Page 1139 – RTO Insider

February 13, 2020

Dominion: ‘No Near Term Impact’ from PJM MOPR

By Christen Smith

Dominion Energy executives told investors Tuesday that PJM’s expanded minimum offer price rule (MOPR) poses no near-term threat to its 2,600-MW offshore wind farm planned for 2026.

CFO Jim Chapman said Dominion’s balanced portfolio in Virginia will shield the company from any financial impact, but that electing the fixed resource requirement (FRR) alternative in the future remains a possibility.

“We don’t expect that that MOPR as proposed will have really any financial impact on Dominion,” he said. “As you know, our capacity and load in Virginia is pretty well balanced, so no near-term impact. And if we foresaw that some change with MOPR and PJM rules that would mean that we would not be potentially receiving capacity payments on new build generation, we could very easily … just elect that FRR option, which we think is pretty straightforward.”

In December, FERC expanded PJM’s MOPR to all subsidized resources entering the capacity market. Critics hold that the ruling will limit renewable energy development because offer price floors will push them out of the capacity market, while others insist capacity revenue factors little into renewable investment decisions.

Dominion MOPR — Dominion’s offshore wind project plans. | *Dominion Energy*

Dominion’s $8 billion offshore wind farm, the largest in the nation, will sit 27 miles off the coast of Virginia in federal waters. Dominion said ocean survey work will begin on the project in April, with construction slated for 2024. The company also confirmed Siemens Gamesa will provide the 210 turbines needed and that it contracted with three labor unions to perform the onshore interconnection work.

“We will continue to monitor that situation as it winds towards resolution,” Chapman said. “In the meantime, we do not see this as a material financial risk for our company given the even balance of supply and demand at Dominion Energy Virginia.”

Chapman’s comments came during a quarterly earnings conference call with investors where the company touted its progress on emissions reductions and improving its environmental, social and governance principles. The company reported a 33% increase in year-over-year earnings in its fourth quarter, totaling $4.48 billion.

Dominion CEO Tom Farrell said Tuesday that coal-fired generation produced just 12% of the company’s electricity last year, representing an 80% decline over the last 15 years. He said most current estimates suggest that “coal-fired generation today accounts for less than 8% of our total regulated investment.”

Farrell also expanded on Dominion’s plans to reach net-zero emissions by 2050, including extending licenses for its nuclear generation fleet; promoting customer energy efficiency programs, investing in wind and solar power; further reducing coal-fired generation; enhancing natural gas infrastructure leak detection; replacing legacy distribution lines; and repurposing agricultural methane emissions as renewable natural gas.

“We will never lose sight of our fundamental responsibility to customers, provision of safe, reliable and affordable energy,” he said. “Though certain approaches will undoubtedly evolve over the coming decades to reflect the most up-to-date assumptions, our commitment to net-zero emissions will not change.”

February 12, 2020February 19, 2025

PJM Seeks to Quell ‘Inflammatory’ Exit Talks

By Rich Heidorn Jr. and Michael Brooks

WASHINGTON — A top PJM official sought Monday to quell talk of an exodus from the RTO in response to FERC’s controversial order expanding the minimum offer price rule (MOPR), telling state regulators they shouldn’t lose sight of the RTO’s overall “value proposition.”

During a panel discussion at the National Association of Regulatory Utility Commissioners (NARUC) Winter Policy Summit, PJM Executive Director Asim Haque said the RTO hasn’t done an analysis on the rate impacts of FERC’s Dec. 19 order (EL16-49, EL17-178). Dissenting Commissioner Richard Glick said the MOPR expansion could add $2.4 billion in annual capacity costs.

But Haque said PJM is heartened by the Independent Market Monitor’s conclusion that the MOPR exemptions allowed for existing resources means that the order “may not have as deleterious an impact for state policy endeavors as at least initially perceived” in the short term.

Haque, a former Ohio regulator, said the order is not workable in the long term because it “needlessly frustrates state policy initiatives.” He said the RTO wants to work with stakeholders to “find that sweet spot between balancing those state policy priorities and wholesale market mechanisms.”

Haque downplayed PJM’s role as a policymaker, referring to it repeatedly as a “market administrator” and noted that FERC rejected both of its proposed options for addressing the concerns that state-subsidized resources were depressing capacity market prices.

