Despite two rate increases that took effect earlier this year, Alliant Energy’s third-quarter results were down year over year because of mild weather this summer.
The Madison, Wis.-based company announced a quarterly profit of $174.3 million ($0.75/share), down from $179.7 million ($0.80/share) a year earlier. Alliant attributed the slump to mild conditions, higher depreciation expenses and higher energy efficiency cost recovery amortization at subsidiary Wisconsin Power and Light (WPL).
CEO Patricia Kampling said earnings would have been on target with earlier estimates had summer temperatures been on par with historical averages.
“This quarter, we continued to produce solid financial and operational results,” Kampling said. “With three quarters of the year behind us, I am pleased to report that our anticipated … temperature-normalized earnings for fiscal year 2017 are in line with the original midpoint of our 2017 earnings guidance. However, taking into account year-to-date temperatures, which resulted in an estimated 6 cents/share of lower earnings, we are updating 2017 adjusted earnings per share guidance to a midpoint of $1.93.”
Alliant provided year-end guidance between $1.89 and $1.97/share.
The earnings announcement follows regulatory approval of two Alliant rate hikes this year. Interstate Power and Light’s interim electric base rate increase was approved in April, while WPL’s electric and gas base rate increases were implemented in January. They will boost annual revenues by $102 million and $18 million per year, respectively. Also in January, Alliant discontinued WPL’s practice of offering winter rates that are lower than summer rates.
New England will see its grid integrate more renewable resources and increase its reliance on natural gas-fired generation over the coming decade, according to ISO-NE’s 2017 Regional System Plan.
| ISO-NE
The plan, which forecasts power system needs through 2026, highlights increasing wind and solar penetration, flat load growth and fuel security concerns because of natural gas pipeline constraints. The forecasts are in line with those aired at a public hearing on the plan in September. (See ISO-NE Forecast Sees Flat Loads, More Solar, No Congestion.)
Declining Load, Increasing Retirements
| ISO-NE
With growing penetration of solar and energy-efficiency resources, the forecast shows the 10-year net energy for load decreasing from 126,786 GWh in 2017 to 119,680 GWh in 2026, a decline of 0.6% per year.
The 50/50 net summer peak forecast of 26,482 MW for 2017 declines to 26,310 MW for 2026. The 90/10 net summer peak forecast, which captures extreme heat waves, is 28,865 MW for 2017 and grows by 0.1% per year to 29,021 MW in 2026.
Retirements will likely be the key driver for new resources. From 2010 to summer 2020, power plant retirements will total approximately 4,800 MW, said the report, which notes that economic and environmental pressures are putting older oil, coal and nuclear generators at risk. Retiring resources are likely to be replaced by gas, wind and solar resources, resulting in a “hybrid” of renewable and conventional generation, the RTO said.
As of April 2017, nearly 13,000 MW of resources had applied to connect to the high-voltage grid, though the interconnection queue historically has had an attrition rate of 68% of the megawatts proposed. The most reliable and economic siting for new resources remains near load centers in southern New England.
Adequate Resources
The 11th Forward Capacity Auction, held in February 2017, procured sufficient resources to meet resource adequacy criteria through 2021, with about 264 MW of new generation, including 6 MW of wind, 5 MW of solar and 640 MW of new demand-side resources, including 515 MW of energy efficiency.
The regional net installed capacity requirement (ICR) is based on gross load and load reductions from behind-the-meter PV. The representative net ICR is expected to grow from 34,300 MW in 2022 to 35,700 MW in 2026, the report said.
Fuel Security Concerns
| ISO-NE
The report cites fuel security risks from the failure of the natural gas pipeline infrastructure to keep up with the growth in gas-fired generation, a particular concern during winter.
ISO-NE is conducting an analysis to quantify the region’s risk, the results of which will be discussed with stakeholders in 2018. The RTO delayed issuing the report in October following the Department of Energy’s proposal to subsidize uneconomic coal and nuclear generators. (See RTOs Reject NOPR; Say Fuel Risks Exaggerated.)
