FOLSOM, Calif. — The CAISO Board of Governors on Thursday approved a controversial proposal on congestion revenue rights and market power mitigation, changes with major financial implications for its markets.
The changes are a result of the CAISO Department of Market Monitoring’s conclusion that the annual CRR auctions are costing retail electricity customers hundreds of millions of dollars by forcing them to be unwilling partners in losing transactions.
CAISO’s proposal limits CRR sources and sinks to only the combinations needed to hedge congestion costs associated with delivering supply. Auction participants can currently purchase CRRs at generator locations, load locations, trading hubs, pricing nodes, and import and export scheduling points.
Another change establishes a deadline to report transmission outages prior to the auctions to more accurately estimate transmission capacity available for CRR purchases.
The CRR auctions have been highly profitable for financial interests, leading to heavy debate and questioning of CAISO’s logic. That debate continued Thursday, with the broadest consensus being that the board-approved changes, which will be submitted for FERC approval, only partially addressed the situation. The ISO says further alterations to the CRR process are in the pipeline.
“This is a serious issue that has to be fixed,” Chairman David Olsen said as the board unanimously approved the proposal.
Governor Ashutosh Bhagwat said that without voluntary sellers, “it’s not a real market,” and he asked whether CRRs could be handled through bilateral transactions.
“These are not voluntary sellers,” he said of CRRs, “and it’s not working.”
There had been much discussion during development of the proposal over whether it would overly limit legitimate hedging activity. (See CAISO Urged to Take Slower CRR Approach.)
During Thursday’s discussion, CAISO CEO Steve Berberich responded to the criticism by saying that CRRs are a valid market tool. But “this is a watershed moment for this organization to send a message … and that is, we agree the current situation has to change,” he said.
By the Monitor’s calculations, the CRR auction has had a $750 million deficiency for retail ratepayers, and annual deficiencies will grow in 2018 under the current structure. The Monitor did not support the changes and said the auction should be based on “willing buyers and sellers” and that more fundamental flaws should be addressed.
CAISO Approves Bidding Rule Changes
The board also approved CAISO’s Commitment Cost and Default Energy Bid Enhancements (CCDEBE), another contentious proposal that is opposed by some investor-owned utilities.
The proposal replaces a static commitment cost bid cap with a local market power mitigation test, which identifies whether a resource needs to be committed to relieve a transmission overload or other constraints. The ISO will only mitigate bids when a generator fails the test.
The Energy Imbalance Market (EIM) Governing Body earlier this month gave advisory approval of the changes, subject to a condition that staff brief it and the CAISO board at the 12-month point following implementation of the changes. (See EIM Governing Body Approves CAISO Bidding Flexibility.) The ISO has been developing the proposal since last year to address what is said to be inadequate cost recovery for generators.
Under the current rules, bids are capped at the generator’s reference level, which is determined by multiplying costs — based on published natural gas price indices — by 125%.
CAISO recently adjusted the proposal by lowering the proposed multiplier for the first 18-month period after implementation to 150% from 200%. The ISO plans to phase in commitment cost bidding flexibility, first raising the commitment cost multiplier to 150% for the first 18 months, and then increasing it to 300% if no issues arise.
Pacific Gas and Electric wants CAISO to maintain the existing 125% cap, saying CCDEBE will have limited benefits. NRG Energy said the proposed caps are too low.
Board Approves Transmission Plan
The board on Thursday also approved the ISO’s 2017-2018 transmission plan, which cuts $2.7 billion from previously approved projects. The plan outlines the proposed design and construction of 17 new projects costing about $271 million. It recommends cancellation of 18 projects and revises 21 others in PG&E’s service area, and two in the San Diego Gas & Electric territory.
The main reasons for the reductions were changing load forecasts, energy efficiency improvements and increased residential rooftop solar systems. (See CAISO Recommends $2.7 Billion Tx Spending Cut.)
The approval will be used to launch the next planning phase, as it is plugged into the California Public Utilities Commission transmission procurement plan for utilities. The process will determine eligibility for incentive rate cost recovery from FERC by virtue of being part of a state plan.