He said discussions over whether states will leave PJM are “unnecessarily inflammatory,” noting that capacity represents less than 20% of generators’ revenues and that the RTO’s “value proposition” includes its energy and ancillary services markets, transmission planning and reliable grid operations.

“So, when you look at the … chunk that the capacity market takes up within that overall value proposition, we are talking about a portion of a portion of a portion of the overall PJM value proposition,” said Haque.

Christine Tezak, managing director of ClearView Energy Partners, agreed that states are unlikely to exit PJM altogether because of the energy market and the requirement to pay off regional transmission spending obligations. “But we think that the potential to opt out of [the capacity market] is on the table.”

She recalled FERC’s 2017 technical conference on capacity markets, where there was much discussion of “blending” state priorities with competitive market rules. (See RTO Markets at Crossroads, Hobbled FERC Ponders Options.)

“When you look at this order, there’s no blending. It is just a decision that the market comes first; everything else comes later,” Tezak continued. “If you look at this order, you start to wonder if joining PJM means that you have abdicated all resource adequacy authority.”

MOPR Contagion?

Mason Emnett, vice president of competitive market policy for Exelon, said the MOPR will push subsidized resources from the capacity market, leaving fossil fuel-fired generation as the marginal resources and threatening the future of the capacity market construct. If the expanded MOPR survives as is, he said, FERC will also apply it to ISO-NE and NYISO.

He cited the Electric Power Supply Association’s filings in January 2017 and April 2018 seeking expedited action on a complaint by the Independent Power Producers of New York over state subsidies (EL13-62). (The commission has listed the docket for action at the Feb. 20 open meeting.)

Although there is no open docket in ISO-NE, Emnett said, state commissions have asked to re-engage with the RTO on a market design accommodating state policies, with Connecticut seeking an analysis on alternatives like PJM’s FRR. (See Connecticut Weighs Pros, Cons of ISO-NE Markets.)

“If there’s a misalignment between what the states on behalf of their consumers are demanding and what the market is providing, that market does not survive,” Emnett said.

But Travis Kavulla, vice president of regulatory affairs for NRG Energy, an independent power producer (IPP), said the expanded MOPR will have little impact on renewables because of their falling costs. He noted his company’s business in ERCOT, where he said “the people who are placing bets are placing them on solar and demand response and not on combined cycle” plants. “If you were for some reason … to impose a capacity market on the state of Texas and establish some type of minimum offer price rule that will exist in PJM, those renewable resources will clear. They will be in the money.

“I think, ultimately, it’s much ado about nothing for renewables,” he said.

Tezak said the Base Residual Auction may need to shrink to its originally intended “residual” role.

“The problem is that the capacity market is mathematically perfect and politically problematic. And it has been from the beginning. It solves for too much capacity, as we’ve observed. The arguments we’re having are political in terms of: ‘What is the value of the things that aren’t included in the market?’” she said, referring to carbon emissions.

“If the capacity markets survive, I would expect them to change. And I think that we may have to come back to the conversations that we set aside [more than] a decade ago … which is, should you have varied tenors for capacity; should you have varied types of capacity?” said Tezak.

Change in Position for PJM?

Maryland Public Service Commission Chair Jason Stanek, who moderated the panel, asked Haque whether PJM’s “pretty pointed” Jan. 21 rehearing request represented a change in position by the RTO, which welcomed a new CEO, Manu Asthana, at the beginning of the year. (See PJM MOPR Rehearing Requests Pour into FERC.)

“I think it does reflect a change in the tenor of where PJM is situated,” Haque responded. “You have to understand that energy policy in the footprint is happening in the states. And it’s a trend that cannot be ignored.”

Maryland PSC Commissioner Anthony J. O’Donnell said later he wasn’t convinced that PJM has changed. “To now say, ‘We’re just the market administrator,’ I think, is a little rich, though I appreciate the change,” he said prompting laughter from other regulators. “You created this mess.”

Carbon Pricing

Most of the panelists were pessimistic at the prospects for the adoption of carbon pricing, which PJM officials have said could address state environmental concerns within a market construct. (See PJM: Carbon Pricing the Answer to Subsidy Dispute.)

“It sounds pretty straightforward in theory, until you figure that there are 14 different opinions about how it might be applied and the value each particular state … may choose to assign to it,” said Tezak, referring to PJM’s 13 states and D.C. She noted that the states in ISO-NE, which she said are more “homogeneous” on environmental policy than those in PJM, were unable to agree on a way to increase the role of carbon emissions in its markets.