Solar PV resources totaled 1,918 MW (nameplate capacity) at the end of 2016. The RTO projects that will more than double to 4,733 MW by 2026, producing about 6.2 GWh of energy that year. PV resources are estimated to reduce summer peak loads by 575 MW this year and by 1,035 MW in 2026.
New England has 1,300 MW of installed wind with about 5,400 MW more proposed as of April 2017. Massachusetts in July launched a solicitation for 400 MW in offshore wind, with proposals due in December.
The RTO sees the role of energy storage growing over the next decade as the technology’s costs decline. The region’s first grid-scale battery system, a 16-MW facility at Yarmouth Station in Maine, was placed online in 2016.
From 2002 and June 2017, the region spent $8.4 billion on 730 transmission upgrades to improve system reliability and reduce congestion. As of June 2017, an additional $4 billion in transmission investment for reliability was planned. The RTO expects the need for major transmission projects for reliability to decline through 2026 but said the integration of large-scale renewable energy resources could change that forecast.
FERC last week denied requests for rehearing of its April 2016 order that approved capacity market changes to prevent ISO-NE generation owners from retiring resources that are still economic (ER16-551-003).
The new rules changed how retiring generators declare their intention with de-list bids — the minimum capacity price that will keep the plant operating — and gave the RTO the power to keep a unit operating if needed for reliability.
ISO-NE said the changes were needed to prevent suppliers from retiring a generator to increase prices for the remainder of the supplier’s portfolio. It followed an uproar over the closing of the 1,517-MW Brayton Point plant in Massachusetts. (See FERC Approves Changes to ISO-NE Retirement Rules.)
In a July 2016 order, FERC also approved a 10% mitigation threshold allowing ISO-NE to substitute the Internal Market Monitor’s cost estimate in place of the supplier’s de-list bid if the Monitor found the supplier had overstated the operating costs of the plant by 10% or more.
Section 205 Rights
The New England Power Generators Association, Exelon and NextEra Energy Resources asked FERC to reconsider the initial order, saying the rule changes forced them to cede to ISO-NE their Section 205 rights to file rates with the commission.
FERC concluded that although the Tariff changes add steps to the bid review process, they do not fundamentally alter the process in a manner that infringes on the suppliers’ rights to file rates. “The Internal Market Monitor’s mitigation is an input into a market-based capacity auction governed by ISO-NE’s Tariff that generates the Forward Capacity Auction’s clearing price,” the commission said in its Oct. 30 order.
| ISO-NE
The commission said “this market construct is distinguishable from a supplier’s right to file cost-of-service rates with the commission pursuant to Section 205 of the [Federal Power Act]. We reject petitioners’ implicit contention that ISO-NE does not provide a jurisdictional service and that the Forward Capacity Auction is the suppliers’, instead of ISO-NE’s, rate.”
The commission also disagreed with the generators’ assertion that FERC provided no evidence that ISO-NE’s proposal represented a balance between possible over-mitigation and the need to curb market power.
“On balance, we are persuaded that the need to address possible price distortion due to a retiring supplier potentially exercising market power to impact the market clearing price outweighs the risk of lower capacity prices resulting from possible over-mitigation,” the commission said.
Two-Run Clearing
FERC also rejected the generators’ complaint that the two-run clearing mechanism in the new rules — under which capacity needed to replace a retiring resource could receive a higher price — was discriminatory.
| ISO-NE
“To the extent that the second run yields a higher price than the first run, this would result from the Internal Market Monitor’s determination that a resource has sought to retire uneconomically,” the commission said. “Therefore, it is necessary to limit suppliers that cleared in the first run to that clearing price to ensure the auction’s competitiveness and protect consumers from the exercise of market power. We find this mechanism is necessary to ensure that non-retiring suppliers themselves are not unduly discriminated against due to a retiring supplier’s exercise of market power.”
The commission dismissed as moot the generators’ request that the mitigation threshold — which FERC’s April 2016 order required the RTO to add — “is in addition to, and not a substitute for, flexibility with respect to forecasts and other inputs of exit bids.”
The commission said its July order approving the threshold had already made that point clear.