FERC has cleared an ITC Holdings subsidiary to buy nearly a quarter million dollars’ worth of transmission assets from a Michigan municipal power agency as part of a settlement over transmission system access.
The $247,225.99 sale of transmission assets in southern Michigan from Michigan South Central Power Agency (MSCPA) to Michigan Electric Transmission Co. (METC) is consistent with public interest, FERC said on Monday (EC18-35).
The sale satisfies part of a settlement approved by the commission last year after a 2016 MSCPA complaint alleging METC was trying to restrict the agency’s ownership entitlements to the transmission system and improperly collect annual payments as high as $1.7 million for transmission use, in violation of a contract struck in 1980. METC’s change to the contract’s terms was prompted by the 2016 retirement of MSCPA’s 62-MW Endicott Generating Station.
Endicott Generating Station | MSCPA
FERC said the transmission sale will have no impact on rates or competition. METC also committed to hold customers harmless from any costs related to the sale.
FERC last week approved an uncontested settlement between SPP and several of its members to add an annual revenue requirement and implement a formula rate template and protocols for a new member (ER17-428).
The settlement resulted from SPP’s 2016 filing that amended its Tariff governing transmission facilities owned by Vermillion Light & Power (VLP). The changes concerned VLP’s base rate of return on equity, payment in lieu of taxes, plant depreciation rate, payment of refunds dating back to Feb. 1, 2017, with interest, and other related adjustments.
VLP, which is owned by the town of Vermillion, S.D., is a member of Missouri River Energy Services (MRES).
Vermillion, S.D.
MRES and VLP said the settlement included three concessions: a 10-basis-point reduction from the as-filed base ROE of 9.7% to a settlement base ROE of 9.6%; an agreement that VLP is prohibited from seeking a change in the ROE until March 1, 2020; and a provision requiring VLP to make a Section 205 filing to participate in certain regionally cost-shared projects.
SPP filed the settlement offer in December on behalf of itself; MRES; Basin Electric Power Cooperative; East River Electric Power Cooperative; Heartland Consumers Power District; Mountrail-Williams Electric Cooperative; and the Western Area Power Administration.
FERC last week also approved an uncontested settlement between NextEra Energy Transmission Southwest (NEET Southwest) and the Kansas Corporation Commission over the company’s base ROE (ER16-2720).
The Missouri River | American Rivers
FERC accepted NEET Southwest’s base ROE of 9.8% to recover costs associated with the transmission assets it develops in SPP. The company’s total ROE, including incentives and adders, will not exceed 10.8%.
NEET Southwest had requested a base ROE of 10.5% with a 50-basis-point incentive adder in 2016, but the Kansas commission protested the ROE portion of the filing.
FERC last week rejected state and local regulators’ rehearing request over MISO’s plan to include its South region in cost sharing for its new category of interregional projects with PJM.
The commission on Monday said it was not convinced by the regulators’ reasoning for rehearing MISO’s planned regional cost allocation on its targeted market efficiency projects (TMEPs), a new, smaller breed of interregional project developed with PJM that targets historical congestion along the RTOs’ seams (ER17-2246-002).
All based in MISO South, the regulators — the Arkansas, Louisiana and Mississippi public service commissions; New Orleans City Council; and the Public Utility Commission of Texas — argued that the RTO’s filing was flawed because it had not named a termination date of the TMEP regional cost-sharing proposal when Entergy’s five-year transition period that limits cost-sharing in the region ends in December.
By that time, MISO has promised to have a comprehensive post-transition period cost allocation proposal filed with FERC. The RTO has been working with stakeholders on a preliminary proposal that would make cost sharing available to 100-kV projects along the PJM and SPP seams but limit it to internal market efficiency projects of 230 kV and above. (See Stakeholders Debate MISO Cost Allocation Plan.)
