PJM argues the ambiguity in the ruling gives the organization leeway to interpret it differently and base its compliance filing on the more lenient reading.
The RTO has scheduled more special MIC sessions to discuss the MOPR, on Feb. 19 and 28. The Demand Response Subcommittee will devote the entirety of its March 9 meeting to the new rules, and PJM will again discuss elements of its compliance filing at the March 11 MIC meeting.
PJM Floats Alternatives to 10-Hour Energy Storage Rule
PJM presented alternative minimum requirements for energy storage resources as part of its upcoming brief due in a paper hearing that challenges its proposed 10-hour minimum runtime for energy storage resources.
FERC accepted most of PJM’s storage rules in October but set the 10-hour proposal for a paper hearing to determine whether it was just and reasonable. PJM requested a 90-day extension for its brief on Nov. 26.
PJM’s 10-hour rule remains the highest requirement proposed among RTOs/ISOs (ER19-469). ISO-NE sought only a two-hour minimum, while NYISO proposed four. PJM says the runtime corresponds with existing reliability standards, noting that it must “remain impartial in administering the markets.”
PJM’s Andrew Levitt said that after a special session on the issue hosted last month, stakeholders brought forward two other proposals that could serve as a reasonable alternative to the 10-hour rule.
The first would cut the rule down to power output measured for four continuous hours. The second would use effective load-carrying capability (ELCC) to determine the runtime. ELCC evaluates reliability in each hour of a simulated year and compares a resource mix scenario with limited resources against one with unlimited resources.
The options will be discussed further in Feb. 24 special session of the MIC, with PJM scheduled to file its brief on March 11.
FERC on Wednesday denied CPower’s two waiver requests to allow its seven summer-only distributed solar demand capacity resources to participate in ISO-NE’s Forward Capacity Auction 14 and substitution auction held last week (ER20-458).
CPower argued that its resources could not participate in FCA 14 and the substitution Competitive Auctions with Policy Sponsored Resources (CASPR) auction because the RTO’s Tariff requires such qualified capacity to be the lesser of those resources’ summer-only or winter-only qualified capacity.
Under ISO-NE rules, demand capacity resources must submit a composite offer (i.e., partly summer capacity and partly winter) into the auction because they have a 0-MW winter qualified capacity; without such an offer, these resources would have a default FCA qualified capacity of 0 MW.
In response, CPower elected to qualify for the FCA 14 under the renewable technology resource (RTR) exemption, which allows a limited amount of renewables to participate in the auction without being subject to the RTO’s minimum offer price rule. Next year’s auction will be the last to include the RTR.
Demand response provider CPower had bid seven summer-only distributed solar demand capacity resources into FCA 14 under the renewable technology resource exemption. | CPower
For each auction, the combined capacity for resources under the RTR exemption has a set megawatt cap, which was exceeded for FCA 14, prompting the RTO to prorate the exemption among resources that qualified for it.
CPower sought to submit the summer-only qualified capacity for FCA 14 at the Internal Market Monitor’s mitigated — or offer floor — price. The company noted that the Tariff does not permit composite offers to be prorated under the RTR exemption when the cap is reached. Alternatively, CPower sought a waiver to allow it to withdraw from its election of the RTR exemption and make composite offers for summer-only and winter-only qualified capacity.
ISO-NE protested the first waiver request but not the alternate.
In rejecting the primary request, the commission said CPower was seeking “to shield its resources from the consequences of its choices and the same risks that other demand capacity resources face in qualifying for FCA 14.”
The commission also ruled that the alternate waiver “would shield only CPower’s demand capacity resources from the risk that proration may apply when selecting” the RTR exemption, and that the company “does not demonstrate why its resources should be offered the opportunity to opt out … once proration results are known, when no other resource has that choice.”
Commissioner Richard Glick dissented on the commission’s rejection of the alternate request, saying that “without a waiver, the FCA will categorically ignore the capacity that [CPower] resources provide.”
“Unless the commission is prepared to categorically reject all waiver requests, the potential for differential treatment is not a reasoned basis for denying the alternate waiver request,” Glick said. “Moreover, the fact that the [request] applies only to CPower’s resources would seem to support CPower’s request, not to undermine it. If the request applied to all resources that elected the RTR exemption, then it might very well not be limited in scope.”