FERC last week approved ISO-NE’s proposal to cluster interconnection requests to relieve a backlog in the queue for northern and western Maine.
The revisions, effective Nov. 1, will allow the RTO to consider interconnection requests and allocated network upgrade costs in groups rather than individually.
The commission’s Oct. 31 order said that the changes “increase efficiencies, better inform the decisions of project developers and allow project developers to share the costs of the upgrades necessary to accommodate their interconnection” (ER17-2421). (See ISO-NE Files Cluster Study Rules; Window to Open in Nov.)
| ISO-NE
The RTO will use its new clustering procedure in addition to its “first-ready, first-served” serial interconnection request system. “When specific conditions are present in the ISO’s interconnection queue, the proposed methodology would allow two or more interconnection requests to be analyzed in the same system impact study and for developers to share costs for certain interconnection-related transmission upgrades,” ISO-NE said.
Together with the New England Power Pool’s Participants Committee and the Participating Transmission Owners Administrative Committee, the grid operator proposed implementing the clustering methodology first to address the queue backlog in Maine, where more than 5,800 MW of proposed resources, mostly wind, want to connect to the grid.
Long-Term Benefits
| ISO-NE
The commission rejected protests by RENEW Northeast, American Wind Energy Association, EDP Renewables and King Pine Wind, who argued it would be unjust and unreasonable to allow the clustering revisions to take effect before Massachusetts issues the results of its 2016 request for proposals. Owners of generation projects in northern and western Maine were among the respondents.
“Given the overall expected long-term benefits of the [revisions], we find that, on balance, it would be inappropriate to wholly reject the revisions to accommodate a subset of interconnection customers in the near term,” FERC said.
RENEW asserted that solicitations like Massachusetts’ determine which renewable generation projects are viable for interconnection construction and, thus, which projects execute power purchase agreements that include recovery of network upgrade costs. EDP said that ISO-NE could avoid such timing issues by aligning the implementation of the clustering with the timing of the Massachusetts RFP process.
NEPOOL responded that RENEW provided an alternative proposal in the stakeholder process to synchronize the interconnection cluster study process with the state’s energy procurement process, but only 40% of Participants Committee stakeholders favored the proposal.
The commission denied protesters’ request to delay implementation of the clustering revisions until 30 days after the results of the Massachusetts RFP are released. FERC also rejected protests that the misalignment between the cluster study process and state procurement processes would cause the first cluster to collapse because interconnection customers not selected for the RFP will withdraw from it. FERC noted that the RTO’s new rules “allow for full refund of the cluster participation deposit in such instances.”
The commission also was not persuaded by arguments that moving an interconnection customer that does not agree to join the cluster to the bottom of the queue is unjust and unreasonable.
“The clustering revisions appropriately aim to ensure that only those interconnection customers that are ready to move forward in the interconnection process participate in phase two of the cluster studies, [which] is consistent with the ‘first-ready, first-served’ approach that the commission discussed as a possible queue reform measure in RTO/ISOs as early as 2008,” the commission said.
FERC last week approved CAISO Tariff changes to establish a process for selecting and procuring black start resources needed to restore segments of California’s transmission system in the event of regional outages.
Black start refers to the ability of a generating unit to begin operating without assistance from the electric grid. Such units are needed to restart other generation and restore the grid after widespread outages; they have certain requirements under the ISO’s Tariff.
CAISO needs additional black start capability in the San Francisco area
The changes reorganize and consolidate certain black start provisions, create rules for technical requirements and operating tests, and remove outdated provisions. They also designate the cost of incremental black start as a reliability cost and allocate it to the transmission owner in the area where the units are located (ER17-2237).
The new black start provisions entail significant involvement of the affected TO — in this case Pacific Gas and Electric — in drawing up technical specifications and vetting proposals from resources bidding into the solicitation. The ISO would have authority to accept or reject a TO’s recommended resources. PG&E supported the changes and cost allocation method.
Under the new rules, CAISO will use a cost-of-service approach to compensate selected resources, rather than provide a capacity-type payment sufficient to support the operation of an otherwise unprofitable generator.
FERC said the revisions improve the reliability and clarity of the Tariff.