A more realistic approach might be greater reliance on bilateral contracts tailored to individual states’ priorities, Tezak said.

Kavulla acknowledged the difficulty of achieving consensus on carbon pricing, saying that informed NRG’s proposal for FERC-approved, state-run clean energy procurements, “not unlike what the Southwest Power Pool has for resource adequacy, or what exists in the Western Energy Imbalance Market.”

He said a return to bilateral contracts could lead to higher prices because default energy suppliers in restructured states “are not appropriately incentivized to get the best deals. Either they’re affiliates of the people who are generation, number 1, or 2, they’re complete pass-through entities who don’t earn any margin or loss whatsoever on the power they procure.”

Emnett said Exelon, whose nuclear units receive subsidies subject to the MOPR, would support technology-neutral payments for carbon-free generation but that NRG’s proposal is unrealistic. “Instead, we’re trying to work with the states to use the tools that they do have available and avoid the harsh customer impacts of the MOPR,” he said.

Auction Timing

Emnett said Exelon agrees with the Maryland PSC that the capacity auctions should be delayed until 2021 to allow more time for the states to react to the ruling. PJM’s effective reserve margin is above 30%, he said, “so there isn’t a need for new generation at this point.”

Haque said the earliest PJM could run the next capacity auction is December 2020, after receiving an order on its compliance filing, which is due to FERC by March 18. That gives states time to explore their option to abandon the capacity market for the fixed resource requirement (FRR), he said. Delaying the auctions longer could mean default service providers will include a “risk premium” in their bids, increasing prices, Haque said.

Tezak said energy retailers also favor an earlier return to auctions because “they have no ability to forecast what their [capacity] costs are going to be.”

NRG circulated a handout that said customers in FRR markets in Ohio and Virginia have paid up to four times more for capacity than those in the rest of PJM because of reduced economies of scale. Kavulla said FRR also would result in a “re-monopolization” of the power sector that would create barriers for innovative technologies such as demand response and storage.

Changes on Rehearing, Appellate Rulings?

Tezak said her company is advising its institutional investors to exercise “caution” because of the possibility of changes in the rule on rehearing or in the appellate courts.

“There’s probably not a lot of durability to the MOPR order,” she said. “One of the things that we see as a big wild card is whether the position on self-supply, in particular, shifts. That would probably extinguish a lot of the criticism, [though] not all.” (See MOPR Ruling Threatens to Upend Self-supply Model.)

Tezak also noted that FERC has yet to act on rehearing requests on its original June 2018 order that found the existing MOPR unjust and unreasonable. “So, there could be all sorts of cascading legal weirdness that turn up that make assuming that this is as positive for the IPP community as it looks at first blush to be probably less beneficial in reality.”

Chatterjee Defends Order

In a press conference at the NARUC meetings on Tuesday, FERC Chair Neil Chatterjee defended the Dec. 19 order, which he and Commissioner Bernard McNamee supported.

Like Haque, he cited the Monitor Joe Bowring’s support for the ruling. The IMM requested clarification on some points but said the order “defines a clear, consistent and comprehensive approach to the PJM markets and to the role of subsidized resources in the markets.”

Bowring is “someone who’s very well respected in the field. Nobody would question his motivations,” Chatterjee said.

He also expressed skepticism that states will leave PJM. “Let’s see how this shakes out; let’s see how the auctions go; let’s what the impacts on these generators are before anyone makes these kinds of decisions,” he said. “I think when folks do the analysis and see what the benefits of participation in organized markets [are], I would think a state would have to think twice before losing the benefits that their consumers enjoy. …

“I know there’s a lot of focus … on tension between the states and federal regulators, but there are also a number of areas where we are continually and actively cooperating in,” Chatterjee added, listing cybersecurity, innovation, “the energy transition” and the Public Utility Regulatory Policies Act as among the topics he has discussed with state regulators at the conference.

February 12, 2020

Traders Respond to IRC on Risk Management Efforts

By Christen Smith

The financial trading group behind a request to update decade-old RTO credit policies fired back Monday against claims that its filing proposes a “one-size-fits-all solution” that would trample on stakeholder processes.

The Energy Trading Institute (ETI) said stalling “centralized discussion and information sharing of best practices” would waste a “golden opportunity” for each RTO to learn from the experienced risk management professionals their organizations lack.