In a similar proceeding, the commission last week denied Genbright a waiver for 14 of its distributed generation projects to avoid what the company claimed was a “complex interconnection study process.” (See related story, FERC Rejects Genbright Waiver on FCA14.)
The New England Power Pool Participants Committee on Thursday heard about ISO-NE’s response to Connecticut state regulators, who last month held a public hearing to examine whether the RTO’s wholesale electricity markets are geared to serving the state’s clean energy objectives.
ISO-NE Vice President of External Affairs Anne George recounted her testimony at the hearing, saying she recommended the state pursue a general policy discussion rather than a regulatory proceeding, especially as no specific regulation could take effect before the end of the 2020s. (See Connecticut Weighs Pros, Cons of ISO-NE Markets.)
PC Chair Nancy P. Chafetz directed stakeholders not to get into a deep policy discussion of ISO-NE’s response to Connecticut officials.
Loads Fall to Historic Lows
ISO-NE COO Vamsi Chadalavada reported that January — like December — saw record high temperatures averaging 7.8 degrees Fahrenheit above normal, which was reflected in loads.
“Real-time loads have been averaging just about 14,000 MW, and the natural gas prices are just about averaging $3/MMBtu,” Chadalavada said.
“Our loads have been averaging close to historic lows for the months of December and for January, almost directly correlated to the very mild weather,” he said. “Season to date, temperatures have been about 4.5 degrees warmer than normal, and January has been much higher than that, almost double at close to 8 degrees more than normal.
Daily average day-ahead and real-time ISO-NE hub prices and input fuel prices, Jan. 1 to 29 | ISO-NE
“Also there’s been very little snow cover, so the output from the PV installations … is going to be more efficient, and that also factors into these low loads that we see during the middle of the day when the sun is out,” Chadalavada said, adding that the RTO forecasts more of the same for the coming weeks, aside from a brief cold spell at the end of this month.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to amplify their presentations.]
Net commitment period compensation (NCPC) payments have also hovered at record lows, continuing a trend from 2019, he said, noting that second contingency payments totaled $108,000, down $2.5 million from December, all of it in Southeast Massachusetts/Rhode Island and resulting from a transmission line being out of service.
Chadalavada also responded to a stakeholder question received offline about testing energy imports for their intensity of emissions.
“We’re hoping to take that up in April, but what we’ve seen based on our research is that there isn’t really granular information that’s available that allows for either a monthly or even a real-time assessment,” Chadalavada said. “There is an opportunity on an annualized basis to collate some data, but to get a more granular level requires some source of public information that we haven’t been able to find.”
Litigation Report
NEPOOL Secretary David T. Doot highlighted several items from the monthly litigation report, starting with the proceedings involving broad resistance to FERC’s December decision to subject new self-supply units to the minimum offer price rule (MOPR) in PJM’s capacity market (EL16-49, EL18-178).
The commission said PJM must expand its MOPR to counter increasing state subsidies, primarily for renewables and financially struggling nuclear generation, but self-supply load-serving entities argue the order will unravel their business model. (See MOPR Ruling Threatens to Upend Self-supply Model.)
Other discussion focused on Forward Capacity Auction 14, which last week cleared 33,956 MW of capacity for 2023/24 after five rounds of bidding at a record low of $2/kW-month, a nearly 50% drop from $3.80/kW-month in 2019. (See related story, ISO-NE Capacity Prices Hit Record Low.)
FERC last week rejected a couple waiver requests related to FCA 14. The commission denied solar aggregator Genbright a waiver for 14 distributed energy resources projects “to avoid ISO-NE’s complex interconnection study process, including the system impact study, which is ISO-NE’s comprehensive reliability evaluation” (ER20-366). (See related story, FERC Rejects Genbright Waiver on FCA14.)
In the second case, the commission denied Mystic owner Exelon a waiver to amend its cost-of-service agreement and allow the generator to retire in the second year of the two-year agreement (ER19-1164).
Doot also highlighted FERC declining to reconsider two orders upholding NEPOOL’s gag rule but allowing an RTO Insider reporter to join the organization’s End User sector. (See FERC Rejects Rehearing on NEPOOL Press Rules.) The commission also denied Public Citizen’s request for rehearing of its April 2019 ruling rejecting RTO Insider’s complaint seeking to void NEPOOL’s policies prohibiting nonmembers, including the press and public, from attending stakeholder meetings (EL18-196-001).
