FERC on Tuesday approved an uncontested settlement to raise ISO-NE’s peak energy rent (PER) adjustment, resolving the issues the commission set for hearing in a 2017 order finding that the mechanism had become unjust and unreasonable because of the interaction between it and higher reserve constraint penalty factors (EL16-120, ER17-2153).
Under the settlement, ISO-NE will increase the PER strike price for each hour “by the amounts that actual five-minute reserve shadow prices exceed the pre-December 2014 reserve constraint penalty factors (RCPF) values for 30-minute operating reserves and 10-minute non-spinning reserves ($500/MWh and $850/MWh, respectively).”
The change will be applied from Sept. 30, 2016 — the date of the initiating complaint by the New England Power Generators Association (NEPGA) — through May 31, 2018, the last day of the capacity commitment period for Forward Capacity Auction 8.
| ISO-NE
The commission’s Feb. 20 order directed ISO-NE to make a compliance filing reflecting the settlement.
NEPGA had asked the commission to apply the revised PER and any resulting refunds to capacity suppliers to an Aug. 11, 2016, scarcity event, but the commission rejected the request in November 2017, saying it would impose “an unforeseen and significant increase in costs” to load. (See Generators’ Rehearing Bid on ISO-NE Scarcity Rules Denied.)
The Feb. 20 order noted the settling parties did not agree on the application of the revised strike price methodology to FCA 9, the capacity commitment period from June 1, 2018, through May 31, 2019.
| ISO-NE
The New England States Committee on Electricity (NESCOE) contended that the new methodology should not apply because FCA 9 was held in February 2015 — after the RCPFs were increased, which allowed resources to reflect the change in their supply offers.
NEPGA countered that NESCOE’s position “would deny capacity suppliers the full extent of the relief granted by the commission.”
The commission chose not to resolve the dispute, saying it was “beyond the scope of this proceeding.”
FERC previously agreed to eliminate the PER adjustment effective with the capacity commitment period beginning June 1, 2019 (ER17-2153, EL16-120). ISO-NE said its Pay-for-Performance program and changes to the day-ahead energy market made the adjustment unnecessary beyond that date.
ISO-NE spokesman Matthew Kakley said the PER calculations will revert to the old method for FCA 9. “The existing Tariff language (not the revised settlement language) will apply,” he said.
NEPGA president Dan Dolan said on Thursday, “PER and the appropriate strike price level has been a persistent issue in the New England markets for years. The settlement and this order help provide some certainty and stability as the market transitions to the elimination of the PER concept beginning on June 1, 2019.”
FirstEnergy CEO Charles Jones said Wednesday the company’s floundering FirstEnergy Solutions (FES) merchant generating arm is now under a death watch and that, in his “simple view of the future,” coal and nuclear generation will become extinct without market changes.
Jones told analysts on the company’s earnings call that “unless something is done to change the construct of these administrated markets, which have been administrated in a way to disadvantage coal and nuclear plants” and “unless the states step in to provide support, there will be no coal or nuclear plants left in these markets.”
During the call, Jones revealed the extent to which the company has cut ties with FES and that he expects the subsidiary will not survive the winter. He said FES has been operating independently since early last year and will no longer have access to its parent’s internal bank by the end of March, “and that will be the last tie that we have with that business.” (See FirstEnergy Selling Merchant Fleet Despite NOPR.)
“While I can’t speak for FES, I will be shocked if they go beyond March without some type of a [bankruptcy] filing,” he said.
‘Personally Disappointed’
Jones said it would be up to the subsidiaries that own generation — FES, Allegheny Energy Supply and Monongahela Power — to determine whether they will bid into PJM’s Base Residual Auction in May. He also touched on the U.S. Department of Energy’s Notice of Proposed Rulemaking and other efforts that could provide support for the company’s ailing nuclear and coal-fired resources.
“I’m personally disappointed that the endeavors haven’t resulted in a meaningful legislative or regulatory support, given the importance of these plants to grid resiliency, reliable and affordable power and the region’s economy,” he said.
The company is also “not planning to make another attempt at Pleasants,” he said, referring to FirstEnergy’s recently abandoned plan to transfer ownership of its 1,300-MW coal-fired plant from Allegheny to Mon Power, where the plant would have received a defined return based on regulatory review. He said Mon Power would meet any supply needs through PJM’s markets while the company determines how to address a capacity shortfall in its most recent integrated resource plan. Another IRP is due in two years, Jones said. (See FirstEnergy Shutting down Unsold Coal Plant.)
