CARMEL, Ind. — History repeated itself during this month’s extreme cold snap — but only to a degree, MISO told stakeholders last week.
While the high load and generation outages during the arctic blast followed the pattern of 2014’s so-called “polar vortex,” this time the RTO managed to keep prices stable and maintain better reliability.
Tim Aliff, MISO director of system operations, said the RTO dubbed the weather event with a simple nickname.
“The best we could come up with was ‘cold snap,’” Aliff joked at Thursday’s Market Subcommittee meeting. “It doesn’t inspire the terror that ‘bombogenesis’ does, and ‘polar vortex’ was already taken.”
Aliff said that while there were major similarities between the polar vortex and last week’s artic conditions, MISO’s response to the demand and ensuing prices were very different, ensuring the RTO’s conservative operations declaration did not escalate to a maximum generation alert.
The recent low temperatures persisted longer and were on average lower than during the polar vortex, although the coldest day during 2014’s events was about 2 degrees Fahrenheit lower than this month’s. Demand peaked at 104.7 GW on Jan. 2, when low temperatures in the footprint averaged 0 F. During the polar vortex, MISO load hit an all-time winter peak of 109.3 GW on Jan. 6, 2014, when lows averaged minus 2 degrees.
Load topped 100 GW on five days during the recent cold snap, compared with two days during the polar vortex.
Polar Vortex (2014) compared to 2018 cold snap | MISO
“We were on average about 10 degrees colder than in 2014,” Aliff said.
This year’s arctic blast was tempered in part by wind’s 13% contribution to the resource mix, supplying 13.4 GW during the Jan. 2 peak hour. In 2014, wind supplied 6.6 GW during the peak.
“The highest locational marginal price was significantly lower than in 2014,” Aliff said. Real-time LMPs hit $281.23/MWh during the peak, compared with the $1,780.70 record price seen in 2014. During the bitter cold on Jan. 1 and 2, gas prices held to $4.63/MMBtu, jumping to $9 a day later when temperatures increased by 13 degrees. In 2014, gas prices ranged between $5.88 and $7 during three straight days of punishing cold.
Outage levels on the most frigid day remained at levels typical for the month of January, Aliff said, accounting for about 36 GW of unavailable generation during the peak, including more than 19 GW of forced outages. Natural gas forced outages, mostly attributable to fuel transportation and supply issues, accounted for almost 7 GW of unavailable generation, while equipment failure in coal generation accounted for slightly more than 2 GW of forced outages.
“That is kind of expected at this time of year. The utility gas supply is competing with the residential gas supply,” Aliff explained. MISO was better prepared for outages this year and was equipped with a more accurate list of gas-fired generators most likely to be affected by a dwindling gas supply.
“We had a better picture of what the generation limitations would be,” he said.
Ameren’s Jeff Moore asked if greater wind production helped MISO fare better during the cold snap.
“I think that there’s a lot that went into the lower LMPs,” Aliff replied. Other improvements made since the polar vortex, especially gas-electric coordination, helped MISO’s performance, he added.
MISO staff at the meeting promised to provide more outage analysis and data collection on the event.
Stakeholders: More Real-Time Communication
Multiple stakeholders asked MISO to consider issuing more immediate updates to members as it navigates challenging conditions.
ITC Holdings’ Ray Kershaw led the charge, asking that MISO distribute more real-time electronic communication to its members when faced with near-emergency or emergency conditions.
Market Subcommittee Vice Chair Megan Wisersky said there was a marked difference between MISO’s sparse communication and PJM’s frequent email updates to its members on the state of its system during the cold snap. “It seemed like there was a little bit of an information gap between the two approaches,” she said.
“It’d be nice to know what the capacity breakdown is,” said Customized Energy Solutions’ David Sapper.
Indiana Utility Regulatory Commission staffer Dave Johnston pointed out that, sometimes, “no news is good news.” He noted that MISO does alert state regulators when reliability issues arise. “But, of course, I’m not a market participant, and I’m not watching prices,” Johnston said.
MISO Senior Director of Systemwide Operations Rob Benbow said the RTO would consider the request and determine what information it could release in real time. “We understand the importance of good communication,” he said.
“Good markets are run with better information,” Wiskersky said.
November Sees Boost in Load, Prices, Wind
MISO released a November market report showing that lower temperatures that month boosted average load to 71.6 GW, up 3.6 GW from a year earlier, while the monthly peak jumped by 2.5 GW to 84 GW. Real-time and day-ahead energy prices both averaged about $27.30/MWh, 10% higher than last November. MISO reported an all-time wind record of 14.6 GW on Nov. 21, only to be exceeded by a new high of 14.7 GW on Dec. 5.
MISO and PJM will decide this spring whether to take another shot at a two-year coordinated system plan, which could result in the RTOs’ first large-scale interregional project.
The grid operators’ Joint RTO Planning Committee will make a decision by May 18 after discussing the issue at a March 30 meeting of the Interregional Planning Stakeholder Advisory Committee.
MISO and PJM staff last year already exchanged information on regional issues, market-to-market congestion, interconnection requests and newly approved projects near the RTOs’ seam. Those details should help the joint planning committee — comprising MISO and PJM planning staff — decide whether to pursue the study, MISO interregional adviser Adam Solomon said during a Jan. 12 IPSAC conference call.
The RTOs are calling on stakeholders to email a list of seams issues by Feb. 28 for the March IPSAC meeting. According to their joint operating agreement, the two grid operators then have 45 days to announce a decision on pursuing a plan.
The RTOs’ last coordinated system plan concluded in the fall without producing a viable interregional market efficiency project. One serious contender, a proposed 30-mile, 138-kV line near the Indiana-Illinois border, ultimately failed the joint 5% generation-to-load-distribution factor test, which requires each RTO to show that at least one of its generators has at least a 5% impact on the affected flowgate. (See MISO, PJM Reverse Support for Lone Interregional Tx Project.) Interregional market efficiency projects also must meet a 100-kV minimum voltage threshold and a 1.25-to-1 benefit-to-cost ratio based on each RTO’s expected share of the project’s total benefits.