Tariff Revisions on Storage
The PC on Thursday approved Tariff revisions to enumerate the services that will result in the transmission charge exemption and expanded its explanation regarding why exempting electric storage facilities from transmission charges is justified given the policy direction set out in FERC Order 841.
The commission in December conditionally accepted ISO-NE’s Order 841 compliance filing but asked for additional changes to clarify the application of transmission charges to electric storage resources (ER19-470). (See Storage Plans Clear FERC with Conditions.)
The Governance Review Committee (GRC) of CAISO’s Western Energy Imbalance Market continued laying out the parameters of its big job this year in a stakeholder call Wednesday, following the release of a scoping paper Jan. 29.
In that paper, the GRC put forward a preliminary set of topics it expects to consider, including the selection of Governing Body members, stakeholder meetings, areas for Governing Body involvement and the development of guiding principles.
“We decided to commence our work by publishing this scoping paper, which provides our preliminary view on topics we should consider and seeks stakeholder input on the scope and substance of the issues the GRC should consider,” it said.
The outline of topics and questions was based largely on stakeholder comments from the EIM’s governance review initiative last year.
“The GRC is going to encourage stakeholders to really reflect on their previous comments,” for example, on the possible extension of the EIM to an extended day-ahead market, said Peter Colussy, CAISO’s regional affairs manager. (See CAISO Takes Step Toward EIM Day-ahead Market.)
The authority of the EIM Governing Body relative to the CAISO Board of Governors is a major topic. So is the criteria for selecting Governing Body members and the number of members who sit on the body.
With the anticipated addition of four Colorado utilities (not shown), the EIM will have member entities in every Western state. | CAISO
The EIM began operations in 2014. It allows wholesale energy transfers across state lines to balance supply and demand in the Western Interconnection in real time, saving its participants nearly $862 million so far, according to CAISO.
The market’s charter required a governance review by 2020 “to account for accumulated experience and changed circumstances over time,” Colussy told a June joint meeting of the CAISO board and Governing Body. (See CAISO OKs EIM Governance Review.)
CAISO and EIM leaders established the GRC in June as a temporary advisory group that will disband once it completes its work. Its mission is to go through a stakeholder process, draft proposals and offer the Governing Body and the CAISO board a set of recommendations in less than a year.
The GRC’s 14 members represent utilities, public interest groups and academia, among others.
Comments on the scoping paper are due Feb. 21. The GRC’s next in-person meeting will be on March 11 in Phoenix, Ariz.
The committee is trying to complete its work this year by publishing a straw proposal in late April and a revised straw proposal in September, followed by a final draft in November.
Joint consideration by the Governing Body and board is expected in early 2021.
The California Public Utilities Commission on Thursday unanimously denied PacifiCorp’s requested annual revenue requirement, rebuking the company for asking to cover the accelerated depreciation of out-of-state coal plants it hasn’t yet committed to close.
The commission approved a revenue requirement of $72 million — $6.6 million less than the utility’s request in its 2019 General Rate Case Application (18-04-002). Most of the requested revenue the commission denied was $5.24 million to cover the depreciation.
“Holding firm on actual retirement commitments for any accelerated depreciation request is an important key in holding the company accountable,” Commissioner Liane Randolph said at the CPUC’s voting meeting in Bakersfield. “Without a retirement date commitment, it’s possible California ratepayers could pay more over time and still be served by coal.”
PacifiCorp operates a dozen coal plants outside California, including the Hunter Power Plant in central Utah. | PacifiCorp
PacifiCorp had asked for the changes in April 2018, contending that it sought to “mitigate current risks by increasing flexibility to address changing carbon policy. Specifically, PacifiCorp is proposing to accelerate depreciation on coal-fired resources so that all coal facilities will be fully depreciated by 2029 or earlier.”
PacifiCorp did not directly address the CPUC’s decision in a statement released Friday. “Pacific Power customers in Northern California will see a 5% reduction in their power bills under a decision finalized Thursday by the California Public Utilities Commission,” it said. “The decision, based on a filing originally made in early 2018, reflects the company’s reduced operating costs from prudent and efficient management including tax savings from the changes in federal tax law passed in 2017.”
