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December 17, 2025

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State Regulators to Re-examine PNM’s EIM Membership

By Hudson Sangree

New Mexico’s Public Regulation Commission vacated an order earlier this month that had paved the way for Public Service Company of New Mexico (PNM) to join CAISO’s Western Energy Imbalance Market by the spring of 2021.

The move surprised many. The effort for PNM to join the EIM was largely uncontroversial and received unanimous support from the PRC’s five elected commissioners on Dec. 20. But the commission decided to revisit its decision after Albuquerque’s water agency protested the December ruling and after two new commissioners were sworn in this year.

PNM doesn’t need the commission’s approval to join the EIM because it does not involve the transfer of any of the company’s assets and market participation is strictly voluntary.

Proponents say New Mexico’s ample wind and solar power would be a valuable addition to the Western Energy Imbalance Market. | U.S. Department of Energy

The case (18-00261-UT) instead dealt with PNM’s request for an order governing the accounting treatment of costs related to joining the EIM. The commission’s December order authorized PNM to recover its expenses in a future rate case.

Now, however, PNM and some environmental groups worry the PRC’s latest move could delay PNM’s membership in the EIM for another year and cost ratepayers $10 million in projected annual benefits.

“Until a new order is issued, PNM will not undertake efforts to join the Energy Imbalance Market,” Western Resource Advocates argued in an emergency motion to the PRC. “Likewise, because it takes two years of preparation to join the EIM, there is a queue to join and a deadline of April 1 in each year, unless the commission issues an order quickly. … New Mexico will lose one year of substantial economic and environmental benefits.”

The Coalition for Clean Affordable Energy joined WRA in its motion, and the Natural Resources Defense Council said in a news release that the commission’s action was a “step backwards” in state efforts to use more renewable energy.

PNM said in it was disappointed by the commission’s move.

“PNM’s decision to join the EIM was dependent on the commission’s December 2018 approval,” Thomas Fallgren, vice president of generation, said in a statement emailed to RTO Insider. “PNM has suspended all work on the Energy Imbalance Market due to today’s actions. Any further delays or changes of the December order may jeopardize our ability to reap the customer benefits.”

In a brief order Feb. 6 vacating its December ruling, the PRC did not explain the reasons for its action. It merely said it had the legal authority to rehear the case at the request of the Albuquerque Bernalillo County Water Utility Authority.

The water utility had argued that the cost-recovery decision was made too hastily by a commission that included members near the end of their terms.

“The procedural record in this case establishes that the commission only had hours to review the hearing transcript, evidence introduced into the record during the hearing, briefs filed by the [water authority], PNM and staff, and the proposed order on accounting treatment,” the water utility’s lawyers wrote in their brief.

“Given the time for this review and the voluminous record to review, a thorough review by commissioners of this material was impossible as a practical matter,” it said. “Such a rush to judgment by departing commissioners is problematic and should not bind the present commission to an ill-advised course of action.”

The water utility contended PNM should be required to file quarterly reports on its EIM benefits and shouldn’t be guaranteed a return on investment, with ratepayers bearing the risk.

“It is axiomatic that the commission is the surrogate for the marketplace, and if PNM were operating in the marketplace, rather than as a regulated monopoly, it would not be guaranteed recovery of its investments,” the water utility’s lawyers wrote in a Jan. 17 application to reopen the case.

Further action by the PRC is pending. It remained unclear if the commission will hold another hearing or, as Western Resource Advocates urged, decide the case on the record before it to expedite a decision.

CAISO, which did not comment on the PRC’s action, says the EIM has generated $565 million in benefits for its members since its founding in November 2014.

The EIM’s membership consists of CAISO, PacifiCorp, Arizona Public Service, Idaho Power, NV Energy, Portland General Electric, Puget Sound Energy and Powerex. The Los Angeles Department of Water and Power, the Sacramento Municipal Utility District and four other entities, including PNM, are scheduled to join between 2019 and 2021.

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Vermont Transco Denied Transfer Fee Cost Recovery Again

By Amanda Durish Cook

FERC on Thursday again denied Vermont Transco permission to embed transmission acquisition costs in its rate recovery through the ISO-NE Tariff.

In rejecting a rehearing request on the issue, the commission affirmed its decision last year rejecting the company’s attempt to recover $639,780 from Vermont ratepayers to cover property transfer taxes, closing fees and advisory fees related to its acquisition of shares in the Highgate Transmission Facility near Quebec (ER18-1259-001).