Staff vowed to collaborate on ways to improve the coordinated system plan process after the study was concluded.
At EUCI’s Transmission Expansion in the Midwest conference in December, several stakeholders and panelists said that an effective wind transmission network in the Midwest will eventually require large-scale interregional projects. (See EUCI Panelists: Midwest Tx Plans Must Address Wind, Seams.)
Regardless of the outcome of the coordinated plan, the proposal window for interregional market efficiency projects — required under FERC Order 1000 — opens in November 2018. Stakeholders have until February 2019 to submit project suggestions.
Bidders in ISO-NE’s capacity auctions would face a lower price threshold for triggering market power reviews under a Tariff revision filed by the RTO on Monday.
ISO-NE and the New England Power Pool Participants Committee filed with FERC to decrease the dynamic delist bid threshold (DDBT) in the RTO’s Forward Capacity Market from $5.50/kW-month (set in 2014) to $4.30/kW-month, starting with Forward Capacity Auction 13, slated for February 2019 (ER18-620). The DDBT is an administrative threshold established by the Internal Market Monitor for use in determining which capacity market bids from existing resources must be reviewed for the potential exercise of seller-side market power in the FCM.
| ISO-NE
The change reflects the Monitor’s estimation of the likely marginal bid in the auction. ISO-NE said changes in supply-and-demand dynamics since 2014 warrant the decrease in the DDBT. Four years ago, the Monitor projected a capacity shortage of more than 1,600 MW, but since then, existing capacity has increased each year while the installed capacity requirement has consistently declined. For next month’s FCA 12, the Monitor projects a capacity surplus of about 1,250 MW.
If the DDBT is set appropriately, bids below the threshold will be considered “infra-marginal” — that is, priced below the auction clearing price and therefore unable to exercise market power.
| ISO-NE
The Monitor aims to set the DDBT slightly below the likely competitive price from the marginal resource in the FCA to minimize the likelihood of an uncompetitive bid setting the clearing price. If the DDBT is set too high and the auction clears below the threshold, all remaining delist bids enter the auction without having been reviewed for the potential exercise of market power.
In its testimony in the filing, the Monitor explained the adverse consequences of setting the DDBT too high.
“Since the ISO makes known … the amount of remaining supply at the start of each auction round, suppliers with market power within the dynamic range of the auction may be able to profitably increase the auction clearing price to benefit their supply portfolio,” the Monitor wrote. “Furthermore, the impact of an uncompetitive increase in the auction clearing price is not localized to the individual supplier that exercises market power; the clearing price is artificially inflated for the entire capacity zone or the entire system.”
But the Monitor said there are no corresponding adverse consequences for the auction if the DDBT is set well below the price of the marginal bid.
“While doing so may result in more suppliers carrying the administrative burden of submitting delist bids for IMM review prior to the auction … this burden is not unreasonable when compared with the significant risk to the competitiveness of the auction from setting the DDBT too high,” it said.
CARMEL, Ind. — MISO’s next capacity auction will likely rely on megawatt values and limits similar to those underpinning last year’s auction, the RTO said Wednesday.
For the 2018/19 Planning Resource Auction scheduled for early April, MISO is planning for a systemwide coincident peak load of nearly 122 GW ― a 42-MW decrease ― and a planning reserve margin requirement of 135 GW, which is 177 MW higher, Tim Bachus, MISO capacity market administration analyst, said during a Jan. 10 Resource Adequacy Subcommittee meeting.
The RTO also forecasts a zonal coincident peak of 126 GW and predicts that its 10 zones combined will need 152 GW to satisfy local resource requirements.
“These numbers aren’t final; we do accept updates to forecasts through January,” Bachus said.
2018/19 Transfer Limit
The RTO expects to make no changes to transfer flow limits between MISO South and Midwest for the 2018/19 planning year after FERC recently endorsed its methodology for calculating those constraints.
Manager of Resource Adequacy John Harmon said a feasibility analysis concluded that no adjustment is needed for this year’s regional directional transfer limits, leaving the preliminary South-to-Midwest limit at 1,500 MW (accounting for 1,000 MW of firm transmission reservation offsets) and the Midwest-to-South limit at 3,000 MW (with no firm reservations to reduce the limit).
In November, FERC denied a rehearing of the process for calculating subregional limits request by a coalition of MISO transmission customers that contended the limits were too conservative. (See FERC Upholds MISO Transfer Limit Policy.)
MISO calculates transfer limits between its Midwest and South regions by deducting firm reservations from 2,500 MW of available capacity flowing from South to Midwest and 3,000 MW estimated to be available in the opposite direction. The initial limits were determined in a settlement with SPP that became effective in early 2016.
Harmon said the RTO will release final megawatt values for the two-way limit in February.
2018 OMS-MISO Survey
MISO is also preparing its annual resource adequacy survey with the Organization of MISO States and moving ahead with a new calculation for estimating the volume of future new resources.
Ryan Westphal, MISO resource adequacy coordinator, said the new resource counting methods for the 2018 survey enjoy general stakeholder support.
In accounting for future resources, MISO will tally projects not yet in the three-part definitive planning phase (DPP) of its interconnection queue — and those that have entered the DPP’s first phase — at a 10% completion rate. Conventional and intermittent resources in phase two of the DPP will be counted at 50% and 25%, respectively, increasing to 75% and 50% in phase 3.
Projects still negotiating a generator interconnection agreement will be tallied at 90% completion, while those with signed agreements will be counted as new generation in the survey’s weighted averages. The percentages represent a further refinement of the likelihood values introduced by MISO in November. (See MISO Still Tweaking OMS Survey Assumptions.)