PacifiCorp said its 2019 integrated resource plan, announced in October, calls for transitioning to lower-cost renewable energy and retiring 16 coal-fired generating units among its dozen Western coal-fired power plants by 2030.
“The unit retirements described in the IRP plan will reduce coal-fueled generation capacity by nearly 2,800 MW by 2030 and by nearly 4,500 MW by 2038 while maintaining reliability and affordability for customers,” the utility said.
Calling out PacifiCorp
PacifiCorp serves about 45,000 customers in California, representing about 2.4% of its total customer base in the West. The utility, based in Portland, Ore., divides its operations between Pacific Power in California, Oregon and Washington, and Rocky Mountain Power in Idaho, Utah and Wyoming.
PacifiCorp’s California service territory occupies an area of rugged mountains and small communities near the Oregon border. Of PacifiCorp’s 10,880 MW of generating capacity — from hydropower, wind, natural gas, coal, solar and geothermal resources — only about 70 MW — all hydro — is in California. All of PacifiCorp’s coal units are in other states, primarily Utah and Wyoming, and serve customers throughout its service territory, including in California.
PacifiCorp’s California service territory occupies a largely rural area near the Oregon border. | PacifiCorp
“Given that so much of their assets and operations are located outside of California, we had to ensure that the small number of ratepayers within California were protected,” Randolph said.
“Under PacifiCorp’s request, California ratepayers would pay off those coal assets faster than their useful lives,” she said. “And this benefit from ratepayers might have been appropriate if PacifiCorp had in turn fully committed to retiring those facilities.”
While the utility has said informally in other venues that it would close its coal plants, “it made no commitment to do so in this proceeding,” Randolph said.
Under Senate Bill 100, passed in 2018, California must remove fossil fuels from its resource mix for retail customers by 2045. Getting rid of polluting coal power is a top priority, and the CPUC has been irked by PacifiCorp’s refusal to commit to retire its plants in other states.
Randolph said PacifiCorp is welcome to submit its coal plant closure plan to the CPUC sooner than its next rate case in 2022 along with a request for accelerated depreciation.
Commissioner Martha Guzman Aceves thanked Randolph and commission staff members for their work in the rate case and questioned why PacifiCorp wasn’t more willing to commit to retiring its coal plants.
“I just appreciate [you] calling out … PacifiCorp [for] having the audacity to seek such a rate benefit while not committing to the retirement of coal,” Guzman Aceves said. “Although obviously we have huge climate goals to drive our dependency on coal away, that really is not even necessary here. It’s really that this resource is no longer cost effective.”
WASHINGTON — FERC Commissioner Richard Glick told state energy officials that he thinks the commission needs to holistically revisit the concept of mandatory capacity markets or risk putting “in peril the future of RTOs in general.”
Speaking at the National Association of State Energy Officials’ Energy Policy Outlook Conference and Innovation Summit at the Fairmont Washington hotel Wednesday, Glick said he was “a big believer that regional markets can provide a lot of benefits,” such as efficient dispatch of generation and integrating renewable energy.
But he said “certain recent orders of the commission” are threatening to make state renewable or clean energy standards “ineffective” and lead states to reevaluate whether they want their utilities participating in the markets.
Instead, he criticized MOPRs in general and lamented the fact that PJM, along with ISO-NE and NYISO, “come to FERC constantly with proposals to change the way we deal with various issues in the capacity markets.”
“I used to think that competition was really about competition; that if there’s an auction, everyone bids in and the most cost-effective generation resources … get chosen and they go along their merry way and that sets the price for everybody,” Glick said. “That’s not actually the way it works at all. We’re telling almost every entity bidding in what they can bid in at, whether it’s because of state policies or because of market power or because of the various curves. … We’re micromanaging every single aspect of these capacity markets, so nobody’s bidding in what they want to bid in at. This makes managing competition in health care look like a small thing.”
“It’s just really frustrating, and I’m not entirely sure we’re achieving anything, because all we’re doing is bringing everything to FERC and litigating every last issue.”
Glick’s rhetoric echoed the criticism that former Chair Norman Bay lobbed at MOPRs three years ago. (See Bay Blasts MOPR on Way Out the Door.) He said he “was still struggling” with what exactly the commission should do but that he would “look at what’s going on in California, maybe MISO [or] even Texas, which doesn’t have a capacity market at all.”