Vermont Transco first filed the request for recovery in March 2018, and FERC rejected it in May.

| Vermont Transco

In a 2017 filing seeking FERC approval to acquire Green Mountain Power’s stake in Highgate — which was eventually granted — Vermont Transco acknowledged that “there is no mechanism in [ISO-NE’s] cost-based transmission formula rate that allows the automatic pass-through” of transaction-related costs. The company promised to make a separate filing if it intended to seek any transaction-related costs that would also demonstrate “specific, measurable and substantial benefits to ratepayers.”

But the company’s 2018 cost-recovery request contended that the requirement to show ratepayer benefits didn’t apply because the company was not seeking to recover an acquisition premium. The company also contended it could recover the expenses from customers because service over Highgate is provided under ISO-NE’s Regional Network Service rate, which relies on cost causation and beneficiary pays principles. It also noted that it never made a hold-harmless commitment on such recovery.

In denying the request, FERC pointed to Vermont Transco’s previous commitment — set out in the transfer application — to demonstrate ratepayer benefits. The commission also said the company couldn’t simply bypass ISO-NE’s restriction on an automatic pass-through of the transaction-related costs and reminded it of its earlier promise that the transaction would not have an adverse effect on rates.

The commission added that Vermont Transco was free to file again for cost recovery provided it detailed how the recovery would benefit ratepayers.

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FERC Rejects PJM’s Gas Pipeline Contingency Proposal

By Christen Smith

FERC said last week that PJM’s proposal for reimbursing generators for fuel-switching costs and for penalties incurred when gas pipelines fail lacked specificity and clarity.

In a ruling issued Feb. 19, FERC rejected the stakeholder-approved mechanism submitted for inclusion in PJM’s Operating Agreement and Tariff that would have implemented a process for market sellers seeking cost recovery for certain gas contingencies associated with fuel-switching instructions from the RTO (ER19-664.)

FERC rejected PJM’s proposal for compensating generators for costs associated with fuel-switching orders. | Entergy

PJM’s filing would have become effective Dec. 21 and allowed generators to request cost recovery from FERC across nine different categories: park-and-loan service charges; overrun charges; exceeding maximum daily quantity; exceeding minimum/maximum storage balance; imbalance cash-out charges; disposal of gas and related products costs; other gas balancing costs; start-up costs; and alternate fuel costs.

FERC described PJM’s definition of “penalty” — costs that are designated as such in the pipeline or local distribution gas company tariff and imposed by the applicable pipeline or company — as “unreasonably narrow and unsupported.” The commission said pipeline tariffs delineate between penalties and the RTO’s proposed categories in different ways, meaning what appears to be relevant fuel-switching costs for one pipeline could be considered a penalty for another. The commission also faulted PJM for not including events that might trigger fuel-switching directives in its Tariff and for lacking established procedures for dealing with such contingencies through existing market design.

“Continuous communication and coordination between the RTO, the gas pipeline operator and the relevant generation owners can be critical to ensure the reliable operation of both systems,” FERC concluded in its ruling. “Given this lack of clarity, PJM’s proposal does not reasonably ensure that coordination occurs prior to a generator’s switching to an alternate pipeline.”

The D.C. Office of the People’s Counsel crafted the rules and compensation plan detailed in the filing after earning a majority of stakeholder support at the December meeting of the Markets and Reliability Committee. (See “Gas Pipeline Contingencies,” PJM MRC/MC Briefs: Dec. 6, 2018.)

The supermajority vote signaled a major victory for load interests who were opposed to the Calpine-authored plan endorsed at the Market Implementation Committee in November. That proposal would have developed a formula for cost recovery to be filed with FERC that did not include pipeline penalties. (See “Gas Pipeline Contingencies,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)

Jeff Shields, a PJM spokesperson, said Friday that staff are still considering next steps.

“We continue to believe that this is an important issue to resolve and is another step in improving gas-electric coordination,” he said. “We are evaluating the order and our options for working with stakeholders to rectify the issues FERC found with our filing.”

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Committee Considers Ways to Streamline MISO Meetings

By Amanda Durish Cook

MISO’s Steering Committee is looking for ideas on how leaders of stakeholder groups can best oversee spirited discussions while sticking to schedules listed on meeting agendas.

Speaking during a Feb. 20 conference call, Chair Tia Elliott said the committee is seeking near-term solutions for managing conversations during heavily attended public meetings.