The regulators wanted assurances that MISO’s TMEP regional cost-sharing plan would not apply beyond the transition period or to MISO South. When it approved the plan late last year, FERC said that if MISO does not have a cost allocation plan readied as promised, the regional TMEP cost allocation would continue to be in effect even after the transition period expires. The RTO proposed to assign its regional share of the costs of TMEPs to transmission pricing zones based on their historical contribution to the market-to-market congestion relieved by the project.
The regulators said FERC’s decision improperly modified MISO’s proposal, citing the D.C. Circuit Court of Appeals’ 2017 ruling that the commission overstepped its authority in prescribing revisions to PJM’s minimum offer price rule. (See On Remand, FERC Rejects PJM MOPR Compromise.)
However, FERC said the MISO South regulators did not have a case for rehearing because they could not prove its decision had caused a concrete injury, or “aggrievement.” TMEP costs could be assigned to MISO South once the transition period expires, FERC acknowledged, but it also said that it was not clear a “mere potential for future harm” is substantial enough to amount to aggrievement.
| MISO
FERC also said MISO has already outlined a plan for if it does not follow through on a finalized comprehensive cost allocation. In that case, certain projects included in the annual Transmission Expansion Plan, including TMEPs, will be subject to the RTO’s existing cost allocation Tariff language.
“Commission precedent is clear: In the event of a conflict between pleadings and proposed tariff language, the tariff language controls,” FERC said.
The commission also disagreed with the regulators’ contention that by specifying that MISO’s plan could continue past the transition period expiration, it “transform[ed] the proposal into an entirely new rate of FERC’s own making.” It noted that MISO has committed to filing a new regional cost-sharing method for assigning MISO’s share of the costs of TMEPs prior to the end of the transition period.
“While we understand MISO South regulators’ desire for certainty regarding future assignment of MISO’s share of the costs of TMEPs, MISO has provided no indication that it intends to deviate from the commitment in its pleadings to convene stakeholder proceedings to develop a post-transition period proposal,” FERC said.
MISO and PJM’s TMEP portfolio, approved last year, comprises five congestion-relieving interregional upgrades to existing systems in Illinois, Indiana, Michigan and Ohio. The projects, which have individual $20 million cost caps, will coincidentally cost $20 million combined. On average, the projects’ costs will be allocated 69% to PJM and 31% to MISO, based on projected benefits, which are expected to reach $100 million. (See FERC Conditionally OKs MISO-PJM Targeted Project Plan.)
Three top generators in Maine have asked the state’s Public Utilities Commission to allow them to intervene late as full parties in the proceeding on New England Clean Energy Connect (NECEC), the 1,200-MW HVDC transmission line proposed by Central Maine Power (CMP) and Hydro-Quebec.
The 145-mile project before the PUC (2017-00232) would deliver Canadian hydropower from Quebec to Lewiston, Maine, at an estimated cost of $950 million. CMP is a subsidiary of Avangrid.
Lewiston substation | Central Maine Power
Massachusetts last month selected NECEC as the alternative for the state’s 9.45-TWh clean energy solicitation after the New Hampshire Site Evaluation Committee (SEC) unanimously rejected Eversource Energy and Hydro-Quebec’s Northern Pass, the 1,090-MW transmission project that the Bay State had awarded the contract just a week earlier. (See Mass. Picks Avangrid Project as Northern Pass Backup.)
Survival Mode
Generators Calpine, Dynegy and Bucksport Generation, owners of one-third of the installed electric generating capacity in Maine, told the PUC that awarding a certificate of public convenience and necessity to NECEC would threaten their plants’ economic survival and harm the region’s competitive wholesale power market.
New England Clean Energy Connect (NECEC) shown in orange | Central Maine Power
The PUC plans to issue a decision on the proposal by September, a year after CMP filed, which is standard procedure. Maine Gov. Paul LePage and his Energy Office both wrote letters to the PUC urging it to review CMP’s petition in an “expeditious manner” and not delay or suspend the proceeding.
CMP on March 23 responded and said they did not object to the late‐filed intervention — if the PUC prohibits the intervenors from reopening phases of the case that have already closed.