FirstEnergy reported a fourth-quarter GAAP loss of $5.62/share based on asset impairments and plant exit costs of $2.4 billion (3.38/share), which included reducing the carrying value of Pleasants, fully impairing nuclear assets and increasing nuclear asset retirement obligations, said Jim Pearson, the company’s new executive vice president of finance. The company also took a non-cash charge of $1.2 billion ($2.68/share) related to the Tax Cuts and Jobs Act.
K. Jon Taylor, the new president of FirstEnergy’s Ohio operations, said the tax law’s elimination of bonus depreciation would add about $400 million to the rate base, but that depreciation was already scaling down to 40% in 2018 and 30% in 2019.
Adjusted earnings were 71 cents/share for the quarter, driven by a 23 cents/share year-over-year increase from the company’s distribution segments. Jones said operating earnings for the company’s transmission and distribution segments increased 14% in 2017, or 25% if the distribution modernization rider (DMR) in Ohio is included. The company is looking for the Public Utility Commission of Ohio to approve a $450 million distribution platform modernization plan to better gird against blackouts and to prepare for “smart grid technologies.”
Wired Future
To pump up its transition to becoming a fully regulated “wires” company, FirstEnergy plans to invest $10 billion in its distribution and transmission infrastructure by 2022, starting with 2018 operating earnings guidance of $2.25 to $2.55 per diluted share, with a long-term growth-rate projection of 6 to 8% through 2021, Jones said. He said that each year between $1 billion to $1.2 billion of that investment will be targeted to transmission. That excludes the DMR in Ohio and is offset by the corporate segment.
Jones was quick to squelch any thoughts that the company is profiteering in its regulated business.
“There should be absolutely no concern in the market about us overearning in Pennsylvania. And if there is any hysteria out there, you all are smart enough to know that there are people that trade off with the hysteria,” he said in response to a question on several rate cases in the state.
The company last month announced the sale of $2.5 billion in equity to investment companies, which included the formation of a “restructuring working group” to advise on any potential restructuring at FES. The group includes three FirstEnergy executives — Pearson, Leila Vespoli and Gary Benz — along with John Wilder of Bluescape Energy Partners and Tony Horton of Energy Future Holdings. The group serves FirstEnergy’s interests, while FES is overseen by its own board of directors. Pearson is also in charge of an internal company redesign known as FE Tomorrow.
Jones also bristled at suggestions that the cash won’t be enough.
“No additional equity through 2021,” he said. “I can’t believe it’s only one month after doing $2.5 billion that we’re already getting that question again, but there will be none.”
Changes at the Top
FirstEnergy also announced several changes to its board of directors and executive suite before the call on Wednesday. Donald Misheff, who has been on the board since 2012, was elected chairman effective May 15 to replace George M. Smart, while Sandra Pianalto became a director. Smart and William T. Cottle, both 72, are retiring in May in accordance with the company’s mandatory retirement-age policy.
From left: William T. Cottle, Donald T. Misheff, Sandra Pianalto, George Smart. Cottle and Smart are retiring from the board in May. Misheff is replacing Smart as chairman of FirstEnergy’s Board of Directors and Pianalto is joining the board. They will be tasked with leading the company through its major restructuring into a fully regulated transmission and distribution company. | FirstEnergy
Within the company:
Kevin T. Warvell became vice president, chief financial officer, treasurer and corporate secretary for FES. Previously, he was FES’ vice president of commercial operations, structuring and pricing and corporate secretary.
Christine L. Walker became vice president of human resources for FirstEnergy Service subsidiary. Previously, she was the executive director of FirstEnergy’s talent management.
Jason J. Lisowski became vice president, controller and chief accounting officer of FirstEnergy. Previously, he was the controller and treasurer for FES.
Donald A. Moul became president of FES Generation and chief nuclear officer. Previously, he was president of FirstEnergy Generation.
Charles D. Lasky became senior vice president of human resources and chief human resources officer for FirstEnergy Service. Previously, he was the senior vice president of human resources.
Steven E. Strah became senior vice president and chief financial officer. Previously, he was a senior vice president and president of FirstEnergy Utilities.