In response to stakeholder questions about the relatively lower completion figures for intermittent resources, Westphal said the RTO has observed that conventional resources have higher rates of completion, “so we’re reflecting that here in the numbers.”
MISO will also apply its capacity credit percentages to the projections, with wind receiving a 15.6% credit, solar receiving 50% and all other resources receiving full capacity credit.
EDF Renewable Energy has escalated its push to make MISO speed up the process for connecting new generation to the grid — this time filing a FERC complaint against the RTO.
Time is of the essence, says EDF, which has previously argued that MISO’s year-old revised interconnection queue process is only worsening the backlog of waiting generators.
In its Jan. 4 complaint, the company asked FERC for a “workable” interconnection timeline to ensure that wind developers can secure federal production tax credits before they expire at the end of 2020. It also seeks a commission ruling no later than Feb. 15 (EL18-55).
“MISO’s apathy and lack of attention to this need is unjust and unreasonable and should be found unacceptable by the commission,” EDF said.
The company argues that its projects can only meet the tax credit deadline if MISO completes interconnection studies by June 2019 to allow for the average 18-month construction of a wind farm. But the RTO’s “severely delayed” interconnection study schedule puts the execution of generator interconnection agreements “perilously close to June 2019” for projects that entered the queue’s definitive planning phase in 2016 and 2017, it said.
And EDF takes a dim view of MISO’s ability to hit even the 2019 target.
“Given MISO’s track record over the last full year in applying its new [generator interconnection procedures], it is highly likely that these dates will continue to slip,” the company said.
If that happens, prospective interconnection customers will forfeit “tens of billions” of dollars, EDF warned.
The company contends that MISO’s Tariff is no longer just because the RTO “cannot deliver interconnection studies and a generation interconnection agreement in sufficient advanced time to allow proposed wind generation projects to achieve commercial operation” in time to receive tax credits.
wind turbines | EDF Renewable Energy
“MISO represented that interconnection studies would be completed and a generation interconnection agreement would be offered in sufficient time to enable proposed wind generation projects to achieve commercial operation before the federal production tax credit expires on Dec. 31, 2020. That has not occurred, and the upcoming prognosis as to timing is not good,” EDF said in its complaint.
EDF brought similar concerns before MISO’s Steering Committee in November, asking the RTO to consider a shortened “fast track” queue process for vetted projects with secured site control, but MISO officials said they would not change the queue process so soon after its early 2017 overhaul. (See EDF Asks MISO to Revisit Queue Overhaul.) Steering Committee members had asked for EDF representatives to return in January with a fuller explanation behind its proposal.
In its complaint, EDF once again argued for the fast-track option and a newly designed two-stage queue, despite FERC’s denial in November of a similar appeal contained in a rehearing request filed by a group of generation developers, including EDF (ER17-156). However, FERC concluded that order by urging MISO to consider additional measures in its revised queue design to avoid delays. EDF now charges that two months have passed without MISO initiating a single stakeholder discussion of the reasons behind the delays or how to diminish them.
MISO planners are sifting through the largest batch of interconnection queue requests in a decade, and the RTO last summer warned stakeholders to prepare for delays. The queue has ballooned to more than 355 projects totaling 60 GW, with 191 projects potentially worth 31 GW entering the definitive planning phase in the August 2017 cycle alone. Before the new design took hold, MISO had predicted that interconnection customers would spend an average of 460 days in the new three-stage definitive planning stage instead of the previous average of 589 days. It remains to be seen if MISO can meet that timeline.
New England state regulators ended up split over ISO-NE’s plan for accommodating clean energy procurements — yet seemingly united in their dismay over how the RTO’s stakeholder process ended.
Vermont, Connecticut and Rhode Island opposed the Competitive Auctions with Sponsored Policy Resources (CASPR) proposal filed with FERC on Monday, while Massachusetts, New Hampshire and Maine supported it (ER18-619). (See ISO-NE Files CASPR Proposal.)
But all six states were upset about last-minute revisions the RTO made to the proposed two-stage capacity auction, according to the New England States Committee on Electricity.
Late Change
“The late change does not reflect the way, in our experience, that New England has done business in recent years,” NESCOE said in a statement at the Dec. 8 Participants Committee meeting, where the proposal fell short of the 60% support needed to win committee endorsement. “If we want New England to be the place where groups gather to try [to] figure out complicated issues, there is work to do to restore trust and restart the willingness to participate in the process.”
[EDITOR’S NOTE: Because the New England Power Pool bars the press and public from its stakeholder meetings, RTO Insider was not permitted to cover any of the stakeholder sessions at which CASPR was debated. This account is based on NEPOOL meeting documents, the NESCOE statement and interviews with state officials and other stakeholders.]
| NEPOOL
CASPR received a sector-weighted vote of 58%, backed by most of the Generation, Transmission and Supplier sectors but receiving virtually no support from End Users. Publicly Owned Entities voted 45-0 in opposition.
The proposal arose out of NEPOOL’s Integrating Markets and Public Policy (IMAPP) initiative, launched in August 2016 in response to state regulators’ cost concerns and generators’ fears that out-of-market procurements of renewable generation would suppress capacity prices.
NESCOE said that although its members are split over CASPR, the states were united in their opposition to ISO-NE’s last-minute decision to adopt changes to the definition of sponsored policy resources (SPR) and limit inter-zonal transfers in the new second capacity auction.
“The states are of one mind on one thing about CASPR. ISO-NE’s approach at the very end of an otherwise open and collaborative process — and specifically its 11th-hour changes — was, to put it mildly, disheartening. These late changes were accompanied by little explanation and provided no time for meaningful dialogue,” NESCOE said.
ISO-NE declined to respond in detail to NESCOE’s criticism. In an email, ISO-NE spokeswoman Marcia Blomberg said only, “The CASPR proposal underwent a robust stakeholder process, with extensive discussion in the NEPOOL Markets Committee and the Participants Committee. The ISO’s goal with CASPR is to balance the accommodation of state policy actions while maintaining accurate pricing in the wholesale markets.”