The generators “seek to entirely reset the clock in this matter and introduce intervenor testimony in utter disregard of the fact that the commission and the parties are six months into a 12-month case schedule, the period for intervenor discovery on CMP’s initial petition has closed, and the deadline for intervenor testimony has passed, not once, but two times,” CMP said.
The generators argued that the developer presented reduced wholesale energy and capacity prices in the region and in Maine as the primary benefit of the project and made no case for reliability benefits.
However, CMP did just that in its September 2017 filing: “In addition to the electricity price suppression, [greenhouse gas] reductions and employment and economic development benefits discussed above, the NECEC transmission project will provide Maine resource adequacy and transmission system reliability benefits at no cost to Maine customers.”
CMP argued in its initial filing that “transmission upgrades to permit an additional 1,200 MW of generation to interconnect” ensures that NECEC’s power “will be deliverable to the New England Control Area. The addition of this non-natural gas-fired capacity (and related energy) will help ensure that ISO-NE has adequate generation resources available to meet load and reserve requirements throughout the year, including especially during periods when natural gas supplies are constrained.”
The intervening generators said “it is abundantly clear that the integration of large-scale, out-of-market (i.e., subsidized) resources within the current ISO-NE market may have profound unintended consequences, which is evidenced by the extensive and challenging stakeholder discussions during the [New England Power Pool’s Integrating Markets and Public Policy] debate and subsequent NEPOOL and FERC-related reviews of proposed capacity market reforms.” (See CASPR Filing Draws Stakeholder Support, Protests.)
Impeding Renewables
Massachusetts issued its MA 83D solicitation for hydro and Class I renewables (wind, solar or energy storage) last July. The selection committee for the clean energy request for proposals issued in July 2017 includes representatives from the state’s Department of Energy Resources and from distribution utilities Eversource, National Grid and Unitil.
Calpine owns and operates the 552 MW natural gas-fired Westbrook Energy Center power plant in Maine. | Calpine
Any contract awarded under the RFP must be negotiated by March 27 and submitted to the state’s Department of Public Utilities by April 25. The New Hampshire SEC voted March 12 to wait until its Northern Pass permit denial is published later this month before considering Eversource’s appeal of that decision, effectively killing the project’s chance to meet the Massachusetts deadline.
The New England generators told the Maine PUC that they “had good cause for delaying their intervention efforts” in that NECEC had been one of more than 40 bids competing to secure the Massachusetts contract and that “it would have been highly impractical for the [generators] to intervene in siting and/or certificate proceedings for every one.”
“At the time, it was widely believed that Eversource Energy, as a member of the state’s evaluation team, would favor its own affiliate’s project, Northern Pass Transmission in New Hampshire, as subsequently proved to be the case,” they said.
The generators also questioned the claim that NECEC will lead to lower prices.
“It is abundantly clear that [NECEC] has been proposed solely to meet a Massachusetts policy goal; it has nothing to do with meeting the needs of Maine ratepayers, and the primary long-term benefits of the project will accrue to Hydro-Quebec and CMP shareholders,” they said.
The generators further argued that, should the project go forward, “it will impede the development of alternative renewable energy projects in Maine, such as solar and onshore and offshore wind farms, for the foreseeable future. This result would be contrary to Maine’s statutory policy favoring the use of ‘renewable, efficient and indigenous resources.’”
The Conservation Law Foundation filed comments asking the PUC to wait until the Massachusetts RFP has been decided before considering the NECEC proposal.
The CLF argued that presumption of the project’s selection in the state RFP underlies CMP’s cost analysis. It also said CMP’s “calculations of benefits including greenhouse gas emission reductions, improvements in system reliability, reductions in electricity prices, and employment benefits … are premised on a baseline scenario in which there is no other project selected in the Mass. RFP.”
MISO is surveying how to get more information from load-serving entities to create a more detailed load forecast for transmission planning, though stakeholders continue to question the feasibility of the plan.