Sam Belcher became a senior vice president and president of FirstEnergy Utilities. Previously, he was president and chief nuclear officer for FirstEnergy Nuclear Operating Co.
Pearson was the company’s executive vice president and chief financial officer. Taylor was a vice president, controller and chief accounting officer.
PacifiCorp said Tuesday it selected bids from developers of four wind farms, totaling 1,300 MW and advancing an effort that would expand the company’s wind portfolio by more than 60% if constructed.
The Portland, Ore.-based company is procuring the wind as part of its Energy Vision 2020 plan, which also includes upgrading its existing wind facilities in Wyoming, Washington and Oregon with longer blades and other technology. Energy from three of the new projects would be carried to the company’s system via the proposed 140-mile, 500-kV Aeolus-Bridger/Anticline transmission line, a segment of the company’s 2,000-mile Energy Gateway, a proposed project under development over the last decade.
PacifiCorp hopes for construction to begin on the new wind and transmission facilities in 2019 | Copyright: arinahabich / 123RF Stock Photo
“We are committed to expanding the amount of renewable energy serving our customers, and these new wind projects will help us cost-effectively further that goal,” said Stefan Bird, CEO of the Pacific Power unit that serves customers in Oregon, Washington and California.
The winning bids resulted from a request for proposals issued last September. (See PacifiCorpSeeks 1,270 MW of New Wind.) The company estimates the projects will cost an estimated $1.5 billion, much less than when the wind and transmission plan was originally announced last April and lower than the cost of market purchases.
The proposed wind projects, all located in Wyoming, are:
A 400-MW project in Converse County to be built by NextEra Energy, which would split ownership and operation with PacifiCorp;
A 161-MW project in Uinta County to be built by Invenergy and owned and operated by PacifiCorp;
A 500-MW project in Carbon and Albany counties to be built, owned and operated by PacifiCorp; and
A 250-MW project in Carbon County to be built, owned and operated by PacifiCorp.
The new wind and transmission projects still require state approval, acquisition of rights of way and other permits, with construction targeted for next year. The company last year announced it would be procuring more wind energy when it issued its 2017 integrated resource plan. (See PacifiCorp IRP Sees More Renewables, Less Coal.)
Avangrid lost $77 million in the fourth quarter after taking a one-time charge related to the sale of its gas storage and trading units, the company said Tuesday.
But the company is sharpening its focus on its core businesses, with 12 GW of renewable projects in the pipeline, healthy growth in transmission and a nearly $9 billion utility rate base in the Northeast.
Fourth-quarter earnings plunged from $207 million a year earlier, while 2017 net income was down 40% to $381 million, in large part because of the charge.
CEO James P. Torgerson told analysts during an earnings call that the company achieved consistent results last year, despite poor wind production and the impact of an unplanned transmission outage that affected its new 298-MW El Cabo wind farm in New Mexico.
“We’re the third-largest wind operator in the United States, and we have 90% emission-free capacity,” Torgerson said. “And we look to be carbon neutral by 2035.”
Transmission Opportunity
Avangrid’s earnings came less than a week after its Central Maine Power subsidiary learned it’s next in line for winning Massachusetts’ 9.45-TWh clean energy solicitation if New Hampshire regulators do not approve the Northern Pass transmission line by March 27. (See Mass. Picks Avangrid Project as Northern Pass Backup.)
Avangrid transmission lines | UWUA
The state initially awarded the contract to Eversource Energy and Hydro-Quebec’s Northern Pass on Jan. 25, only to see the New Hampshire Site Evaluation Committee (SEC) unanimously reject the 1,090-MW transmission project a week later. Eversource has appealed the decision.
“People can make their own judgment as to what’s going to happen in New Hampshire but [should] keep in mind that they ruled 7-0 not to approve the project previously,” Torgerson said.
The company expects its rate base to increase by two-thirds from 2016 levels to $14.5 billion in 2022.
“So 85% of our rate base is secured by multiyear rate agreements and FERC formula rates,” Torgerson said. “And the rate base increases with investments. We don’t have bonus depreciation, and remeasurement of the deferred tax assets also boosts the rate base.”
The recent corporate tax cuts created some benefits for the company, but Avangrid intends to work with state regulators in New York and New England to ensure utility customers benefit fully, Torgerson said.
‘Smarter’ and ‘Cleaner’
Torgerson also highlighted the company’s work to install advanced metering infrastructure (AIM) and electric vehicle charging stations, and develop smart grid technology and programs to benefit its customers in the Northeast and Pacific Northwest.