“Because individual black start capacity resources do not benefit all parts of the system equally, it is just and reasonable to recover these costs from a participating transmission owner where the resource is located and serves the reliability need,” FERC said. No parties objected to the cost allocation, and the benefits were roughly commensurate with the costs, the commission said.
To comply with CAISO rules, black start generators must make a minimum number of starts, operate in standalone and parallel modes, be able to pick up load during start-up load, produce and absorb reactive power, and have communication and control equipment.
A cool summer and the impact of Hurricane Harvey drove NRG Energy third-quarter earnings sharply lower, but the company still sees bright days ahead, according to CEO Mauricio Gutierrez.
NRG earned $171 million ($0.53/share) last quarter, compared with $402 million ($1.27/share) in the same period last year. Revenues were down 10.9% to about $3 billion.
Gutierrez | NRG
Gutierrez said during a Nov. 2 earnings call that although the company is “on track” to transform itself through cost-saving measures, the third-quarter results led the company to lower its full-year earnings before interest, tax, depreciation and amortization (EBITDA) guidance to $2.4 billion to $2.5 billion from the previous $2.56 billion to $2.76 billion.
“In Texas we saw both a major hurricane and the coolest August since 2004, with cooling degree days 13% below normal, and in the Northeast, cooling degree days were on average 8% below normal for July and August,” Gutierrez said. He noted that ERCOT summer wholesale prices fell 43% below expectations. Mild weather across the East and in Texas eliminated any opportunity to benefit from scarcity pricing.
NRG attributed one-time financial impacts of $40 million to Hurricane Harvey, evenly divided between its generation and retail operations in Texas. About 80% of the company’s baseload generation on the Gulf Coast was available during the worst part of the storm, and 95% has been restored to date.
Brighter Side
NRG’s retail business continues to improve its operating efficiencies, customer acquisition and retention, which partially offset the impacts of milder summer weather, especially in ERCOT, Gutierrez said.
He said certain cost and margin enhancements will start impacting the company’s bottom line next year, as well as the sale of subsidiary NRG Yield and its renewables assets, which is expected to be completed this year and return up to $4 billion. The company continues to use excess cash to deleverage itself, he said.
“Since our second-quarter call, we have taken another $600 million of debt out of our capital structure, completing our 2017 capital allocation,” Gutierrez said.
He also pointed to improving market conditions in Texas as a particular bright spot for the company.
| NRG
“Despite the absence of extreme weather this summer, ERCOT fundamentals remain strong. ERCOT’s 2017 peak load of 69.5 GW was up nearly 2% over the five-year average and came in just shy of the 2016 peak,” he said.
| NRG
The recently announced retirement of more than 4 GW of generating capacity in ERCOT puts further pressure on a market with already strong fundamentals, Gutierrez said. Vistra Energy on Oct. 6 announced plans to retire three aging coal-fired units in East Texas with a combined capacity of 1,880 MW, rendered obsolete by ERCOT’s record low prices. (See Vistra Energy to Close 2 More Coal Plants.)
“For summer of 2018, these new retirements and asset delays alone will put ERCOT at the lowest reserve market on record, which is suspected to be somewhere between 10 and 11%,” Gutierrez said. “Other changes, such as delayed new builds and new industrial demand, could lower these numbers even further.”
But while the retirements are nudging up forward markets, prices are still below what is needed to justify new builds, he pointed out.
Calls to Action on Market Reform
In response to an analyst question about whether NRG would consider selling parts of its Texas portfolio, Gutierriez said, “Right now we’re very comfortable with our Texas portfolio.” He said the capability of NRG’s generation fleet aligns well with its retail loads.
But while the recent retirements are improving market health, ERCOT must do more to strengthen markets and should recognize the locational value of power plants, he said.
“Reliability and resiliency are important attributes to the grid, and we will continue to work with ERCOT to ensure that generators close to load centers are compensated for all the benefits they provide.”
Beyond the positive developments in ERCOT, Gutierrez said NRG sees several other “calls to action” occurring for market reform.
