Connecticut regulators are getting mixed signals from power industry participants as they approach a Feb. 1 deadline for issuing a report on the economic viability of the Millstone nuclear power plant.
While some stakeholders say Millstone may be the most profitable nuclear plant in the country, others contend the plant must contract directly with the state in order to remain operational.
Gov. Dannel Malloy last July ordered the state Department of Energy and Environmental Protection (DEEP) and the Public Utilities Regulatory Authority to assess the current and future viability of the plant and determine whether the state should provide financial support (17-07-32). (See CT Gov Orders Financial Analysis of Millstone Plant.)
The governor’s move came a month after the state’s General Assembly failed to pass a bill that would have allowed the 2,111-MW nuclear plant in Waterford to bid into the state’s procurement process reserved for renewable energy resources such as large-scale hydropower, wind and solar (S.B. 106).
Plant owner Dominion Energy is seeking guaranteed state contracts for its nuclear units, claiming they operate under the same financial constraints from low natural gas prices that led New York and Illinois to provide state subsidies for some of their nukes.
The Electric Power Supply Association filed comments with the state this month, contending that Millstone’s profitability made any ratepayer subsidy unnecessary.
“EPSA believes — and the draft Levitan report confirms — that Millstone will remain economically viable through 2035,” said EPSA, referring to a Levitan & Associates report sent to the governor last month. (See Millstone Likely Profitable Through 2035, Conn. Consultant Says.)
EPSA also submitted a new study by Energyzt Advisors that said “numerous studies have shown that the plant is profitable — perhaps the most profitable nuclear plant in the United States.” The study also recommended regulators put a “price or cap on carbon for all sectors in the state and let market forces determine which carbon reduction investment provides the greatest payback.”
EPSA CEO John E. Shelk said Energyzt’s new analysis “identifies a wide range of strategies state policymakers can implement to protect and grow jobs, manage costs and reduce emissions for the long term.”
Dominion: Flawed Economics
Dominion’s Jan. 8 filing with DEEP and PURA accused the Levitan study of “mixing apples and oranges” in using the company’s regulated, Virginia-based nuclear plants as a proxy for Millstone’s cost projections.
“Millstone Unit 2 and Unit 3 are entirely different designs requiring separate control rooms, separate spare parts inventory, distinct operator training and separate teams of licensed operators,” Dominion said. “In addition, Millstone’s larger physical footprint requires a larger security staff and has higher site maintenance costs including utility costs, building maintenance and snow removal.”
Dominion also cited higher labor costs in Connecticut, saying its plants in Virginia are located in lower-cost rural areas.
In addition, Dominion said the Levitan report “understates the upcoming capital requirements of Millstone as critical station components reach their end-of-life cycle and need to be replaced to maintain the company’s core commitments of safety and operational efficiency. It is important in this regard not to confuse operating cash flow, much of which must be reinvested in the capital needs of the station, with profitability.”
The General Assembly submitted comments last week encouraging PURA and DEEP to “hedge against natural gas by opening a bidding process to receive bids from nuclear generating facilities, including Millstone, to purchase power directly by long-term contract.”
The legislators argued that “since Millstone’s power is currently purchased by hedge funds and financial institutions, these groups are receiving the benefit of price spikes today due to the current ‘cold snap.’”
Environment and Markets
Environmental organization Citizens Campaign for the Environment, which has more than 80,000 members in Connecticut and New York, said that it “strongly opposes any special deals for nuclear power under our state’s energy procurement markets. Allowing Millstone to compete with up-and-coming renewable technologies like wind and solar power would unfairly force Connecticut ratepayers to foot the bill for an antiquated, and yet highly profitable, power source.”
The Conservation Law Foundation submitted a draft proposal for a Dynamic Forward Clean Energy Market (DFCEM) that would allow Connecticut and other states in the region to procure clean and renewable electricity via a market administered by ISO-NE.
“The DFCEM market mechanism would allow Connecticut to procure the environmental attribute of new and existing zero-emission resources, including nuclear, on a least-cost basis through an auction mechanism that places all emissions-reducing resources on equal footing while allowing Connecticut to share emissions compliance costs with other states fairly and in proportion to each state’s climate and energy laws and regulations,” CLF said.