Avangrid will invest about $14.4 billion in “smarter” and “cleaner” energy from 2017 to 2022, Torgerson said. Repair and replacement of traditional electric and gas distribution infrastructure and transmission repair and replacement will account for 64% of the investment, with Avangrid Renewables providing the remainder.
The company is investing about $285 million in upgrading transmission lines in Maine and $680 million in AIM and a distributed system integrity program in New York.
Not included in the company’s formal outlook, but mentioned in the call, was Avangrid’s proposed Connect NY project, a 1,000-MW underground DC line from Utica, through the congested Central East interface, to New York City, which the company said will support the retirement of the Indian Point nuclear plant and is well-positioned for regulatory approval.
The company is also a 20% partner with other utility owners in NY Transco, which plans to build an AC line from upstate New York to the load areas around New York City. The company’s Networks division is also poised to develop transmission options in the Massachusetts offshore wind solicitation. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)
“Offshore wind is going to be huge for everybody, but particularly for us with our partnership with [Copenhagen Infrastructure Partners] and our ownership of a lease off Kitty Hawk, N.C.,” Torgerson said.
Avangrid Networks plans to expand beyond the Northeast and into other RTOs across the country. This year it is identifying opportunities to invest about $3 billion per year on requests for proposals, particularly in CAISO, MISO and PJM.
Consumer advocate Public Citizen has filed a complaint with FERC, accusing PJM of violating the Federal Power Act by making political contributions with membership funds (EL18-61).
Tyson Slocum, director of Public Citizen’s energy program, said PJM has made at least $456,500 in campaign contributions to the Democratic Governors Association and the Republican Governors Association since 2007 and hasn’t disclosed the contributions to either FERC or its stakeholders.
Susan Buehler, a PJM spokesperson, said the contributions were meant to allow staff access to energy-related policy summits and “were not intended to support any political campaign.”
“PJM has acted in accordance with all applicable laws and regulations,” she said in an emailed statement. “PJM’s external affairs and communications costs, including these memberships, are collected through PJM’s filed stated rates consistent with FERC’s order authorizing these costs to be collected from ISO-RTO members. PJM operates as a profit-neutral organization for which educating and informing are essential to our FERC-defined functions.”
Slocum said that’s the problem.
“That’s a violation of the Federal Power Act’s just and reasonable standard,” he said. “Given PJM’s admission that they funded these contributions with filed rate money makes this much more complicated for PJM. … They can talk about, ‘Oh, it wasn’t our intent.’ … When you give [PACs] money, you are enabling the financing of partisan election campaigns. … That is totally inconsistent with just and reasonable rates, and I think that we now have a very good case that they’re in violation.”
Public Citizen identified $456,500 in campaign contributions made by PJM to the Democratic and Republican governors associations since 2007. | Public Citizen
Slocum said the contributions came to light during a broader investigation of corporations using political action committees (PACs) to make otherwise unlawful campaign contributions.
“You simply launder the money through the Democratic or Republican association, who then gives it to the candidate. It’s money laundering in the political sense,” he said.
Slocum said he does not suspect PJM of attempting to funnel the money to any particular candidate but is concerned that it is not disclosed.
“PJM has not disclosed that level of detail to FERC or its stakeholders. This is not a FERC-approved transaction. [PJM is] saying they think it’s consistent with FERC’s order, but FERC is not aware that PJM has been using revenues from its filed rate to make contributions to a 527 [PAC],” he said.
NiSource lost $52.4 million during the fourth quarter due to one-time charges related to the federal tax cuts passed late last year, the company said Tuesday.
But during a Feb. 20 earnings call, CEO Joe Hamrock focused on adjusted earnings, noting the company would have made $110.3 million ($0.33/share) in the fourth quarter absent the charges — beating analyst estimates by a penny. The Merrillville, Ind.-based company earned $88.8 million ($0.28/share) during the fourth quarter of 2016.
Hamrock said that “2017 was a year of solid execution,” aided by record utility infrastructure and a growing customer base helped by an upswing in the housing market. NiSource added 28,000 new customers in 2017.
“We’re well positioned for continued growth,” Hamrock told investors.