More participants are asking more questions following stakeholder meeting presentations, the RTO has found. Among the subjects sparking the interest: proposed new rules to address a growing gap in resource availability and need; a new load forecasting method; studies to determine when renewable integration will become unmanageable; and plans to incorporate storage separately into energy markets and the transmission planning process.

The MISO Reliability Subcommittee meets last year. | © RTO Insider

The committee has discussed using the “raised hand” function on the online meeting platform WebEx, as well as having participants send emails directly to the Client Relations Department during the discussions.

Reliability Subcommittee Chair Bill SeDoris said at a recent heavily attended RSC meeting, leaders gave in-person attendees priority to make comments and ask questions while compiling emails of questions to take from phone participants.

“Emails did work, but it was a little clunky,” SeDoris said, noting that the RSC had two stakeholder specialists on hand to handle the high-traffic discussion.

But MISO Stakeholder Relations Specialist Alison Lane said it’s unlikely the RTO can provide two specialists for every meeting.

Lane suggested stakeholders develop a “comment queue” following a presentation, where committee chairs ask those in the room to raise their hands and those over the phone to signal, allowing a specialist to compile an ordered list of stakeholders to call on.

She also said chairs might have to limit stakeholders to “one really good question” apiece instead of allowing a single stakeholder to ask multiple questions. She added that MISO and chairs must anticipate which topics on the agenda will elicit a lengthy discussion and plan accordingly.

Resource Adequacy Subcommittee Chair Chris Plante said stakeholders attending by phone are sometimes forced to interrupt conversations to ask long-awaited questions.

Elliott said the Steering Committee will consider the comment queue suggestion and noted that any process changes wouldn’t likely be memorialized as a rule in the RTO’s Stakeholder Governance Guide.

MISO will also host a March 18 stakeholder training on managing meetings as part of Board of Directors Week in New Orleans. Lane said the session will focus on governance rules and tips on how to successfully facilitate a meeting.

MISO Rebrands Market Roadmap

MISO also told the Steering Committee on Wednesday that it will rebrand its Market Roadmap list of future market improvements as the “Integrated Roadmap,” which will include more research and reporting on industry trends to provide support for the RTO’s reasoning behind and prioritization of proposed changes.

The roadmap will now include research focus areas and an emphasis on changes to accommodate what MISO dubs the “3Ds”: demarginalization, decentralization and digitization of the electric grid. It will also include the annual publication of an insights and strategy report to explain how major trends might affect RTO operations. The first such report will be published in early March, and MISO has also tentatively planned an April 9 stakeholder workshop to discuss the report.

MISO Director of Stakeholder Affairs Joan Soller told the Steering Committee that the new design is meant to be “more inclusive” of topics that span multiple committees.

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‘Boring Good’ Rulemaking Seeks to Clean up Order 845

By Robert Mullin

Decked out in a New England Patriots jersey to commemorate her beloved team’s Super Bowl victory, FERC Commissioner Cheryl LaFleur on Thursday also celebrated the workaday process behind a new rule clarifying the commission’s 2018 directive to improve the generator interconnection process.

FERC Commissioner Cheryl LaFleur | FERC

LaFleur said the “highly technical rule” clarifying Order 845 brought to mind former Commissioner Robert Powelson’s emphasis on the importance of the commission’s work doing “the boring good” (RM17-8-001, Order 845-A).

“These sorts of technical rules are a big part of the way this commission is working to help adapt to all the changes in resources on the grid — particularly renewables and storage coming on, as well as changes in ownership structures of who is developing and who is doing work on the grid.”

The ruling came in response to 12 requests for rehearing or clarification related to Order 845, the rules issued last April to increase the transparency and speed of the interconnection process. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.) While the majority of the that order — originating in a request by the American Wind Energy Association — remains intact, Thursday’s decision provides a bevy of updates, including the following:

  • Requiring transmission providers to explain why they do not consider a specific network upgrade to be a standalone network upgrade, while also allowing them to recover option-to-build oversight costs;
  • Clarifying that the Order 845 option-to-build provisions apply to all public utility transmission providers, including those that reimburse interconnection customers for network upgrades, and that the option to build does not apply to standalone network upgrades on affected systems;
  • Granting rehearing on a provision to create a surplus interconnection service process, explaining the commission did not intend to limit the ability of RTOs and ISOs to argue variations are appropriate;
  • Clarifying transmission providers may use FERC’s critical energy/electric infrastructure information (CEII) regulations as a model for evaluating entities that request network model information and assumptions;
  • Clarifying the phrase “current system conditions” does not require transmission providers to maintain network models that reflect current real-time operating conditions of the transmission provider’s system but that should reflect the system conditions currently used in interconnection studies;
  • Clarifying the reporting requirements do not require transmission providers to post 2017 interconnection study metrics, with the first report expected for the first quarter of 2020;
  • Granting rehearing in part to find that an interconnection customer may propose control technologies at any time at which it is permitted to request interconnection service below generating facility capacity; and
  • Clarifying a transmission provider must provide a detailed explanation if it determines additional studies at the full generating facility capacity are necessary when the interconnection customer has requested service below full capacity.
Kathleen Ratcliff, FERC Office of Energy Market Regulation | FERC

Thursday’s order denied all other requests for rehearing and clarification.