It’s not just states pulling out of the RTOs that Glick is concerned about.
“I think we’re just going to create more and more litigation,” he said.
The more energy prices fall, the more that companies will look to make up for it in the capacity markets and petition FERC to further change the rules, he said. “That’s not what people intended when they started talking about competitive energy markets 20, 30, 40 years ago.”
Mary Beth Tung, director of the Maryland Energy Administration, asked Glick what difficulties he could foresee in states pulling out of RTOs.
Glick said it would be difficult for deregulated states to “put Humpty Dumpty back together again.” The states would have to reassess whether they want to return to the vertically integrated model, he said. Tung, who in introducing Glick said that Maryland was watching the MOPR proceeding closely, acknowledged “that is definitely an issue we’ve been having discussions about as well.”
Speaking to reporters after he answered several audience questions, Glick said he thinks “there are several items or errors” in the MOPR order “that I think the court could easily use to overturn that decision.”
“We can’t continue doing what we’re doing because the future of the RTOs is at stake.”
VALLEY FORGE, Pa. — PJM under-forecasted the peak hour load on three days in January, staffer Stephanie Monzon told the Operating Committee on Thursday.
Monzon said lower-than-anticipated temperatures on Jan. 5 and 18 spiked load by as much as 5% above estimates. On Jan. 2, load rebounding faster than expected from New Year’s Day meant PJM’s forecast was off by more than 4%. The RTO commits to a 3% margin of error for daily load forecasts.
Daily peak forecast error in January | PJM
TO/TOP Matrix
The OC unanimously agreed to recommend TO/TOP matrix revisions to the Transmission Owners Advisory Committee for endorsement later this month.
The latest version of the matrix cuts about 20 pages of NERC standards that were retired in 2017. The slimmer manual will make the matrix easier for TOs and PJM’s auditors to use, staff said.
Manual 40: Training and Certification
The committee unanimously endorsed revisions to Manual 40: Training and Certification stemming from a periodic review. Various sections, including 2.3.4, 3.3 and 3.4, were updated to reflect correct operator/dispatch terminology and temporary waiver language for training and certification compliance. Staff also removed Section 4: PJM Operator Training entirely.
VALLEY FORGE, Pa. — PJM told the Planning Committee last week that it will share unredacted project proposals with its Independent Market Monitor, despite confidentiality concerns raised by incumbent transmission owners late last year.
“The confidentiality agreements were done pursuant to our guidelines and rules, which made it very clear that the information is not confidential between PJM and its contractors,” said Chris O’Hara, PJM’s general counsel. “The IMM is one of our contractors. We are not deviating from those agreements.”
The issue came to a head at the Markets and Reliability Committee meeting on Dec. 19 when a majority of stakeholders endorsed Manual 14F language that memorializes the Monitor’s role in analyzing competitive transmission proposals. (See PJM TOs Challenge Monitor’s Competitive Tx Role.)
Incumbent TOs contended the revisions had no basis in Attachment M of PJM’s Tariff and undermined the yearslong vetting process stakeholders undertook to fine-tune cost-containment language for Manual 14F. (See PJM TOs Wary of Cost Containment Rules.)
PJM’s explanation on Feb. 4, however, left some in the sector, including PPL and Public Service Electric and Gas, questioning its logic and expressing confusion that the RTO expected TOs to know that the Monitor is a PJM contractor.
O’Hara reiterated PJM’s position that “there is no basis to withhold data submitted from market participants in competitive windows from the IMM, and the IMM will observe the confidentiality requirements associated with that data.”
Market Efficiency Process Enhancement Packages
The Market Efficiency Process Enhancement Task Force brought three sets of packages to the PC for first read as part of the group’s phase three recommendations.
The packages address changes to the benefit calculation, the window for capacity drivers and the regional transmission market efficiency project (RTMEP) process, and included proposals from PJM, the Monitor, American Electric Power and FirstEnergy.
AEP’s package for updating the RTMEP process won 67% support in a nonbinding poll of 13 respondents representing 110 companies. The company proposed a process that would fill the gap that exists when historical congestion “is persistent and not captured in planning models.” Among its suggested changes, AEP said benefits should be based on two years of historical congestion. The approval process should consider capital costs with no discounts and whether or not those costs will be recovered within the first four years of service via benefits provided. The projects also would be designated to the incumbent TOs.