The group did not specifically address the issue of Millstone’s financial viability, but it referred to a November 2017 report by The Brattle Group that assumed “nuclear plants (with the exception of Pilgrim) retire after 60 years in service, or earlier if going-forward costs exceed market revenues.”
California faces a “severe shortage” of transmission capacity needed to tap potential New Mexico and Wyoming wind resources that would help the state meet its 50% renewable portfolio standard, CAISO said in a new study.
The findings regarding interregional transmission projects are supplements to CAISO’s 2016-2017 transmission plan, which was approved by the ISO’s Board of Governors last year. A second study released Jan. 5 looked at the impact of gas generator retirements scenarios, finding flexible capacity shortfalls at certain times.
The ISO assessed the feasibility of accessing 4,000 MW of wind from New Mexico and Wyoming to meet the 50% renewables goal and reached out to other Western planning regions to assess out-of-state portfolios. It said it had received feedback that its production cost simulations and power flow analyses do not fully capture the challenges of accessing out-of-state resources.
California needs more transmission capacity to fully access New Mexico and Wyoming wind power
The study was “a preliminary examination of transmission implications of meeting part of California’s 50% RPS requirement by assuming California’s procurement of 2,000 MW of wind resources in Wyoming and 2,000 MW of wind resources in New Mexico,” it said.
CAISO did not say whether the lack of transmission capacity would make the RPS goal unattainable. But wind energy interests are urging the ISO to explore additional transmission capacity to access low-cost regional wind resources, and the transmission projects included in the study represent billions of dollars in investment to serve California’s RPS.
The study is informational, CAISO said, and the results are not intended to direct interregional transmission, renewable generation development or policy direction.
The study looked at four large proposed transmission projects — TransWest Express, Southwest Intertie Project – North, Cross-Tie Transmission Line and Renewable Energy Express. It used two case studies based on two assumptions regarding resources and transmission.
Major transmission projects outside California have a large impact on grid operations, CAISO said. It noted that transmission constraints on a 230-kV network in southern Wyoming would have to be mitigated for California to realize the full benefit of the Western transmission system.
CAISO Studies Gas Retirements
In a second study on the risks of early retirement of uneconomic gas plants, CAISO said in some scenarios capacity shortages would occur in early evening, the new period of peak net load.
“Capacity issues start to emerge between 4,000 to 6,000 [MW] of retirement, considering some uncertainties in forecasts,” the study said.
CAISO studied six retirement scenarios of between 4,000 and 7,900 MW for four types of gas-fired technology. It found “unlimited renewable curtailment” is masking the need for flexible ramping capacity to meet morning and afternoon demand ramps.
| CAISO
Large amounts of renewable generation on the grid “is also putting economic pressure on the existing gas-fired generation fleet, especially for those generators not obtaining resource adequacy contracts.”
CAISO produces its transmission plan each year to assess system limitations and needed reliability improvements. As part of the 2017-2018 plan, the ISO examined proposed system improvements in the Moorpark area, where it is increasingly unlikely that NRG Energy will build the Puente natural gas power plant. (See NRG Signals Pull-out on Proposed Puente Plant.) The review is needed because of the expected retirement of up to 2,000 MW of generation, CAISO said in a Jan. 11 presentation. Comments on the analysis are due Jan. 18.
SAN FRANCISCO — California regulators last week issued several decisions that will affect the state’s energy resource mix and markets, including approving the retirement of the Diablo Canyon nuclear plant and replacing three reliability-must-run contracts for gas-fired generators with energy storage.
In its first meeting of 2018, the California Public Utilities Commission also approved exploring more uses for energy storage and pilot programs for new electric vehicle infrastructure. But staff delayed until Feb. 8 a vote on a proposal that would subject community choice aggregators (CCAs) to resource adequacy requirements, an idea that has drawn swift opposition from CCA supporters.
Fraction of Negotiated Cost Recovery
The CPUC unanimously approved the retirement of Pacific Gas and Electric’s 2,240-MW Diablo Canyon plant in San Luis Obispo County, the last remaining nuclear plant in the state. But the commission granted only a fraction of the $1.8 billion in cost recovery that was included in a joint proposal negotiated between PG&E and labor and environmental groups.