NiSource earned $128.6 million ($0.39/share) for the year, compared with $328.1 million ($1.02/share) in 2016. Still, the company’s 5% increase in operating income to $901.6 million was accompanied by a 72% jump in income taxes — to $314.5 million — based on “certain balance sheet adjustments and other items as a result of federal tax reform legislation,” the company said.
Chief Financial Officer Donald Brown said NiSource’s continuing commitment to utility investment will be boosted by last year’s federal tax law change despite the non-recurring write-down. Hamrock said the company continues to work with stakeholders and regulators in the seven states it serves on how to best pass the benefits of tax reform on to customers.
“This effort should play out over the next six months or so,” Hamrock said.
During 2017, the company refinanced almost $1 billion of its long-term debts at more favorable rates, which is expected to result in “significant interest savings and positively impact its earnings,” according to the company.
NiSource also invested $1.7 billion in infrastructure last year, the company’s largest-ever single-year investment, Hamrock said. The investment involved replacing 377 miles of gas pipeline, replacing 1,300 electric poles, and placing 68 miles of underground electric cable.
The company’s future financials will be helped further by a recent settlement over the cleanup of several coal ash ponds at two of its Northern Indiana Public Service Co. coal plants. The Indiana Utility Regulatory Commission in December approved a settlement allowing the utility to recover 80% of federally mandated costs to clean up the ponds through surcharges in customer bills (44872). The $193 million bundle of projects ― at Michigan City Unit 12 in Michigan City, Ind., and at R.M. Schahfer Units 14 and 15 in Wheatfield, Ind. — is expected to bring NIPSCO in compliance with EPA’s Coal Combustion Residuals rule. The other 20% of project cost recovery will be deferred until NIPSCO’s next rate case before the IURC.
Michigan City generating station | NIPSCO
Hamrock said NiSource expects to complete the environmental mitigation project by the end of this year.
He also said the company is still on track to reduce its greenhouse gas emissions 50% from 2005 levels by 2025. NiSource last year announced plans to retire half its coal generation by 2023, shuttering more than 1.2 GW in coal between its Bailly and Schahfer plants. (See Big Spending, Shrinking Coal Fleetin NiSource’s Future.) NIPSCO officials have said new EPA rules on coal ash contributed to the company’s decision to partially close Schahfer.
ISO-NE on Thursday defended its proposed two-stage capacity auction, responding to criticism by its External Market Monitor and others.
In its Feb. 13 response to protests, the RTO asked the commission to approve its Competitive Auctions with Sponsored Policy Resources (CASPR) program, saying the Monitor’s “proposed cure would be worse than the disease” (ER18-619). Monitor David Patton filed a protest Jan. 30 saying that he supports “the objective and approach” of CASPR but that the RTO’s proposal has a “critical design flaw” that will result in “inefficient investment and retirement decisions and over the long term … raise costs substantially to New England’s customers.”
Also filing protests in response to the Jan. 8 CASPR filing were Massachusetts Attorney General Maura Healey; municipal utilities (New England Consumer-Owned Systems); Connecticut; the Natural Gas Supply Association; a coalition of environmental groups (Clean Energy Advocates); the New England Power Generators Association; and several merchant generators. (See CASPR Filing Draws Stakeholder Support, Protests.)
The CASPR proposal grew out of the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative, launched in August 2016 to address state regulators’ concerns about ratepayer costs associated with policy-driven resources and generators’ fears that out-of-market procurements of renewable generation would suppress capacity prices.
Under ISO-NE’s proposal, it would clear the 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. The proposal would phase out the current Renewable Technology Resource (RTR) exemption, which has allowed ISO-NE to clear 200 MW of renewable generation in its capacity auction annually (to a maximum of 600 MW) without regard for the MOPR.
ISO-NE’s External Market Monitor included this example in its protest, saying excluding new conventional resources from the substitution auction (left) would clear only 400 MW of sponsored resources, with three existing resources retiring and sponsored resources foregoing $31.2 million in capacity payments. Under the Monitor’s proposal (right) 500 MW of sponsored resources would clear and only one plant would retire. Sponsored resources’ foregone capacity payments would total only $2.7 million. | Potomac Economics
Bad Cure
ISO-NE said it prohibited new conventional resources from participating in the secondary auction “to protect the Forward Capacity Market’s ability to guide competitive and cost-effective entry and exit decisions to maintain resource adequacy.”