Regional Split
Although state regulators don’t have voting rights in NEPOOL, they are nevertheless an important constituency.
ISO-NE’s effort in IMAPP to balance the interests of states and generators was further complicated by the disparity in the states’ environmental goals. Massachusetts, Connecticut and Rhode Island plan to procure more than 3,600 MW of nameplate renewable generation. Vermont, New Hampshire and Maine have not adopted such goals.
Those differences were evident when New England rejected increasing carbon emission prices to accommodate the state procurements within ISO-NE’s wholesale markets.
Although the New England states have supported carbon pricing through the Regional Greenhouse Gas Initiative for a decade, RGGI’s emissions limits would have to be substantially reduced to make the resources sought by the states economic in the RTO markets, Market Monitor David Patton told a FERC technical conference in May. Cost was among eight factors NESCOE cited in an April 7 memo outlining the states’ opposition to a “carbon pricing-style mechanism” administered by ISO-NE and regulated by FERC.
“What I want is not to pay for Massachusetts’ and Connecticut’s policies,” New Hampshire Public Utilities Commissioner Robert Scott said at the conference. (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)
Proposal Described
Under CASPR, ISO-NE would clear its Forward Capacity Auction as it does today, applying the minimum offer price rule (MOPR) to new capacity offers to prevent price suppression. In the second Substitution Auction (SA), generators with retirement bids that cleared in the primary auction would transfer their obligations to subsidized new resources that did not clear because of the MOPR. Because the SA will not use the MOPR, it will clear at lower prices than the primary auction, enabling existing resources to buy out their obligations at a lower cost in return for retiring.
| ISO-NE
The proposal would phase out the current Renewable Technology Resource (RTR) exemption, which has allowed ISO-NE to exempt limited quantities of renewable generation from the MOPR.
Supporters of the RTO’s proposal said it was “an improvement over [the] status quo and is properly tailored narrowly to address particular concerns in the markets that are arising or threatened from the future addition of substantial state-sponsored resources,” according to the minutes of the Dec. 8 meeting.
One representative described the CASPR proposal as “a reasonable balance in accommodating states’ initiatives while minimizing the impact on the markets. Many expressed support for how the proposal seeks to support reasonable price formation in FCM and for the late changes that address concerns they had with a very broad definition for sponsored policy resources.”
ISO-NE’s Reversal
The states became disillusioned after the NEPOOL Markets Committee voted on the CASPR proposal and nine states suggested amendments on Nov. 8-9. Only one amendment, by NESCOE, was approved.
According to a summary memo prepared by Day Pitney attorneys for the Participants Committee, the NESCOE proposal included a FirstLight Power Resources amendment to limit SA capacity transfers between zones. They would be permitted only where the cleared outcome does not change marginal reliability impact congestion in any capacity zone.
NESCOE also proposed a backstop mechanism to take effect after the phase-out of the RTR exemption that would allow up to 200 MW of state-procured renewables to enter the market annually even if there were no corresponding retirements in that year.
The NESCOE amendment won a 61% vote of the Markets Committee. With the amendment, however, the overall proposal won only 58%, just below the 60% threshold to recommend it to the Participants Committee. In a separate vote, only 28% of the committee supported the RTO’s proposal without the NESCOE amendment.
Dec. 8 Participants Committee Meeting
Without a Markets Committee-approved package, it was unclear what ISO-NE would propose at the Dec. 8 Participants Committee meeting — the final venue for stakeholders to express their opinion before the RTO filed its proposal with FERC.
On Nov. 30, the RTO outlined its plans in a memo, saying it was adding the FirstLight amendment and a revised definition of SPR.
The revised definition, proposed by the Natural Resources Defense Council and Conservation Law Foundation, limited eligibility in the SA to renewable or clean energy resources receiving out-of-market revenue under state rules enacted before Jan. 1, 2018.
Although the states had included the FirstLight amendment in their November proposal to the Markets Committee, NESCOE’s statement said they opposed the amendments “on a standalone basis [because they would] limit the likelihood of CASPR being successful.”
Liquidity Concerns
Vermont, Connecticut and Rhode Island say the limits on inter-zonal substitution will reduce liquidity in the SA and the chance that CASPR will accomplish ISO-NE’s design objective No. 2: accommodating the entry of SPR into the Forward Capacity Market over time. That, they said, creates a risk that consumers will pay twice for state-procured renewables.
By agreeing to the Jan. 1 cutoff date for eligibility, NESCOE said, ISO-NE “reversed its previously unwavering position that CASPR would be resource-neutral” and accommodate future technologies and solicitations for resources such as storage.
“Without explaining what new information caused the reversal or [providing] an opportunity to discuss, ISO-NE let us all know that its ‘notable property’ — resource neutrality — was wrong all along and that ISO-NE instead prefers a tariff that limits resource eligibility based on an arbitrary statutory date,” NESCOE said.
The Jan. 1 cutoff means CASPR will be a “very short-term mechanism,” the states said. “Should any state adopt a new law this coming legislative session, for example, states and perhaps others will be back where we were at the outset of this process, with a diminished appetite to negotiate and tempered optimism more broadly.”
Connecticut expressed concern at the Dec. 8 meeting that the RTO’s proposal did not “definitively allow” large-scale hydro that the state may procure “through existing or future state law or regulations” to qualify for the SA.
“The minutes accurately reflect a concern Connecticut expressed at the December [Participants Committee] meeting, which speaks to the general confusion and lack of dialogue that resulted from the ISO-NE’s 11th-hour changes to the proposal,” Katie Dykes, chair of the Connecticut Public Utilities Regulatory Authority, said in an email to RTO Insider.
In contrast, Katie Gronendyke, spokeswoman for the Massachusetts Executive Office of Energy and Environmental Affairs, said her state supported the final CASPR proposal because it “will provide the region with the mechanism necessary to provide residents and businesses with affordable energy while achieving carbon reduction goals set forth under the Global Warming Solutions Act as well as regional emissions targets.”