MISO Senior Policy Studies Planner Temujin Roach said the RTO wants to try “bottom-down” load forecasting, where it relies on data compiled from LSEs to form the basis of its load forecast that informs transmission buildout. For that, MISO’s 140-plus LSEs will have to annually assemble four different 20-year load forecasts to fit with each of the RTO’s four future scenarios developed for the Transmission Expansion Plan. (See MISO Looks to Align Load Forecasting, Tx Planning.)
The approach is one of two MISO is vetting to improve its load forecasts. If LSEs decide they cannot collect that level of information, the RTO will continue its practice of hiring a contractor to put together a load forecast. In that case, Roach said the level of specificity would not be as detailed, though the contractor would take any load information LSEs provide on a voluntary basis. MISO currently uses Purdue University’s State Utility Forecasting Group to create an independent load forecast; the forecast is not based on any of the MTEP future scenarios.
| Purdue University
MISO has a survey out until April 12 asking LSE owners how feasible it is to put such forecasts together and how much it may cost LSEs to assemble detailed load data.
“For some, it’s negligible so far, and for others, it may be a burden,” Roach said during a special March 21 conference call on improving MISO’s load forecast.
“What we’re looking for from load-serving entities is if this is information they already have, or if they’re willing to provide it,” Roach added.
Stakeholders asked what share of LSEs had to participate in the forecasting before MISO would pursue the new approach. Roach said he didn’t know.
“We’re looking for a feel of who has got problems with it and how feasible it is — most specifically it’s the small munis and co-ops that might not have the ability to forecast already in place. … We’d be willing to work with them and make this as painless as possible,” Roach said. “I don’t have an answer. It depends on who is struggling with it, and how big their loads are. We need more information to make … a prudent decision.”
Stakeholders Skeptical
Several stakeholders said they still weren’t convinced MISO had put enough thought into how it would align 140-plus disparate data sets into a cohesive load forecast.
Minnesota Public Utilities Commission staff member Hwikwon Ham said that LSEs don’t understand how MISO expects them to adapt their base-case loads to fit into the “limited fleet change,” “continued fleet change,” “accelerated fleet change” and “distributed and emerging technologies” MTEP futures.
Roach said MISO would most likely hold workshops and develop a Business Practices Manual to describe how to approach the data.
“I’d like to hitch onto [the] exasperation,” said WPPI Energy’s Steve Leovy. “I don’t know how to provide what MISO is asking, because I don’t think the data question is adequately specified. I don’t think multiple LSEs have the same idea about it.”
While MISO is under budget so far in 2018, the RTO’s financial staff is forecasting a slight overspend by year-end, members of the Audit and Finance Committee of the Board of Directors learned Wednesday.
In the first three months of 2018, MISO has spent $41.5 million of its $42.3 million year-to-date budget, under budget by 1.8%. Chief Financial Officer Melissa Brown said the savings were mostly related to belated start times of some of MISO’s planned investments.
“A lot of those just had slow starts this year,” Brown said during a committee conference call ahead of a March 29 board meeting in New Orleans, where numbers will again be presented.
However, Brown said MISO is forecasting spending $266.8 million by year-end, 0.7% more than its $264.9 million 2018 budget. The expected overspend is because MISO is reclassifying $1.6 million from its capital budget into one-time operating expenses. The reclassification will lower the RTO’s projected total capital expenses from $29.6 million to $28.1 million for the year.
| MISO
So far this year, MISO’s capital spending is trending lower, also owing to delayed project starts, Brown said. To date, the RTO has spent $6.1 million of its $7.3 million budget.
In addition to beginning work to replace MISO’s aging market platform with a new modular computer system, the 2018 capital budget includes maintaining its cybersecurity team, automating employee system access revocations, automating its settlements program, replacing software and hardware that fails throughout the year and renovating meeting space at the Carmel, Ind., headquarters.
Board Chairman Michael Curran asked in future meetings to see a separate financial report for MISO’s $130 million, seven-year effort to replace its market platform. (See MISO Makes Case for $130M Market Platform Upgrade.)
A wide range of stakeholders filed comments this week requesting clarification or rehearing of FERC’s Order 841 requiring RTOs and ISOs to revise their tariffs to allow energy storage resources full access to their markets (RM16-23).