But Patton’s Jan. 30 filing said the exclusion of new conventional resources from the SA will cause “new resources to clear and enter when they are not economic or needed and existing resources to retire that are economic to continue operating and whose costs of remaining in operation (i.e., going forward costs) are much lower than the entry costs of new resources that are entering.”
Patton would allow new conventional resources to clear through the SA “so they may be efficiently displaced by the sponsored resources.”
“This was a component of the ISO’s original proposal, but it decided to alter its proposal by excluding the new conventional resources from the Substitution Auction,” Patton wrote. “By doing this, the supply and demand (and prices) that will determine when a new conventional resource enters will ignore supply from the sponsored resources.”
The RTO retorted that “the EMM’s proposed cure would be worse than the disease” by creating “more, and more significant, problems than the overbuild problem it seeks to fix.”
One such problem would be fictitious entry, in which developers with no intention of building generation enter the FCA just to secure the severance payment in the second auction. The EMM’s fix? New conventional resources that are displaced by a sponsored resource would receive no payment.
The RTO said that could scare off new competitive generation, resulting in high capacity clearing prices — the “price blowout problem.”
Patton said that fear is “misplaced.”
“The risk described by the ISO is a risk that is common to all investment decisions and is efficient for the investor to consider in making its investment decision. Any time new resources are entering the market, whether they are sponsored resources or competing conventional resources, this will reduce the expected profitability and increase the risk to subsequent investment,” he wrote.
The EMM would modify the MOPR applied to sponsored resources in the primary FCA so that they can clear at a moderate price, potentially replacing the market-based clearing price with an administratively determined one.
“In addition to its complexity, this multilayered solution is both unfair and ineffective,” the RTO said.
Impossible to Win?
“In this situation, the conventional new resource has responded to the market’s price signal and succeeded in securing a capacity supply obligation (CSO) because it was willing to sell its capacity in New England at the primary auction’s clearing price,” the RTO said. “To strip such a resource of its award without compensation would alter the meaning of the clearing price, as a high price no longer would serve its fundamental purpose as a market signal to encourage commercial investment.”
The EMM’s proposal makes it impossible to “win” an auction, and the outcome differs fundamentally from “the outcome of a normal competitive auction in which an investor fails to clear because its offer price exceeds the market’s clearing price,” the RTO said.
ISO-NE also objected to the EMM’s proposed “price-setting by administrative dictate,” which it found “problematic, both practically and philosophically.”
Practically, the EMM methodology would create reliance on a predetermined estimate that may or may not reflect the true net cost of new entry (CONE), and “to the extent that number is wrong, FCM’s clearing price may be inflated or deflated,” the RTO said.
Philosophically, the EMM’s proposal would result in an outcome largely dependent on administrative parameters. The outcome, like that of the RTR exemption that CASPR seeks to replace, “ameliorates system overbuild but undermines the competitiveness of capacity prices,” ISO-NE concluded.
Applying the Monitor’s proposal to FCA 12 would have resulted in total costs of $4.15 billion, an increase of $908 million, or 28%, the RTO said.
“There can be no perfect solution that completely meets the objectives to maintain competitive pricing and accommodate state-sponsored resources,” ISO-NE said. “When required to trade between these competing objectives, the ISO prioritizes competitive prices.”
RTR Exemption
The RTO also defended its proposal to phase out the RTR exemption, calling it a “blunt instrument.”
The conditions that made the RTR exemption just and reasonable upon its adoption will no longer exist going forward, the RTO said: “Instead, load growth has slowed, the region has excess capacity, and, most significantly, the states have announced plans to contract for substantial amounts of sponsored capacity.”
NextEra Energy and NRG Energy insisted that the commission eliminate the RTR exemption immediately, saying it suppresses prices. CASPR would phase out the exemption by allowing the exempt megawatts that have accrued in earlier auctions — currently 481 MW — to be used over the coming three years through FCA 15.
NextEra argued that the three-year phase-out made no sense because the conditions that supported the exemption no longer exist. The RTO answered that a measured transition was necessary to maintain investor confidence and lower costs over the long term. It noted that the commission has accepted similar transition mechanisms in other capacity market proceedings.
Attorney General Healey opposed CASPR as not allowing “for any regular or reliable integration of sponsored policy resources” into the FCM. She recommended a mechanism like the “backstop” proposed by the New England States Committee on Electricity, which would guarantee entry of up to 200 MW of sponsored policy resources annually regardless of whether they were matched by retirements.