The 2008 act requires the state to reduce greenhouse gas emissions by 25% from 1990 levels by 2020 and 80% by 2050. To meet those goals, the state in 2016 required its utilities to purchase 1,600 MW of offshore wind and about 1,200 MW of other new renewables, including onshore wind and hydropower.
ISO-NE’s Seeks to Balance Competing Concerns
Chadalavada | ISO-NE
ISO-NE Chief Operating Officer Vamsi Chadalavada attempted to assuage the states’ concerns at the Dec. 8 meeting with a promise that the RTO would consider future rule changes if CASPR fails to accommodate state policies.
He noted that it took the RTO from 2005 to 2010 to implement its capacity market and said it has made “numerous and material changes” to the market since, according to meeting minutes. “He stated that, with CASPR, the ISO favored price formation as the best means for the market to address a very uncertain future.”
Chadalavada’s “expressed hope was that necessary improvements over time would be much more limited and capable of being identified and implemented quickly,” according to the minutes. “He acknowledged that some of the late decisions illustrated the ISO’s internal struggles related to the competing objectives inherent in the CASPR proposal.”
Lack of ‘Backstop’
Vermont, Connecticut and Rhode Island said the elimination of the RTR exemption was unacceptable without a backstop provision “that provides a comparable degree of accommodation of the requirements of state laws and, thereby, mitigation of excessive consumer costs and oversupply,” NESCOE said.
Consumer advocates for Massachusetts, Connecticut, New Hampshire and Maine, who are members of the End User sector, cited the lack of a backstop in voting against the RTO’s proposal.
For FCA 12, which begins Feb. 5, 514 MW of RTR exemptions are available. Under CASPR, RTRs would be eliminated beginning with FCA 16. In the interim, RTRs would decrease annually by the amount of capacity supply obligations (CSO) acquired by new RTR capacity in the prior auction. If 100 MW of CSO is acquired in FCA 12, for example, the FCA 13 cap would be reduced to 414 MW. Any RTRs remaining after FCA 15 would be void.
Public Power’s Concerns
Brian Forshaw, representing the Public Power sector, also was dissatisfied with the RTO’s promises to consider changing the SPR definition in the future, according to the Participants Committee meeting minutes, “because such a commitment provided no assurance of whether or when any definitional change would be made.”
Forshaw moved to restore the SPR definition to that advocated by ISO-NE at the Nov. 8 Markets Committee meeting, before its Nov. 30 changes.
In a memo to NEPOOL, Forshaw said the earlier “technology-neutral” definition would allow procurement of resources meeting “broader policy objectives including fuel diversity, local area resiliency, maintaining competitive electric rates, and mitigating the volatility of capacity costs in addition to environmental stewardship objectives.”
Forshaw also was unmoved by the RTO’s assurances that resources not meeting the SPR definition could be offered into the primary auction. “Many of the policy resources that states and local communities are seeking to meet fuel diversity and local area resiliency objectives (including microgrid facilities and battery storage projects) are smaller and limited to specific locations, making it highly unlikely that such resources will be able to clear in the primary FCA, even if those states and communities are willing to absorb the incremental costs above the FCA clearing price,” he said.
“What this means is that if a state or local utility wants to develop a battery storage project (outside of a limited quantity in Massachusetts) or a fuel cell-based combined heat and power project (outside of Connecticut) it would be precluded from having such projects acquire a capacity supply obligation through the Substitution Auction.”
The Public Power motion failed by a show-of-hands vote.
The CLF also opposed the RTO’s proposal, despite the revised SPR definition that excluded fossil fuel generation.
The organization’s David Ismay told RTO Insider it also insisted on inclusion of “a reasonable RTR backstop that would ensure state clean energy procurements are timely integrated into the regional market (and unjust/unreasonable double charging for capacity avoided) if CASPR doesn’t work as advertised or at all — a risk we think is … potentially significant.”
Pacific Gas and Electric stands to lose millions of dollars in transmission revenues after a federal court this week challenged FERC decisions allowing the utility to include a CAISO participation adder in its transmission rates.
In a 3-0 ruling Monday, the 9th U.S. Circuit Court of Appeals remanded to FERC two previous orders authorizing the adders for 2016 and 2017, saying the commission’s interpretation of its authority to grant incentives “does not reflect thorough consideration, nor is it persuasive in its own right.”
The ruling could shake up FERC’s longstanding practice of routinely granting the 50-basis-point adder to transmission owners, a practice the California Public Utilities Commission has challenged because state law requires investor-owned utilities to be members of CAISO. (See CPUC Contests ISO Incentive for PG&E.) The CPUC has contended the adder provides a $30 million “unjustified windfall” for PG&E but has withdrawn previous challenges as a condition of settlement.
A federal appeals court reversed incentive rates granted to PG&E by FERC for membership in CAISO
The Energy Policy Act of 2005 directed FERC to create the incentives, and the adders were introduced the following year in Order 679. Rather than being included as a “generic” adder to a TO’s formula rate, RTO incentives are subject to commission approval on a case-by-case basis — which the commission has routinely granted PG&E.
FERC last year rejected the CPUC’s request to rehear a decision permitting PG&E to include the adder in its 2017 rates, calling the incentive “longstanding practice.” (See FERC Upholds PG&E ISO Incentive Adder, Rebuffs CPUC.)
But the appeals court took issue with the commission’s approach.
“FERC did not reasonably interpret Order 679 as justifying summary grants of adders for remaining in a transmission organization,” the court said in its ruling. It called FERC’s practice “an unexplained departure from longstanding policy” and said the commission’s rationale for granting the incentives amounted to the creation of generic adder.
“FERC’s interpretation of Order 679 is plainly erroneous and inconsistent with the regulation,” the court said.