While their concerns included specific cost and billing issues, most comments focused on the high-level interaction between federal and state oversight in energy markets and argued that the order had overstepped FERC’s authority. (See FERC Rules to Boost Storage Role in Markets.)
Implementation Issue
Subsidiaries of AES, including Indianapolis Power & Light, requested clarification that the order — which doesn’t require implementation for nearly two years — doesn’t supersede MISO’s compliance requirements in response to IPL’s 2016 complaint that its 20-MW battery was being denied market participation despite its capability. That implementation is already underway. (See MISO Rules Must Bend for Storage, Stakeholders Say.)
Invenergy’s 31.5 MW Grand Ridge Energy Storage project | Invenergy
Otherwise, AES requested a rehearing to determine ways “to help alleviate in the interim” the conditions Order 841 is supposed to correct. It argued that “the commission simultaneously predicated participation of … electric storage resources on dispatchability, which … completely fails to recognize the physical and operational characteristics of electric storage resources like” IPL’s, which “can provide their services automatically, without a need for direct interface with RTO/ISO dispatch software at all.”
FERC required RTOs/ISOs to submit compliance filings detailing how they will implement the order by Dec. 3, with implementation finished a year after they file. MISO asked for a six-month extension of the implementation deadline to accommodate distributed energy resource issues that are still pending.
“Granting the requested clarification, or rehearing, will help ensure that an RTO/ISO has sufficient flexibility to design and implement [a storage] market participation model that is technically and operationally feasible in each RTO/ISO’s specific context,” MISO said.
The RTO also asked for clarification about how the 100-kW minimum threshold for resource participation should be calculated, noting that giving grid operators flexibility in how they handle charging and discharging limits “can avoid unnecessarily limiting the range for clearing energy or reserve products.” It also requested the ability to phase in the number of very small resources that can participate each year “to avoid an unmanageable influx.” Grid operators should also be allowed to require storage resources to comply with rules necessary to address any reliability impacts that distribution utilities identify, MISO said.
Finally, the RTO requested confirmation that three potential bidding parameters are acceptable:
Requiring storage units to provide their state-of-charge forecasts at the beginning of identified market intervals, such as day-ahead, five-minute and real-time.
Requiring storage units that don’t provide minimum limits and can be moved smoothly between negative and positive to submit a single hourly ramp rate for the day-ahead market and “look-ahead commitment” process, or alternatively applying MISO’s real-time security-constrained economic dispatch practice if appropriate.
Requiring units that use their state-of-charge to lock output to a narrow range to be treated as self-scheduled price-takers that can’t set prices because they are potentially unable to fulfill capacity obligations, provide ramp products or perform ancillary services.
EEI’s Issues
The Edison Electric Institute requested clarification or rehearing on whether relevant electric retail regulatory authorities (RERRAs) would have the ability to opt in or out of allowing distribution-connected resources from participating in wholesale markets because their participation “has significant implications for the operation and reliability of the distribution system.”
EEI pressed FERC on how rates should be calculated, arguing that in situations where storage is paired with a retail load behind a single retail meter, the storage should either pay for any costs to separately measure the retail and wholesale loads or the entire load should be treated as retail. The institute said that storage must still be required to “pay any applicable charges covered under state jurisdictional tariffs in order to adequately reflect their use of state jurisdictional facilities.” It also disliked the 100-kW threshold, fearing that an “influx of smaller resources” could create administrative, reliability and cost issues.
DER Technical Conference
Finally, EEI said rules developed through the separate technical conference that FERC ordered on DER aggregation (RM18-9, AD18-10) should also apply to any storage resources covered by Order 841 “to ensure consistency.”
Several organizations representing public power filed a joint request asking for the same, adding that any RTO/ISO tariff revisions regarding Order 841 not become effective until after rules from the technical conference are developed.
RERRA Clarifications
Like many other commenters, the public power organizations — which include American Municipal Power, the American Public Power Association and the National Rural Electric Cooperative Association — also focused on state and local authority and requested FERC include an opt in/out mechanism for RERRAs.