“As the power grid continues to undergo significant change — low gas prices, renewable penetration and attempts for out-of-market subsidies for uneconomic generation — regulatory bodies and other stakeholders are taking note,” Gutierrez said. “These have led to several significant catalysts, from the [Department of Energy] staff report on competitive markets and [Notice of Proposed Rulemaking], to PJM’s proposed market reforms. I cannot recall another time when there has been such urgency and reach across ISOs to improve competitive energy markets.” (See Market Summit Tackles Ongoing PJM Changes.)
Gutierrez said NRG has been optimistic about market developments in PJM, especially around the introduction of Capacity Performance.
Asked to rank the most promising areas for growth, Gutierrez responded that NRG aims to balance its generation and retail businesses and is focused on perfecting an integrated platform.
“A lot of the generation is going to be driven by our retail needs and how we grow retail, and a lot of our retail will be driven by where we have generation,” he said. “We’re still long in generation in PJM. We have a ways to go before we have a balanced portfolio like we have in Texas. … Just in terms of market structure, I would put PJM No. 1, New England No. 2 and New York No. 3.”
Eversource Energy last week reported third-quarter earnings of $260.4 million ($0.82/share), down nearly 2% from the same quarter in 2016. Earnings for the first nine months of 2017 were $750.6 million, up 5% from earnings of $713.1 million in the same period last year.
Lembo | Eversource
“The primary drivers of our [quarterly] results were higher electric transmission earnings being offset by lower electric distribution results,” Eversource CFO Phil Lembo told analysts in a Nov. 2 conference call.
A higher rate base boosted transmission earnings by 10.7% to $99 million, the result of the company investing $600 million in its transmission system this year through September, with just less than $1 billion planned for the full year, Lembo said.
He attributed a 7.4% drop in earnings for the company’s electric distribution and generation division to lower sales reflecting mild weather in July and August. Cooling degree days in Boston were down nearly 34% for the quarter compared with last summer and 8% below normal, he noted.
In addition to lower electric revenues, the company recorded higher property tax, depreciation and interest expense in the quarter, but was able to offset much of the negative impact by controlling costs, Lembo said. Eversource’s natural gas distribution segment posted a net loss of $6.2 million in the third quarter and earnings of $49.1 million in the first nine months of 2017, compared with a net loss of $7 million in the third quarter of 2016 and earnings of $51.9 million in the first nine months of 2016.
“For the long term, we continue to project 5 to 7% [earnings per share] growth,” Lembo said. “We are pleased with our results today and remain comfortable with our 2017 guidance, although I’d like to see some very cold weather in November and December, and that would really help us reach the higher end of our earnings range for ’17.”
Future Developments
Lembo noted that Eversource last month filed with the New Hampshire Public Utilities Commission to sell its remaining 1,200 MW of generation assets in the state for $258 million, and expects the two sales to be completed late this year or in early 2018. On the company’s proposed merger of subsidiaries NSTAR Electric and Western Massachusetts Electric Co., he said state regulators should issue a decision by Nov. 30 on the merger and grid modernization, and a decision on performance-based rate design by Dec. 29, with rates to become effective in January 2018.
| Eversource
Lee Olivier, Eversource executive vice president for business development, said the company’s Northern Pass transmission project achieved an important milestone Nov. 1 when utility subsidiary Public Service Company of New Hampshire filed a settlement agreement on the lease terms for most of the 192-mile route for the line.
“The settlement was reached with New Hampshire PUC staff and the Office of Consumer Advocate, the two principal intervenors in the case,” Olivier said. “We expect the New Hampshire PUC approval of the settlement by the end of the year. Taken together, we are very pleased with our current position in the siting process, with significant progress being made in all venues.”
Eversource has also partnered with Ørsted, formerly DONG Energy, to form Bay State Wind for the offshore wind solicitation in Massachusetts.
“We are preparing our bid into the Massachusetts offshore wind [request for proposals], which is due Dec. 20,” Olivier said. “Given the vast experience of Ørsted in European offshore wind and our knowledge of New England markets and transmission, we believe we will be able to submit a highly compelling set of proposals for review by the evaluators.”