“The current efforts/discussions underway at the ISOs and RTOs to address credit practices do not go far enough or are not exploring the appropriate corrective measures to address credit risk and market participant exposure in today’s market dynamics,” the group said in its answer filed Monday (AD20-6). “The ISOs/RTOs and industry undoubtedly could benefit from a discussion on well-established industry best practices for credit and risk management.”

The ISO/RTO Council urged RTO Council Balks at Credit Rulemaking.)

IRC Risk Management — GreenHat Energy, which ran up huge losses in PJM’s FTR market, listed its address as a UPS store between a nail salon and a RiteAid. | *Google*

The IRC also challenged ETI’s premise that the rules should be standardized, saying “the underlying markets to which the credit policies apply are not standardized.”

ETI asked the commission on Dec. 16 to schedule a technical conference by March 30 and convene a rulemaking to update FERC Order 741, its 2010 rulemaking on credit and risk management in the RTO/ISO markets.

The Institute said GreenHat Energy’s default on its 890 million-MWh financial transmission rights portfolio in PJM and RTOs’ slow adoption of credit policies to manage risks means the time is ripe for collaboration. In its answer, ETI points out that its rulemaking proposes “to explore common risk principles and risk management tools, such as the use of initial and variation margin and know-your-customer processes.”

“The technical conference and rulemaking process will allow parties to discuss the different methods to manage risk, the practical application of such methods and the tools available for implementation, which in turn will inform the ISOs’/RTOs’ efforts to protect their markets and their market participants,” ETI said. “This clearly is not a one-size-fits-all solution; it would allow the ISOs/RTOs and their stakeholders to work within a best-practices framework to implement credit and risk management policies and procedures appropriately suited for their respective markets.”

ETI also challenged IRC’s contention that RTOs have made significant progress on addressing credit reforms on their own. It said all regions save PJM still expect market participants to self-report rule violations. SPP lacks basic know-your-customer processes, while MISO could benefit from a deeper exploration of the practice, ETI said. The group did commend PJM, however, for hiring outside contractors to help design a margining model.

The Institute said FERC’s regulatory oversight means it must safeguard open and competitive markets from lackluster credit policies implemented by RTOs.

“The GreenHat default in PJM’s FTR market served as a significant eye-opener for the ISOs/RTOs and their stakeholders,” ETI said. “While it has been nearly two years since the default … the subsequent actions taken by the ISOs/RTOs to assess and improve their respective credit policies appear to be uneven in terms of whether they are addressing credit and to what degree, and include objectives that may not align with industry best practices for risk management.”

February 12, 2020

MISO to Debut Online Queue Requests

By Amanda Durish Cook

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 as k ing 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 Queue Requests — 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 meeti n g. 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 M I SO Makes Second Attempt at More Rigorous Queue.)

February 11, 2020

FERC Denies CPower Waivers for FCA 14

By Michael Kuser

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).

FCA 14 cleared 33,956 MW of capacity for 2023/24 after five rounds of bidding. (See related story, ISO-NE Capacity Prices Hit Record Low.)

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.

CPower Waivers FCA 14 — 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.)

February 11, 2020

NEPOOL Participants Committee Briefs: Feb. 6, 2020

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.

“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.)

— Michael Kuser

February 11, 2020

EIM Governance Review Committee Now Scoping

By Hudson Sangree

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.

EIM Governance Review Committee — CAISO’s Board of Governors and the EIM Governing Body met jointly in September. | © *RTO Insider*

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.

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.

February 11, 2020

CPUC Cites ‘Audacity’ of PacifiCorp Rate Request

By Hudson Sangree

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.”

CPUC PacifiCorp Rate Request — 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.

“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.”

February 11, 2020

Glick Warns Capacity Rules Putting RTOs ‘in Peril’

By Michael Brooks

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.

Glick Capacity Rules — FERC Commissioner Richard Glick | © *RTO Insider*

“I think the commission needs to think twice before we go down that path,” Glick said. “FERC needs to accommodate state policies, not override them.”

Glick was referring to FERC’s December order expanding PJM MOPR Rehearing Requests Pour into FERC.)

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.”

February 11, 2020

PJM Operating Committee Briefs: Feb. 6, 2020

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.

PJM Operating Committee — 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.

– Christen Smith