“The commission should … unequivocally state that [its] regulations … do not authorize an [energy storage resource] to violate state or local laws or regulations or contract rights governing retail electric service or the local distribution of electric energy,” the organizations wrote.
Pacific Gas and Electric asked for clarification that “nothing in Order 841 is intended to suggest that the state no longer has jurisdiction to determine how power flowing from the distribution grid, through the customer meter and then into the storage resource located behind the customer meter is to be split between retail consumption and wholesale charging for later discharge into the wholesale markets.”
Sodium sulfur battery storage facility at Pacific Gas and Electric’s Vaca-Dixon substation. | California Energy Commission
The company warned that “if the commission were to conclude that the state no longer has this authority, then a retail customer could use its behind-the-retail-meter storage resource as a means to completely bypass retail rates for its onsite electricity consumption. The customer could simply claim that all electricity flowing through his/her retail meter went into the storage device for later discharge into the wholesale markets, even if the power were never returned to the wholesale market but instead used to meet on-site electricity demand.”
The Organization of MISO States reiterated the request to “clearly” acknowledge “applicable state and local laws, and applicable orders and rules” of RERRAs, disqualify resources that don’t comply with those rules and develop a process to confirm that compliance.
The National Association of Regulatory Utility Commissioners filed similar requests, warning FERC to “be careful that its actions do not inhibit or conflict with authority Congress specifically reserved to NARUC’s state commission members.” The association took issue with wording in the order that barred states from deciding whether distribution-level storage in their jurisdiction can participate in wholesale markets, which it said should be eliminated.
“FERC has exclusive jurisdiction over the wholesale markets and the rules that apply to resources participating in those markets, including how such resources participate,” the association said. “Nonetheless, Congress assigned states the task of determining whether resources located behind a retail meter or on the distribution system can, in the first instance, participate in wholesale markets.”
Xcel Energy Services, filing on behalf of its four utility affiliates in Minnesota, Wisconsin, Colorado and the Southwest, expressed concern about many of the same issues other stakeholders addressed, including: not providing states with an opt-out option; complications around separate metering for wholesale and retail activity; flexibility in developing an implementation schedule; allocation of integration costs for storage resources; and the inability to institute rules for storage to address reliability issues.
Market Exclusivity
The Transmission Access Policy Study Group (TAPS) noted the RERRA opt-out issue, but it also argued that FERC erred in rejecting the group’s proposal that storage resources be required to choose exclusive participation in either wholesale or retail markets.
“To avoid market manipulation, prohibited resales of energy purchased at retail and prohibited end-use consumption of energy purchased at wholesale, distributed storage resources [should] be required to make a binding choice to participate exclusively either in the wholesale markets or at retail,” TAPS said.
Grid Operator Responsibility
CAISO requested that FERC clarify several points about grid operators’ responsibilities, including that someone — although not grid operators — must directly meter storage resources, that grid operators can require storage resources to resolve retail double-billing issues with their retail energy provider as a condition of wholesale market participation, and that storage resources not incur transmission charges when they are dispatched to charge up because they’re performing a service.
Other Clarifications
Several organizations also sought separate clarifications of the order. PJM requested confirmation that the order “does not mandate a particular methodology” for accounting for “the physical and operational characteristics” of storage resources. The California Energy Storage Alliance requested clarity on “when and why transmission charges should apply to wholesale energy purchased for later resale in the same area” because potential “double-billing would be unduly and financially burdensome to the usage of energy storage and unreasonable in the application of the cost allocation and recovery for transmission charges.”
A CAISO official revealed Tuesday that a generation owner has approached the ISO about seeking a 2019 reliability-must-run contract, a development likely to sharpen an ongoing stakeholder debate about the out-of-market payments.
Keith Johnson, CAISO infrastructure and regulatory policy manager, acknowledged the generator’s request in response to a series of questions during an hourslong stakeholder meeting that at times became slightly charged as market participants delved deeply into the ISO’s backstop energy procurement policies.