Responding to a question from LaFleur, Kathleen Ratcliff, of FERC’s Office of Energy Market Regulation, said she thought the most recent order “balanced the interests” of interconnection customers and transmission providers and “appropriately considers” the concerns of both.

“I think Order 845 was an important step forward to help improve interconnection processes and facilitate interconnection of technologies like storage. This starts the clock for [RTOs and ISOs] submitting compliance filings,” FERC Chairman Neil Chatterjee said.

While acknowledging the changes announced Thursday will help transmission customers “better utilize interconnection processes and ultimately make more efficient use of existing transmission grids,” Commissioner Richard Glick said, “the job is not complete.”

“We still have important work to do, especially as we consider reform related to affected systems coordination as we review each compliance filing to today’s rule.”

Other Rules

Under its consent agenda, FERC adopted a rule updating its regulations on when an applicant who would otherwise require commission authorization to hold an interlocking position between a public utility and financial company “need not do so” (RM18-15).

Under the changes, an applicant for an interlocking position between a utility and a “bank, trust company, banking association or firm that is authorized by law to underwrite or participate in the marketing of public utility securities” will not require FERC authorization when:

  • the applicant does not participate in any of the utility’s deliberations or decisions regarding the selection of the bank, trust company, banking association or firm to underwrite or participate in the marketing of securities for the public utility;
  • the firm of which the person is an officer or director does not engage in the underwriting of, or participate in the marketing of, securities of the utility of which the person holds the position of officer or director;
  • the utility for which the utility serves or proposes to serve as an officer or director selects underwriters by competitive procedures; or
  • the issuance of the utility’s securities has been approved by all federal and state regulatory agencies having jurisdiction.

Another rule adopted Thursday stipulates the commission will no longer review corporate mergers valued at less than $10 million (RM19-4). The rule will also require public utilities valued above $1 million to notify FERC regarding mergers and consolidations. The rulemaking implements Congress’ direction under an amendment to Section 203 of the Federal Power Act, the commission has said.

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CAISO Seeks More Transfers with Pacific Northwest

By Hudson Sangree

SALT LAKE CITY — CAISO is exploring ways to exchange more low-carbon electricity with the Pacific Northwest, while WestConnect is looking to absorb exports from California during times of CAISO overgeneration, speakers said Tuesday at the Western Planning Regions Annual Interregional Coordination Meeting.

WestConnect’s CAISO Export Stress Study is intended to “test the robustness of the WestConnect transmission system in a [scenario of] high California export into the WestConnect footprint,” said Charlie Reinhold, project manager with WestConnect, which oversees transmission planning in Arizona, New Mexico, Colorado and several other Western states.

CAISO’s Gary DeShazo addressed the 2019 Western Planning Regions Annual Interregional Coordination Meeting in Salt Lake City on Tuesday. | © RTO Insider

The Feb. 19 meeting brought together stakeholders and representatives of CAISO, ColumbiaGrid, Northern Tier Transmission Group (NTTG) and WestConnect to discuss interregional coordination under FERC Order 1000. The order requires transmission providers to participate in a planning process that identifies the most cost-effective solutions to transmission needs and to allocate costs based on estimated benefits.

No regional transmission needs under Order 1000 were identified in the current planning cycle, but several studies are underway in response to California’s ambitious clean-energy goals. The state enacted a new law last year, SB 100, that requires investor-owned utilities, publicly owned utilities and community choice aggregators to obtain 100% of their energy from renewable and zero-carbon resources by 2045.

The new law sets renewable milestones along the way: 40-44% by 2024, 45-52% by 2027, and 50-60% by 2030. That means California will have to import more clean electricity, and export solar energy when it’s generating too much, in the coming years. (See Can Calif. Go All Green Without a Western RTO?)

At the same time, natural gas generation, the state’s main fossil-fuel source of electricity, is expected to gradually disappear.