MISO predicts the 2018/19 planning year will require a reserve margin just more than 17%, a figure that’s been steadily increasing over the years.
Based on its annual loss-of-load-expectation (LOLE) analysis, MISO expects the planning period to require a 17.1% reserve margin for installed capacity (ICAP) and 8.4% margin for unforced capacity (UCAP), the latter of which represents ICAP minus forced outage rates. The RTO will use the margins along with the latest load forecasts to create its enforceable planning reserve margin requirement before April’s capacity auction.
| MISO
Systemwide, MISO predicts it has about 150 GW of ICAP and almost 139 GW of UCAP to meet a nearly 126 GW expected peak demand for the June 2018-May 2019 period. The RTO’s planning reserve margin assumes the inclusion of 4,764 MW of firm UCAP and 2,331 MW non-firm UCAP from external resources.
MISO’s needed reserve margin has been on the rise since 2013. Last year, MISO predicted 15.8% for ICAP and 7.8% UCAP reserve margin for the 2017/18 planning year, up from 2016/17’s 15.2% and 7.6% values. (See MISO 2017/18 Planning Reserve Margin at Nearly 16%.) All local requirements increased from the 2017/18 planning year, the RTO noted.
Speaking during a Nov. 2 Reliability Subcommittee conference call, MISO senior engineer William Buchanan said the increase is primarily driven by an upswing in generation outages and a change in the dispatch model for demand resources, but it was partially offset by reduction in anticipated load growth. The RTO this year added a new modeling step to capture economic load uncertainty that increases the risk associated with high peak loads, also boosting the reserve margins.
Despite the yearly increases, MISO predicts reserve margins will begin to plateau. According to the LOLE analysis, they will largely hold steady because of similar forecasts over the next decade even as peak demand exceeds 129 GW by the 2023/24 planning year. The LOLE analysis found that through 2027, MISO’s ICAP reserve margin will fluctuate between 17.1 and 17.2% while the UCAP reserve margin will oscillate between 8.3 and 8.4%.
Consolidated Edison’s third-quarter earnings fell 8% to $457 million ($1.48/share), a drop the company attributed to changes in its rate plan and regulatory charges, as well as the impact of weather on steam revenues. The new rate plan includes changes in the timing of recognition of annual revenues between quarters.
Con Edison Forecasted Average Rate Base Balances ($ in millions) | ConEd
“This is an exciting time in the energy industry,” CEO John McAvoy said during a Nov. 2 earnings call. “We’re incorporating renewables into the grid at an increasing rate, we’re using data analytics to provide customers with more information about the way they’re using energy and how they can save, and we’re working on programs to increase electric vehicle use and access to charging stations. At the same time, our $1 billion storm hardening program after Superstorm Sandy has made our system more reliable than ever five years later, having already prevented 250,000 power outages due to our investments.”
The company updated its guidance on adjusted earnings per share for 2017 slightly to $4.05 to $4.15/share. The previous range was $4 to $4.15/share.
Con Ed also said it is unable to estimate the amount or range of possible costs related to an April 21 subway power outage in New York City.
ConEd plant on the East River at 15th Street in Manhattan, New York City
After investigating the outage, the New York Public Service Commission in August issued an emergency order requiring the company to inspect electrical equipment serving the Metropolitan Transportation Authority’s system, analyze power supply and power quality events affecting subway signaling services, provide new monitoring and other equipment, and file monthly reports with the commission on all activities related to the subway system. The commission last month approved another order extending the subway outage oversight beyond its original 90-day limit but has not yet issued the second order.
FOLSOM, Calif. — In a move that met criticism from some stakeholders, CAISO’s Board of Governors on Thursday approved two measures intended to prevent the early retirement of unprofitable — but needed — generation in California.
The board approved a reliability-must-run (RMR) contract for Calpine’s Metcalf Energy Center, saying it was an undesirable but necessary measure to maintain electric grid reliability in the Silicon Valley.
Despite the unanimous vote, the board expressed unhappiness about approving the contract, an out-of-market payment to keep the 605-MW natural gas-fired plant from retiring.