Some 55% of poll respondents preferred PJM’s package for updating the benefit ratio calculation to modify inputs to consider capacity benefits. The current capacity benefit calculation uses the Regional Transmission Expansion Plan for simulation, including versions that look three years and six years ahead. Changing this calculation to use simulations for the delivery and planning years will better address topology and capacity energy transfer limit uncertainties, PJM said.
PJM also suggests placing restrictions on the in-service date for the capacity market so that project analysis ensures projects address a capacity driver by the applicable auction year. PJM proposes projects must be in service prior to June 1 of the delivery year for which the Base Residual Auction is being conducted.
The Monitor argued that PJM’s cost-benefit analysis is flawed because it doesn’t consider a proposal’s positive and negative impacts. The IMM’s two proposals to base calculations on systemwide load or production costs received just 18% and 11%, respectively.
Finally, 100% of poll respondents supported PJM’s proposal to create a standalone process to address capacity drivers independent of energy driver analysis. The RTO suggested opening separate windows for energy and capacity drivers used for market efficiency projects. The Monitor’s proposal to consolidate the windows received 31%.
The PC will vote on the packages at its next meeting March 10.
Dominion, BGE Supplementals
Dominion Energy wants to add a third, 84-MVA distribution transformer at Cloverhill substation in Prince William County, Va. The new transformer would support continued load growth in the area and contingency loading for the loss of one existing transformer, Dominion said. The projected in-service date is June 1, 2022.
The company also proposed a $14.1 million plan to replace the obsolete Chickahominy 500/230-kV transformer with three single-phase banks and one spare bank with new units. Dominion identified the transformer for replacement during its ongoing transformer health assessment process, noting that the existing unit was installed in 1987 and has known issues.
Baltimore Gas and Electric, an Exelon subsidiary, said it wants to replace four 230-kV oil-filled circuit breakers at its Raphael Road and Waugh Chapel substations. The units are at risk for poor performance and carry environmental risks, the company said.
CARMEL, Ind. — MISO will soon seek FERC approval for a proposal to tighten load-modifying resource accreditation standards for capacity auctions even as some stakeholders complain that the plan is too restrictive.
MISO’s proposal would base an LMR’s accreditation on the smaller of either its tested availability or an average of its actual availability over a three-year period. LMRs that can respond more often and with shorter lead-times will receive a larger capacity credit. (See MISO Eyes Cuts to LMR Capacity Credit.) The original proposal has been tweaked to allot full capacity credit to LMRs that can respond to 10 or more calls in a year.
Additionally, MISO will no longer qualify LMRs with lead times greater than six hours as emergency-only resources, although those resources will still be eligible to qualify as capacity resources. The RTO is analyzing whether these LMRs actually help mitigate emergency events.
Multiple stakeholders have said MISO’s late April filing goal is too impractical and aggressive. RTO staff disagree, noting the deadline is essential to implement the changes before the 2021/22 Planning Resource Auction offer window opens.
“It’s a missed opportunity in MISO’s view to make incremental improvements,” planning adviser Davey Lopez said of not pursuing the accreditation proposal now. He also pointed out that the RTO has altered the proposal to count only availability during daily peaks of the summer months for the three years, and not year-round daily peaks.
Stakeholders at the Resource Adequacy Subcommittee’s meeting Wednesday said the proposal seemed designed to punish LMRs.
“If you’re sitting in our seats, it’s absolutely punitive. … There’s a lot you could do before whacking capacity credits off our resources,” Madison Gas and Electric’s Megan Wisersky said. “I can’t help but think of the risk and reward of being an LMR in MISO. The risks and the potential penalties so far outweigh the benefits.”
Lopez reiterated that resources must be compensated based on their availability. He also said the proposal would cut down on the uncertainty that MISO control room operators currently face.
“Right now, we just don’t think there’s an incentive to update the values in the [MISO Communications System]. There’s no incentive to be available in fewer than 12 hours. … Those LMRs are compensated the same as LMRs with short lead-times,” Lopez said.
“The data our operators have shown is that they’re nowhere near” their reported availability, he added.