Order 1000 transmission planning regions in the West. | FERC

CAISO embarked on its study of north-to-south transmission after it received a letter in February 2018 from the California Public Utilities Commission and California Energy Commission asking it for help in planning for transmission needs as the hobbled Aliso Canyon natural gas storage facility near Los Angeles is phased out in the next 10 years and the state’s gas generation diminishes.

“Phasing out Aliso Canyon usage and potential impacts on the gas-fired generation fleet need to be considered from the perspective of reliability of electricity supply to southern California more generally and the Los Angeles Basin in particular, as well as the role those resources play in providing adequate system capacity and flexibility overall,” CEC Chairman Robert B. Weisenmiller and CPUC President Michael Picker wrote to CAISO CEO Steve Berberich.

At the interregional planning meeting, Gary DeShazo, regional coordination director at CAISO, said the ISO has a close working relationship with the PUC and CEC, which provides CAISO with renewable portfolio standards and load information.

“We do a transmission plan with that information in our base case,” DeShazo said.

“They’ve looked at it from the point of view of what does it take to meet the state’s greenhouse gas goals?” he added.

Planners are studying how to increase transfers of low-carbon electricity between California and the Pacific Northwest without major upgrades to existing infrastructure. | CAISO

In the joint letter, the PUC and Energy Commission told CAISO: “Expanded transmission capability is an important option available to us. Clearly, increasing the transfer of low-carbon supplies to and from the Northwest can be one of the multiple puzzle pieces that we must examine to build a cumulative phase out strategy.”

“Toward this end, we are requesting a specific sensitivity case be included in the 2018- 2019 California ISO transmission planning process (TPP),” Weisenmiller and Picker wrote. “It is time-critical that we act now to evaluate key options to increase transfer ratings of the AC and DC Intertie and assess what role these systems can play in displacing generation whose reliability is tied to Aliso Canyon.”

Ebrahim Rahimi, CAISO’s lead regional transmission engineer, said the effort, called the Pacific Northwest-California Transfer Increase Informational Special Study, involves increasing transfer capacities without major system upgrades, primarily on the main AC and DC interties linking the Columbia River basin to Los Angeles — and thereby the Pacific Northwest to the desert Southwest.

The retirement of California’s last nuclear generating station, PG&E’s Diablo Canyon Power Plant on the central California coast, will ease congestion on existing pathways, Rahimi said. CAISO is also examining whether NERC and WECC might relax their standards on the physical separation of high-voltage transmission lines.

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MISO Offers Reassurances on FTRs, Examines Changes

By Amanda Durish Cook

The fallout from GreenHat Energy’s record default in PJM’s financial transmission rights market prompted MISO officials on Wednesday to reassure members that such failures are unlikely to happen there.

“MISO doesn’t believe there’s as much of a risk in our market versus PJM’s,” Director of Finance and Accounting Ross Baker said during a Feb. 20 Advisory Committee conference call.

However, Baker acknowledged that MISO’s ongoing investigation of its own practices could identify some improvements to its FTR credit calculation later this year.

MISO Advisory Committee in September | © RTO Insider

In September, MISO officials said they were giving increased scrutiny to an already in-progress review of the RTO’s own FTR market. At the time, the executives said MISO’s FTR market was less susceptible to a default than PJM’s because MISO relies on a more conservative credit calculation and requires higher collateral, preventing “thinly capitalized” parties from buying large portfolios. The grid operator also said it limits FTR terms to one year, while PJM allows rights for up to four years. The RTO pointed out it estimates the value of transmission congestion more frequently than PJM, updating congestion estimates monthly rather than annually. (See “MISO Reviewing FTR Process” in MISO Board of Directors Briefs: Sept. 20, 2018.)

Baker reiterated MISO’s stance to the Advisory Committee on Wednesday. He said the RTO’s practice of not netting net auction bid prices with estimated congestion credit value for collateral requirements is a “key component for minimizing the magnitude of a default.”

“We haven’t identified any significant issues … We expect we’ll be able to provide an update sometime in May,” Baker said of the ongoing review. “We don’t believe our calculations are perfect; we believe there will be some potential improvements.”

As of December, PJM’s total FTR default was estimated at about $187 million; however, if FERC’s rejection of PJM’s requested waiver of liquidation methods is upheld, the default could climb to more than $430 million, according to PJM. (See PJM: FERC Order Could Boost GreenHat Default by $300M.)

“We don’t have any means of verifying [PJM’s estimate],” Baker told the Advisory Committee.