Governor Ashutosh Bhagwat said: “I am going to hold my nose very, very hard.” He added that “I understand the problem, but I think this is going to be a recurring issue and we need to come up with a solution.”
Governor Mark Ferron said he was tempted to vote against the RMR “because I am opposed to the process and the situation we find ourselves in.” But, he added, “to vote against this contract is not a risk that we should play with.”
The Metcalf RMR is the third such contract awarded to a Calpine plant this year, sparking concerns among industry participants that the CAISO market and California’s resource adequacy (RA) process are not supporting generation needed for future reliability. Calpine in June told the ISO it planned to remove the plant from dispatch on Jan. 1, 2018. The RMR contract was developed in a relatively short time frame after the ISO determined Metcalf was needed for local reliability. (See Metcalf Reliability-Must-Run Draws Scrutiny.) Metcalf’s designation as RMR follows similar contracts approved earlier this year for Calpine’s Yuba City and Feather River plants. (See CAISO RMRs Win Board OK, Stakeholders Critical.)
Representatives from the California Public Utilities Commission, Pacific Gas and Electric and Cogentrix spoke against the agreement at the meeting.
CAISO CEO Steven Berberich told the board that use of RMR “is not at all how we want to handle procurement.” He added that “the RMR is symptomatic of a bigger problem, which is that resource adequacy is no longer able to meet the needs of the system.” He said that the ISO does not want to frequently approve RMR agreements, and that procurement should be done through the RA process.
Board Approves CPM ROR Changes
In addition to the Metcalf RMR, the board approved a separate, broader program that will pay generators to stay in service to meet reliability needs. The Capacity Procurement Mechanism Risk-of-Retirement (CPM ROR) program expands the existing CPM process to include procurement of at-risk capacity needed for the next RA compliance year.
The program includes two application windows each year — in April and November — for three types of ROR designations. As the ISO developed the process, some stakeholders — including the PUC — raised concerns that inclusion of the April window gives resources undue insight into price discovery for the commission’s RA program, which occurs in October. The commission was concerned “that moving a CPM ROR determination to a date prior to the conclusion of the year-ahead procurement process will result in front-running the RA bilateral procurement process.” (See CAISO Participants Question Retirement Program.)
CAISO added the April window based on requests from generation owners, who said they needed the option of a designation earlier in the year for planning reasons. CAISO changed the proposal to require that a resource attest that it “reasonably believes” its annual fixed costs meet or exceed certain price thresholds. Some have criticized that the ISO would accept an attestation in that regard.
CAISO Infrastructure and Regulatory Policy Manager Keith Johnson told the board that the PUC’s 2019 RA proceeding is an opportunity to address the issues that have been identified. The ISO will evaluate potential modifications to the RMR construct to better align with the current environment, he said in a presentation to the board.
Keith Casey, CAISO vice president of market and infrastructure development, repeatedly took to the microphone on Thursday to rebut criticisms of both the RMR and CPM ROR. He acknowledged that the state’s RA program and ISO markets need fixes, but there is not enough time to develop them in an adequate time frame.
The ISO would normally let the RA procurement process run its course in October before signing an RMR agreement, but Calpine told it that the normal time frame would not be workable. Calpine also indicated it was not interested in the CPM ROR program, leaving the RMR as the best option, Casey said. “We don’t want to be one wire away from blacking out Silicon Valley,” he added.
“The issue for me is one of timing,” Casey said. Changing the RA construct is going to be a long and difficult process, and with increasing retirements, “we have got to have some tools to ensure that resources that are critical on the system can be retained.”
The board on Thursday also approved modifications to an incentive that is meant to ensure that RA resources can meet their must-offer obligations and provide replacement capacity if the resource has a forced outage. It changes the Resource Adequacy Availability Incentive Mechanism (RAAIM) calculation to separately calculate generic RA used for system load and flexible capacity, among other changes, according to an Oct. 25 letter from Casey to the board.
Lastly, the board voted to increase its retainer compensation to $40,000/year, which CAISO said is well below the retainers paid to the governing boards of the nation’s other RTOs/ISOs.