CPUC President Michael Picker said that with the decision, “We chart a new energy future by phasing out nuclear power here in California in 2024 and 2025.” Attending the meeting by teleconference, he called it “a very difficult and contentious case,” but “we agree the time has come.”
Diablo Canyon represents 6% of energy generated in California, but it is exacerbating overgeneration and curtailment of renewable resources. The plant is also aging and not needed for local reliability, Picker said. PG&E’s load is dropping with the growth of CCAs, direct access users (that buy directly from wholesale) and customer-based generation such as rooftop solar.
Picker said the order also directs PG&E to explore shutting the plant’s two units down earlier, in 2020 and 2022.
The CPUC rejected provisions in the joint proposal that would have paid for $1.3 billion in energy efficiency projects. An administrative law judge had proposed denying the efficiency cost recovery because the utility is already required to make that effort. (See PG&E Disputes ALJ’s Diablo Canyon Recommendation.)
The commission also rejected provisions in the joint proposal that allocated $85 million to mitigate the impact of the plant’s closure on the local community. Local officials say the plant is the hub of the local economy, but the CPUC said it would not authorize assistance without legislative direction.
The CPUC did approve recovery of $211 million to retain PG&E employees until the plant closes, $11 million for employee retraining of workers and $19 million for license renewal expenses already incurred. The commission said replacement capacity would be addressed in its integrated resource plan proceeding.
Parties to the joint proposal include PG&E, International Brotherhood of Electrical Workers Local 1245, Coalition of California Utility Employees, Friends of the Earth, Natural Resources Defense Council, Environment California, California Energy Efficiency Industry Council and Alliance for Nuclear Responsibility.
PG&E said it was “disappointed” the full proposal was not approved, but it noted the CPUC increased funding for employee retention above what was in the proposed decision.
“The joint proposal represents an array of interests from many parties who joined together to promote the best path forward for our state and PG&E’s customers,” the utility said in a news release. “Since the full proposal was not approved, in line with our agreement, PG&E will be meeting to confer with our labor, community and environmental group partners in the days ahead about the decision, our next steps and the path forward.”
Commissioners noted the significance of the plant and the new challenges involved with retiring a major energy resource. Commissioner Martha Guzman Aceves called it a “landmark decision” to get a safer source of energy that is also clean. Commissioner Clifford Rechtschaffen noted that the commission intends to ensure the replacement capacity does not increase greenhouse gas emissions.
Elizabeth Echols, director of California’s Office of Ratepayer Advocates (ORA), said, “PG&E customers benefit from this decision because it protects customers from paying $1.56 billion in unnecessary costs, while providing important funding for PG&E employee retention and retraining programs. Today’s decision is well-supported by the evidence ORA and other parties provided in this case.”
The two units at Diablo Canyon went online in 1985 and 1986.
In its consent agenda, the CPUC passed a resolution to replace RMRs inked between CAISO and Calpine for the Metcalf, Yuba City and Feather River plants in PG&E’s service territory. The contracts have created tensions among ISO stakeholders and signal the state’s resource adequacy is not meeting reliability needs. The decision requires PG&E to hold solicitations to replace the RMRs with energy storage. (See CPUC Targets CAISO’s Calpine RMRs.)
Commissioner Carla Peterman also developed two decisions approved by the CPUC, including one adopting 11 rules governing multiple-use applications for energy storage. The decision creates a framework enabling energy storage companies to stack their offerings and provide more than one service to the wholesale market, distribution grid, transmission system and resource adequacy programs. The rule, developed in coordination with CAISO and other agencies, is supported by energy storage companies.
“This is the first time any commission has tried to do anything like this,” Peterman said.
Her other proposed decision supports new EV pilot projects, which she called “an important issue for the state of California.” It directs PG&E, Southern California Edison and San Diego Gas & Electric to invest $41 million in pilot projects for school buses, delivery trucks, airport/seaport equipment, truck stops and commuter locations. Other projects include the installation of fast charging for urban locations and car dealerships, the commission said.
The full list of the CPUC’s approved, withdrawn and held decisions from the Jan. 11 meeting is available here.
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.