Responding to a stakeholder question, Baker said he couldn’t be sure whether MISO’s exposure to default is non-existent or greatly reduced compared with PJM. “There certainly is a potential for loss, but we believe it’s much less of an exposure in our market,” Baker said.

Baker said MISO may convene a stakeholder task team to examine possible improvements to the calculation.

MISO will continue its evaluation of FTR practices as planned, concluding sometime this year. Baker said the RTO will discuss any FTR collateral requirement changes with stakeholders in regularly scheduled Market Subcommittee meetings.

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MISO LMR Capacity Rules Get FERC Approval

By Amanda Durish Cook

FERC on Tuesday approved a MISO proposal requiring owners of load-modifying resources to provide firmer and more clearly documented commitments regarding their availability before participating in the RTO’s capacity market.

The proposal represents the first piece of MISO’s three-part near-term resource availability and need initiative.

” … Recent maximum generation emergency events have frequently occurred outside the summer season as generator forced outages and high load conditions converge with planned generator outages that are typically scheduled in the spring and fall seasons. MISO contends that these spring and fall maximum generation emergency events do not align well with the obligations of LMRs, which currently are not required to serve MISO load in non-summer seasons,” the RTO said in making the case for the new rules.

MISO control room | MISO

The new rules require a load-modifying resource (LMR) to offer capacity in accordance with a seasonal availability report provided to MISO and commit to deploying based on the shortest notification time it “can consistently meet” but no longer than 12 hours (ER19-650). LMR owners must provide that information to MISO during registration.

In return, MISO will issue scheduling instructions before an emergency occurs based on an LMR’s unique notification times. The RTO has also promised to confirm or withdraw advanced scheduling instructions at least two hours prior to an expected emergency event. LMRs that acknowledge scheduling instructions will receive credit for one of the five times per year that LMRs are required to respond, regardless of whether the emergency declaration is made.

MISO said the rules will improve transparency around LMR capability and give it easier access to LMRs during emergency situations.

In approving the filing, FERC also granted a waiver of MISO’s usual deadlines for LMRs to register their availability for the April capacity auction. LMRs now have until March 1 to complete registration. (See “LMR Registration Confusion” in MISO Preliminary PRA Data up Slightly from Early Prediction.)

A group of MISO industrial customers protested the filing, saying the RTO was vague and failed to outline how the “best physical capability” and “shortest notice requirements” of LMRs would be measured and verified. Those customers also said the new availability requirements could create an “incentive for LMRs to exit the market,” which could drive up capacity auction clearing prices.

But FERC said cut-and-dried availability rules wouldn’t work best for LMRs, which differ in operating characteristics and limitations: “Although a specific definition would provide certainty to some LMRs, it would likely be incompatible with the capabilities and circumstances of other LMRs. Therefore, we find reasonable MISO’s proposal to give flexibility to each LMR in determining its own capabilities and the type of supporting documentation it can provide for the purpose of demonstrating its capabilities.” The commission also dismissed as “speculative” the claim that the RTO’s proposal will force LMRs to exit the market.

MISO has two other near-term filings awaiting FERC action as part of the short-term resource availability and need project: one to subject demand response to annual capability testing and the other to impose new generator accreditation penalties for planned outages taken fewer than 120 days in advance and during what MISO deems “low-margin, high-risk periods.” The trio of filings is aimed at immediate relief in time for spring and to buy time for in-depth solutions. The Market Subcommittee and Resource Adequacy Subcommittee will work on the more involved solutions — yet unnamed — through 2020. (See Stakeholders Seek Slowdown on MISO RAN Project.)

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PJM Extends Planning Window After FERC Approvals

By Christen Smith

PJM will extend the submission window for long-term projects an additional two weeks to account for recent transmission planning rule changes approved by FERC.

“We are not expecting significant changes, but we are expecting some changes, so we felt it right to extend the window,” PJM’s Brian Chmielewski told a special meeting of the Transmission Expansion Advisory Committee Feb. 20.

PJM will extend the submission window for long-term transmission planning projects another two weeks to account for market efficiency rule changes. | © RTO Insider

FERC earlier this month approved PJM’s revisions to its market efficiency planning rules effective Feb. 13. (See FERC OKs PJM’s Market Efficiency Rule Changes.) The updates impact Section 1.5.7 of the RTO’s Operating Agreement that would exclude from market efficiency planning — with exceptions — generation either with only an executed facilities study agreement (FSA) or with an executed interconnection service agreement (ISA) under suspension (ER19-562).