“We are disappointed with the ruling and intend to pursue the issue when FERC considers its next steps in the proceedings,” PG&E said.
The CPUC told RTO Insider that “FERC was going against its own longstanding policy that incentives should induce future voluntary conduct. By granting PG&E this incentive adder, FERC was essentially giving PG&E a windfall for action it had already taken and is legally required to do.”
If reversed on remand, the CPUC expects $25 million to be removed from PG&E’s current rate case and $30 million or more in future rate cases.
FERC spokesman Craig Cano said the commission had no comment on the decision.
The CPUC has also filed a separate protest with FERC over similar adders being considered in Southern California Edison’s current rate case, a position that has won sympathy from new Commissioner Richard Glick.
CAISO market participants have many opinions on how the ISO should prioritize the many complex and urgent tasks on its plate for 2018.
The ISO recently announced major initiatives to become a Reliability Coordinator in the West, expand its day-ahead market into the EIM, and implement a new package of resource adequacy enhancements, among a slew of other ongoing market changes listed in the grid operator’s policy initiatives catalog. Renewable integration issues such as flexible capacity needs and regional markets and transmission planning are other topics on the minds of market participants who commented on the CAISO roadmap laying out the schedule for policy initiatives.
The spate of initiatives is emerging as CAISO and California regulators look to overhaul their resource adequacy (RA) programs in the face of rising reliability-must-run (RMR) payments to gas generators. Misalignments in RA procurement between the ISO and the California Public Utilities Commission has increased the ISO’s reliance on backstop processes such as RMR and capacity procurement mechanism (CPM) contracts.
Pace of RMR Overhaul Questioned
In comments filed with CAISO, some stakeholders said they want the ISO to combine and accelerate timelines for initiatives such as its RMR/CPM overhaul, while others questioned whether the ISO is taking on too many issues at one time given the complexities and interplay of the many initiatives already underway going into this year.
PG&E’s 2250-MW capacity DIablo Canyon Power Plant
Pacific Gas and Electric’s Matt Lecar urged quicker action on the RMR/CPM initiative, which kicks off with a Jan. 30 meeting. The company wants CAISO to combine proposed Phases 1 and 2 of the effort into a concurrent process and move on an accelerated timeline to prevent a wave of RMR contracts.
“PG&E is deeply concerned that this schedule and framing of the issue [do] not rise to the level of current challenges in the backstop procurement arena,” he said. The timeline does not allow for policy changes until 2019, leaving little time for FERC approval before the 2020 RMR designations go into effect, he said.
“The CAISO has proposed a timetable that may condemn PG&E customers to bear hundreds of millions of dollars of new RMR contract costs for a minimum of three more years and likely longer. There is no justification for this delay,” Lecar said.
The RMRs and other backstop procurements have become more urgent issues since the CAISO Board of Governors reapproved three RMRs in 2017, which PG&E referenced in its roadmap comments. The CPUC responded by soliciting contracts that would replace the three RMRs with Calpine last year, with a fast-track vote set for Jan. 11. CAISO also last month assigned a CPM designation to more gas-fired plants. (See CPUC Targets CAISO’s Calpine RMRs.)
CAISO-CPUC resource adequacy interactions | CAISO
PG&E, the CPUC, and others have opposed the RMRs, each for their own reasons, and CAISO officials have also expressed they would rather procurements result from market signals than out-of-market mechanisms. The debate also has implications for ratepayers and other market participants such as community choice aggregators, which the CPUC is proposing be brought under its RA procurement requirement.
NRG Director of Market Affairs Brian Theaker said, “The increased use of RMR and CPM is a sign of the growing failure of the RA program to identify and compensate the resources needed to maintain reliability.” NRG also said the RA problems and RMR/CPM initiatives should not be fixed sequentially.
“The perpetual limbo for lesser items must be addressed,” said Theaker.
Carrie Bentley, representing the Western Power Trading Forum (WPTF), said CAISO should take full responsibility for the RA program, which holds the ISO accountable for local and flexible capacity requirements.
“Concurrently, RA reform is being taken up by the CPUC, and the CAISO has stated [it] will need to be coordinated with this effort,” she said. “WPTF believes that both efforts are very large and worthwhile and therefore asks the CAISO to make transparent how [it] will allocate resources to each process.”
EIM Participants Look to Day-Ahead
Integrated resource plans, resource adequacy and CAISO markets must align to meet policy goals | CAISO
Other commenters are focused on CAISO’s Western Energy Imbalance Market (EIM) and regional issues, such as transmission planning and the ISO’s announced expansion of its day-ahead market into the EIM.
The Public Generating Pool (PGP), an association of 10 consumer-owned utilities in the Pacific Northwest with more than 6,000 MW of generation, said CAISO should publish an issue paper on its EIM expansion soon and mentioned the many other initiatives the ISO has underway. PGP thinks CAISO should extend its time frame for working on the day-ahead market enhancements.
“PGP finds the timeline for these initiatives to be very aggressive and is concerned about the impact and unintended consequences implementing these initiatives on such a constricted schedule will have,” PGP said in its comments. While PGP acknowledged the constraints on the ISO’s priorities and resources, it also said “there is currently little transparency around how and when the ISO makes those changes.”
The American Wind Energy Association’s California Caucus said it was concerned that CAISO’s roadmap is focused too much on operational efficiencies and not enough on transmission planning to access renewables. The group said it “implores the CAISO to immediately begin studying transmission expansion to access low-cost renewable resources outside of the current CAISO footprint.”
The Bonneville Power Administration said it was encouraged that the roadmap includes CAISO’s Flexible Resource Adequacy and Must Offer Obligations (FRACMOO2) initiative, which is important to all Northwest hydroelectric producers and can provide fast-acting response to help manage intermittent renewables. (See Power Sellers Urge Action on CAISO Flex Capacity.)