Generation owners typically inquire about an RMR when they are considering shutting down a unit and want to know if it might be eligible to receive one of the increasing number of contracts the grid operator has been inking in recent years to keep gas-fired plants available for reliability reasons.
Stakeholders have questioned whether retirement notifications and subsequent discussions between generation owners and CAISO should remain confidential or be announced immediately. In response, the ISO is working on rule changes that would allow it to provide the public early notification of unit retirements under different scenarios.
The notification changes are included in “Phase 1” of a broader set of RMR and capacity procurement mechanism (CPM) changes that CAISO is developing. Another primary component of the program is a must-offer requirement for RMR units that will “look, feel and act more like resource adequacy,” Johnson said.
| CAISO
The ISO on March 13 issued its draft final proposal for Phase 1, with the goal of getting approval from the Board of Governors in May, in place for fall contracting for the 2019 operating year. Comments are due April 10 on the proposed rule changes, a topic of a similarly pointed stakeholder session last month. (See CAISO, Stakeholders Debate RMR Revisions.)
CAISO has received plenty of feedback about including more RMR/CPM reforms in Phase 1, but Johnson told stakeholders Tuesday that “we are avoiding shoehorning stuff in there that can’t be adequately vetted with you.”
More comprehensive RMR/CPM refinements are being considered for a later Phase 2, CAISO said in a presentation during the meeting. Thirteen items are up for discussion for the second phase, including more clarification regarding the differences between RMR and CPM, and whether the two programs can be merged into one procurement tool.
Additionally, CAISO had already developed and submitted a package of RMR changes to FERC, which it said it expects to be approved on April 12.
RMR critics — which include the California Public Utilities Commission — say the growing need for the contracts points to market deficiencies that call for broader reforms across the market. The commission replaced a previous set of CAISO-approved RMRs with energy storage. (See CPUC Retires Diablo Canyon, Replaces Calpine RMRs.)
NRG Energy subsidiary GenOn recently notified the commission that it plans to retire three gas-fired plants by early next year, possibly setting them up for RMRs. (See NRG Set to Retire California Gas Plants.)
Citing FERC’s concerns over supplemental transmission projects, Kentucky regulators have rejected upgrades to two substations, ruling that Kentucky Power failed to prove they were needed.
The Kentucky Public Service Commission released an order on March 16 granting a certificate of public convenience and necessity (CPCN) to Kentucky Power for a baseline project to rebuild a 161-kV line between its Hazard and Wooton substations but denied a CPCN for a more expensive supplemental project to make upgrades at the substations. Kentucky Power, a subsidiary of American Electric Power, estimated the baseline project to cost $20 million and the supplemental project another $24 million.
| PJM
Baseline projects are administered by PJM to address violations of publicly available reliability criteria, while supplemental projects are developed internally by transmission owners and are not driven by RTO criteria. Supplementals are included with baseline projects in PJM’s Regional Transmission Expansion Plan to allow staff to identify possible reliability or operational performance issues, but they are not subject to staff oversight or approval. For years, several organizations representing demand-side interests have been clashing with TOs over the projects, arguing that TOs are incentivized by their formula rates to build as much as possible and that regulators’ oversight is not adequate to corral the impulse. Spending on supplementals has been on the rise, and critics believe TOs see them as an unsubstantiated way to build more. (See PJM TOs, Customers Await Ruling on Supplemental Projects.)
The PSC was unpersuaded by Kentucky Power’s contention that the supplemental made sense because engineering and construction resources would already be focused in that area. “This may speak to efficiency but not to necessity,” the commission said, noting that consideration of the projects happened through a PJM stakeholder process that FERC has since determined requires revision.
FERC ruled in February, following a 2015 technical conference and subsequent show-cause order in 2016, that TOs’ processes for receiving “meaningful input” from stakeholders on supplemental projects need additional structure to comply with Order 890 (EL16-71). TOs, through PJM, have subsequently submitted a proposed timeline for project consideration, but opponents have challenged the order as not sufficient. (See Group Contests ‘Supplementals’ Ruling as PJM, TOs Advance.)