A second ruling issued Tuesday accepts PJM’s changes to its evaluation of economic-based enhancements as part of its Regional Transmission Expansion Plan, ensuring the benefit/cost ratio for projects proposed in the current year — as opposed to those with delayed in-service dates — will be an “apples-to-apples” comparison (ER19-80).

The rule changes come near the tail-end of the long-term transmission planning window opened in November, which accepts proposals capable of reducing future congestion. (See PJM Market Efficiency Rules Could Slip Deadline.) Chmielewski said extending the submission window will not affect the market efficiency planning cycle, with final review by the TEAC and the board scheduled for December.

Revised Benefit/Cost Ratio

In the Feb. 19 ruling, PJM won its bid to revise the benefit/cost ratio to ensure projects with delayed in-service dates only receive analysis within the existing 15-year planning horizon. Under previous rules, PJM said it spent considerable time developing ad-hoc projections for years beyond the current cycle, resulting in “risky” and “unreliable” modeling.

FERC agreed with PJM’s argument that “limiting the timeframe over which benefits are calculated for market efficiency projects with in-service dates beyond the RTEP Year would address concerns regarding the additional risk of using more speculative benefit estimates for projects with farther out in-service dates.”

The new calculation factors the present value of the total annual enhancement benefit for the 15-year period starting with the RTEP year — defined as current year plus five — minus benefits for years when the project is not yet in-service, divided by the present value of the total enhancement cost for the same 15-year period.

“Thus, under this proposal, if a proposed market efficiency project has an in-service date that extends beyond the RTEP Year, benefits and costs (i.e., revenue requirements) would be evaluated over the same timeframe used for projects with an in-service date of the RTEP Year, which would be for a shorter period than under the current calculation,” FERC concluded.

ITC Mid-Atlantic and NextEra filed a joint protest Oct. 31 arguing the calculation favors smaller, more incremental market efficiency projects and incumbent transmission owners with the ability to propose small-scale upgrades to their own systems. The Independent Market Monitor seconded protestors’ concerns in a separate filing, noting PJM didn’t provide sufficient evidence to suggest their new calculation wouldn’t encourage developers to “game” the system.

PJM said it reviewed 13 projects from the 2016/17 planning window with in-service dates beyond the RTEP year and found that benefit/cost ratios for 11 improved under the changes. The RTO acknowledged several methods exist to levelize project evaluations — each with pros and cons — but prefers its proposed method because it eliminates ad hoc projections for out years.

“We find PJM’s proposal to use the same 15-year planning period for evaluating all projects to be just and reasonable, given that the data for periods outside of the planning period are less accurate,” FERC ruled. “PJM has made a filing to align its benefit/cost analysis with its planning horizon, and we find that proposal just and reasonable as it establishes a level playing field upon which competing market efficiency projects may be evaluated.”

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ISO-NE Chief Sees ‘Year-round’ Energy Risks Coming

By Rich Heidorn Jr.

ISO-NE CEO Gordon van Welie said Wednesday that his concerns about New England’s ability to keep the lights on continue to grow despite recently enacted market rule changes, predicting that energy security risks “could become a year-round concern.”

ISO-NE CEO Gordon van Welie | © RTO Insider

The region has benefited from a milder-than-normal 2018/19 winter and has not faced the severe, lengthy natural gas shortages that marked the two-week cold spell early last year. The RTO also has implemented its Pay-for-Performance incentives and held its first capacity auction under rules intended to mitigate price suppression by subsidized resources.

But speaking at his annual State of the Grid press call, van Welie said the transition to a “hybrid” grid with growing distributed and renewable generation means that “eventually nearly all resources in the fleet will have some energy limitations.”

In addition to limited oil and LNG supplies and just-in-time natural gas deliveries, the region will face new challenges as the shares of wind and solar generation grow. “As this contingent of energy-limited resources grows, the region’s energy-security risks could become a year-round concern,” he said. “New England’s power system is operating from a strong foundation, but the vulnerabilities we’ve discussed in previous briefings are still here, and still growing.”

The grid operator marked a milestone on April 21, 2018, a sunny day when — for the first time — net load peaked overnight because of strong solar power during mid-day.

“On the other hand, clouds and snow cover prevented solar panels from reaching their seasonal potential during last year’s historic 16-day cold spell, particularly during Winter Storm Grayson,” van Welie said. The cold snap also exposed the limits of energy storage, which van Welie said may eventually “help manage through day-to-day variations but may not be able to charge up again to help when bad weather lasts for multiple days.”