“We look to this initiative in 2018 to explain the objectives driving any limitations for external resources providing flexible RA,” BPA said. It also asked CAISO to prioritize changes to the default energy bid option that address opportunity costs for hydro units.
Clean energy interests in jointly filed comments urged CAISO to prioritize the expansion of the day-ahead market into the EIM and begin outreach to stakeholders this month. They include the Western Grid Group, Islands Energy Coalition, Natural Resources Defense Council, Northwest Energy Coalition, and Vote Solar.
ALBANY, N.Y. — New York power industry stakeholders on Monday debated the merits of a draft work plan designed to guide the implementation of carbon pricing in the state’s wholesale electricity market.
Devised by the Integrating Public Policy Task Force (IPPTF) late last month, the plan consists of six “issue tracks” designed to generate stakeholder recommendations for pricing carbon into the market. The task force, which held its first technical conference Dec. 11, will next month begin meeting nearly every Monday over the course of the year to work through each track. (See New York Hashes out Details of Carbon Policy.)
The objective is to develop a firm proposal by December 2018 — if possible.
The issue tracks include the following: 1) straw proposal development; 2) wholesale energy market mechanics (including “carbon leakage” and how to measure emissions); 3) policy mechanics; 4) interaction with other wholesale market processes (such as the capacity market); 5) interaction with other state policies (such as RGGI); and 6) impacts.
The task force will issue a final work plan by the end of January, said IPPTF co-chair Nicole Bouchez, a NYISO market design economist.
During the Jan. 8 meeting, attorney Kevin Lang of Couch White, representing New York City, quickly questioned the premise of the task force, contending that pricing carbon seemed to be a conclusion built in to the process.
“When will we talk about whether we will price carbon?” Lang said. “It’s not just about how to do it, but whether this is the right way to go.”
IPPTF co-chair Marco Padula, deputy director for market structure at the state’s Department of Public Service (DPS), said Lang was moving too fast and the whole point of a deeper analysis of the issue is to determine whether a carbon charge would work in New York.
Defining the Challenge
The first hour of Monday’s meeting was devoted to discussing Track 1 — developing a straw proposal for carbon pricing, which the IPPTF wants to complete by March.
“What is the rationale, what is the end goal for carbon pricing as means to some end?” asked Benjamin Mandel, renewable energy policy advisor to the New York City mayor’s Office of Sustainability. “We broadly suspect it relates to decarbonizing the energy supply, but as has been brought up multiple times by colleagues, there are concerns about whether this one policy instrument in isolation is sufficient to actually achieve that objective in certain locations within New York state.”
NYISO Senior Vice President for Market Structures Rana Mukerji said he thinks the goal is for the state to get 50% of its power from renewable resources by 2030, which the status quo would attempt to achieve solely with renewable energy credits and zero-emissions credits.
“What we asked Brattle to do was to see, if we use carbon pricing in addition to REC and ZEC, whether you could get the same outcome in a more efficient manner,” Mukerji said. “And you have the result of the Brattle analysis, which included impacts on a zonal basis. For Track 1 we’ll have to see more questions on that, whether carbon pricing is indeed more efficient and cost effective when the [Brattle] study shows it was in the range of being cost-neutral.”
Kelli Joseph, NRG Energy’s director of market and regulatory affairs, said she was surprised by Mukerji’s assessment “because if the goal is really [50% emissions reductions] by [2030], there are fundamental assumptions in that [Brattle] report that need to be challenged, including the marginal emission rate that is assumed over time. The state’s goal of getting renewables on by 2030 will have much less carbon emission in the market and [Brattle is] assuming a 2015 system, and even in 2025 the system is not going to look like that.”
Net Change in Carbon Charge | Daymark Energy Advisors
Mark Reeder, an economist representing the Alliance for Clean Energy New York, said a much more detailed economic analysis would be needed: “We don’t know what the price impacts are because we lack the analysis.”
Sanity Check
Bouchez hit the pause button, reminding meeting participants that “what started this was not the Brattle report [on carbon pricing], it was stakeholders asking if there was a better way of harmonizing wholesale electricity markets with state policy … the fundamental question is, how do our wholesale markets interact with state policy and is there a way of making that a better interaction,” said Bouchez.
Greenberg Traurig attorney Doreen Saia said the Brattle report’s limited review of the issues produced a favorable enough answer to compel NYISO and DPS to develop a proposal showing the benefits of carbon pricing.
“Is it fair to assume, to address the consternation of [stakeholders], that [when Track 1 is ready] you would start to look at the impacts associated with what the proposal does or does not produce, does or not provide, so that by June … you can take a test — a sanity check — to see if where you’re headed seems to be sufficient?” Saia asked.
Three Criteria and Transmission Need
Meeting participants also heard an evaluation of possible pricing mechanisms commissioned by the Department of Public Service’s Utility Intervention Unit (UIU).
Speaking on behalf of the UIU, Marc Montalvo of Daymark Energy Advisors, who conducted the study, said the group determined three criteria for measuring the success of carbon pricing: strategic alignment, technical feasibility, and cost effectiveness.
According to Montalvo, strategic alignment would ensure that a chosen approach furthers the overall public policy aims of reducing greenhouse gases and deploying new renewable energy resources. Technical feasibility would mean meeting minimum grid reliability standards, while cost effectiveness would yield the most benefit at the lowest cost.
The three criteria “allow you to whittle down through the potentially long menu of options in a very systematic way,” Montalvo said.
The Brattle report wanted “to get a sense of [the] magnitude and direction if one were to implement a carbon charge with a certain structure, what would that mean for rate trajectory for consumers inside New York generally, as an aggregate,” Montalvo said.
Net Change in Carbon Charge | Daymark Energy Advisors
But now the exercise is to understand all the factors that actually contribute to the evolution of New York’s power sector, the necessary investments in generation and transmission, the response of consumers to changing rates “and what … that [means] for the broader economic issues inside the state, and ultimately for the goals that we have around carbon dioxide emissions and renewable buildout,” Montalvo said.