Record-high solar production on April 21 reduced ISO-NE’s net load by more than 2,300 MW at mid-day. | ISO-NE

First Auction Under CASPR

Van Welie said he was pleased with the RTO’s first capacity auction under its Competitive Auctions for Sponsored Policy Resources rules. The February auction made ISO-NE the first grid operator to implement a market-based mechanism to accommodate state-sponsored resources. State-sponsored Vineyard Wind won a 54-MW capacity obligation from a retiring resource in the substitution auction under CASPR.

Forward Capacity Auction 13 cleared at the lowest price in six years, with high levels of new resources, including conventional generators and renewables. Sunrun’s home solar and battery aggregation project became the first in the nation to win a capacity commitment from a grid operator. (See ISO-NE Completes FCA 13 Despite Controversy.)

Van Welie said he expects capacity prices to rise as uneconomical resources retire and declining energy prices — a consequence of increasing renewables with no fuel costs — force generators to seek more revenue from other sources.

ISO-NE’s interconnection queue currently lists more than 150 projects totaling more than 20,000 MW, a level “we’ve rarely seen,” van Welie said. Wind generation represents about two-thirds of the proposed new capacity, more than half of it proposed for offshore. In the past, only about 30% of capacity that enters the queue has come to fruition, however.

Wind power represents almost two-thirds of the proposed capacity in ISO-NE’s generation queue. More than half of the proposed wind is offshore.| ISO-NE

Van Welie said New England states’ increasing renewable portfolio standards are “leading to complexities in market design as well as grid operations, thereby requiring adjustments to both.”

The RTO sees pricing carbon as an “elegant” solution to eliminating out-of-market contracts for renewable resources but has been unable to persuade policymakers to adopt it. “I’ve been a bit of a broken record on this,” said van Welie. He said the Regional Greenhouse Gas Initiative is an “excellent concept” but that its carbon prices are too low to be effective.

Retirements

In June, New England became the first region to price active demand response resources in the daily energy market alongside generators. DR and energy efficiency have been eligible for capacity payments since the start of the capacity market in 2006. In FCA 13, more than 4,000 MW of DR and EE cleared, more than 10% of the total.

Despite the growth in demand-side resources and renewables, however, New England is facing increasing challenges from plant retirements. The retirement of the 677-MW Pilgrim nuclear plant by June “will worsen the region’s energy security risks and its emissions profile,” van Welie said.

ISO-NE says New England states’ increasing renewable portfolio standards are “leading to complexities in market design as well as grid operations, thereby requiring adjustments to both.” | ISO-NE

The region, which will see 5,200 MW of retirements between 2013 and 2022, could face another 5,000 MW of nuclear and coal-fired generation retirements, the RTO says. The region’s nuclear capacity will be reduced to 3,347 MW, with only the Millstone and Seabrook plants remaining.

The RTO is predicting a slight decrease in peak demand over the next 10 years because of EE but says the trend could reverse with the growth of electric transportation and heating. “We don’t expect electric vehicles or heat pumps to have a substantial effect on regional demand in the near future,” van Welie said.

Future Initiatives

Van Welie said the RTO is “facing reality” and does not expect any new gas pipeline capacity. “We have to operate with what we have,” he said, citing more transmission to deliver renewables and imports, and more oil and LNG storage as alternative answers.

Van Welie said the RTO’s Pay-for-Performance incentives, which took effect last June, “may not address all aspects of the region’s winter energy security challenges that have continued to intensify since the incentives were developed.”

Although it provides price signals for resources when the grid is at risk, it does not tell generators of fuel supply shortages days or weeks ahead. “We don’t have a regional fuel gauge that indicates how close we’re getting to the bottom of the fuel tank,” he said.

The RTO’s long-term solution for its winter energy security concerns would expand the current day-ahead market to a multiple day-ahead construct. It will seek to co-optimize its fuel and energy supplies to ride out a seven-day outage of the largest non-gas resource on the system.

“If it’s clear we have more than enough fuel for tomorrow but will run short before the end of the week, resources that can save energy for the end of the week will be properly compensated,” van Welie explained.

It also would include a forward market settlement against the multiday co-optimized market. “The forward market would be seasonal in nature, roughly six months ahead of winter,” he said.

The RTO opened discussions on the proposal in November and plans to provide more details in a white paper in April. It hopes for a FERC filing by November with implementation over three to five years. “This is a very complex project,” van Welie said. “Probably the most complicated thing we’ve done in the history of the ISO.”