As a starting point, the UIU study ran a few sensitivities and hypothesized several scenarios in the years 2020, 2025, and 2030.
“One of the interesting things in looking at 2020 is that a lot of the dynamics that are built in to the model for 2025 don’t show up by 2020 because it’s two years away, so a lot of the market response is not yet motivated because there’s not enough time for things to happen,” Montalvo said.
Similarly, some of the issues around demand elasticity are a little different, depending on the year chosen, he said.
Under the model, 2020 is the year when prices tend to be highest and the impacts are greatest because the market has not had time to adjust to carbon pricing, Montalvo said.
“If one is to impose a carbon charge of this sort, is it appropriate and should one consider some kind of mechanism to transition the marketplace into it so you don’t have a great disruption among certain sectors of the economy?” Montalvo asked.
“All other things being equal, there’s a lot of economic interest in constructing a new plant, but there’s really no way to connect that plant to load in the model,” he said. “That’s something to be aware of, that you can’t just add generation to New York’s power system without ever accommodating it with additional transmission and expect prices to go down uniformly across the region.”
[Editor’s Note: An earlier version of this story incorrectly attributed Doreen Saia’s comments to Doreen Harris, director of large-scale renewables at the New York State Energy Research and Development Authority.]
ISO-NE asked for FERC approval of its two-stage capacity auction Monday following months of negotiations that left the RTO’s stakeholders split.
The RTO filed for approval of its Competitive Auctions with Sponsored Policy Resources (CASPR) proposal even though it fell short of the 60% support needed to win endorsement in a Participants Committee vote on Dec. 8 (ER18-619).
CASPR received a sector-weighted vote of 57.75%, with the strongest support coming from the Generation, Transmission and Supplier sectors and virtually no support from End Users. Publicly Owned Entities voted 45-0 in opposition.
‘Cash for Clunkers’
CASPR arose out of the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative, launched in August 2016 in response to state regulators’ concerns over funding of their procurements of renewable generation and generators’ fears that out-of-market resources will suppress capacity prices. Massachusetts, Connecticut and Rhode Island plan to procure more than 3,600 MW of nameplate renewable generation.
“The New England states have expressed concern that the [minimum offer price rule] may cause electricity consumers to ‘pay twice’: once for the cost of the capacity procured in the [Forward Capacity Market], and a second time for the additional generation capacity obtained through the out-of-market contracts with preferred policy resources,” the RTO explained in its filing. “In other words, the region could develop more generation resources than the ISO requires to operate the power system — at an unnecessarily high total cost to consumers.”
| ISO-NE
In the first stage, ISO-NE would clear the auction as it does today, applying the MOPR to new capacity offers to prevent price suppression. In the second Substitution Auction (SA), generators with retirement bids that cleared in the primary auction would transfer their obligations to subsidized new resources that did not clear because of the MOPR.
Because the SA will not use the MOPR, it will clear at lower prices than the primary auction, enabling existing resources to buy out their obligations at a lower cost in return for retiring. The savings would in effect be a “severance payment” to the retiring resources, ISO-NE said. The RTO has explained the SA as akin to a “‘cash for clunkers’ secondary market,” referring to the Obama administration’s 2009 program to encourage the retirement of older, gas-guzzling automobiles.
The proposal would phase out the current Renewable Technology Resource exemption, which has allowed ISO-NE to clear 200 MW of renewable generation in its capacity auction annually without regard for the MOPR.
The RTO asked that most of the CASPR rules become effective on March 9, 2018, when it will begin its planning for FCA 13 in 2019. “This auction is the first opportunity for FCM participation by up to 1,200 MW of nameplate clean energy supply to be procured by Massachusetts pursuant to statute,” the RTO said.
States Split
Although state regulators have no votes in NEPOOL, they were engaged in the negotiations — and split over the result.
Vermont, Connecticut and Rhode Island opposed the final proposal, while Massachusetts, New Hampshire and Maine supported it, according to the New England States Committee on Electricity (NESCOE).
Massachusetts, New Hampshire and Maine are supporting the CASPR proposal “primarily based on the view that CASPR is not expected to have an adverse impact on their ratepayers, and they don’t have the same requirement of state law to satisfy,” NESCOE said in a statement read at the Dec. 8 meeting.
For Vermont, Connecticut and Rhode Island, on the other hand, “the assertion ISO-NE made at the outset — that CASPR is better than what was in place — has not been proven out,” NESCOE said.
Change to Definition
ISO-NE upset many stakeholders when it agreed to a proposal by the Natural Resources Defense Council and Conservation Law Foundation to limit eligibility in the SA to renewable or clean energy resources receiving out-of-market revenue under state rules enacted before Jan. 1, 2018.
“We thought that the original SA supply definition was incommensurate with the goal of IMAPP, which was to integrate big purchases of low carbon/renewable purchases by states,” CLF’s David Ismay told RTO Insider. “As originally proposed, CASPR would have allowed any generation — including traditional fossil fuel generation — to qualify in the new, second auction (as SA supply) as long as it was deemed desirable for some/any reason by some/any public entity.”
But the change alienated the Public Power sector. In a memo to NEPOOL, Public Power representative Brian Forshaw said the revised definition abandoned ISO-NE’s pledge to be “technology-neutral,” which would have allowed it to cover resources meeting “broader policy objectives including fuel diversity, local area resiliency, maintaining competitive electric rates, and mitigating the volatility of capacity costs in addition to environmental stewardship objectives.”
Connecticut also opposed the change, according to meeting minutes, saying the RTO’s proposal did not “definitively allow” large-scale hydro the state may procure “through existing or future state law or regulations” to qualify for the SA.
Lack of ‘Backstop’
The dissenting states also said the RTO’s proposal was unacceptable without a proposed “backstop” provision that would have allowed up to 200 MW of state-procured renewables to enter the market annually even if there were no corresponding retirements in that year.