She also suggested the commission could remand the proposal to the RTO with an order to reinstate the RTR exemption.
The RTO said that, given current market conditions, a 200-MW RTR exemption would depress FCA clearing prices by up to 87 cents/kW-month. Continuing the RTR exemption or adding a backstop would undermine CASPR “because no sponsored policy resource would elect to sell capacity at a low price in the Substitution Auction when it could instead receive the higher primary auction price through the exemption,” ISO-NE said.
The CAISO Board of Governors last week enacted new governance policies and named Governor David Olsen as chairman. It also reviewed the ISO’s policy roadmap for 2018.
In a teleconferenced meeting Thursday, the board enacted a new process whereby governors will hold yearly elections for chair. The five-member board voted to replace sitting Chair Richard Maullin with Olsen, who was originally appointed to the board in 2012 by Gov. Jerry Brown.
Governor Angelina Galiteva said that with CAISO involved in more regional matters and the Western Energy Imbalance Market (EIM), the board felt members should have the opportunity to participate as chairs and share some of the growing workload. The board went through an analysis to study best practices, she said.
“This is something we thought over and talked about for quite a while,” Galiteva said. The board elected her to the newly created position of vice chair, nominated by Governor Mark Ferron and seconded by Governor Ashutosh Bhagwat.
“We are entering a period where there could be some rapid change we are part of or instrumental for,” Maullin said, as other board members thanked him for his service in his role. Maullin’s term on the board ended Dec. 31, and he said remaining on the board depends on the California State Senate, which confirmed him as chair in July 2015. He was reappointed by Brown in January 2015.
Cook Briefs Board on 2018 Roadmap
CAISO Director of Market and Infrastructure Policy Greg Cook briefed the board on the 2018 Policy Initiatives Roadmap and Annual Plan, saying the presentation to the board represents the final step in the implementation process.
In January, Cook briefed the EIM Governing Body on the plan, which includes a proposal to extend the ISO’s day-ahead market to the EIM. (See CAISO Plan Extends Day-Ahead Market to EIM.) Each balancing authority area would retain reliability responsibility, and states would retain control over integrated resource planning. Transmission planning and investment remains with each BAA and local regulatory authority.
Cook shared some of the tasks associated with the day-ahead market extension, including the alignment of transmission access charge paradigms to ensure EIM entities recover transmission costs consistent with the existing bilateral network, and consistent billing determinants across the day-ahead market footprint for market efficiency. There will also be distribution of congestion rents collected through the day-ahead market and a day-ahead resource sufficiency evaluation, among other requirements.
Keith Casey, the ISO’s vice president of market and infrastructure development, told the board that implementing the day-ahead across the EIM will provide additional benefits, but it “certainly will fall short of the full benefits we would get with full participation under a regional construct.” These would include efficiency of a single balancing authority over a larger footprint, as well as transmission planning and resource adequacy benefits.
“We believe it has important benefits … but I do want to stress it will fall short of the full integration benefits,” Casey said.
PG&E Continues Criticism of RMRs
During a public comment period, Eric Eisenman, director of ISO relations and FERC policy for Pacific Gas and Electric, told the board that PG&E has no issue with anything in the roadmap but that addressing the increasing use of reliability-must-run designations (RMRs) and the capacity procurement mechanism (CPM) is the utility’s “highest priority.” He reminded the board of the “robust discussion” it had over RMRs at its November meeting when the designation of the gas-fired Metcalf Energy Center was approved. (See Board Decisions Highlight Market Problems.)
“PG&E continues to be very concerned about a slew of RMRs for 2019 that would be designated later this year,” Eisenman said. “But at this point, we just don’t know what is going to happen.” He urged CAISO to implement more extensive “Phase 2” changes in its RMR/CPM initiative in time for 2019 designations. The ISO has indicated it only intends to address must-offer requirements for RMR and CPM units in that time frame.
Casey said the ISO is looking at transmission alternatives to prevent situations that might otherwise lead to RMRs, including working with PG&E to address “low-hanging, fast upgrades” in the subarea where the Metcalf plant sits. The improvements would alleviate about 600 MW of local capacity requirements and are included in a transmission plan due to be finalized in March, he said.
“There is much we can do — we have a great deal of flexibility with the transmission plans to do those types of studies,” but it would be challenging to complete the improvements by fall 2019, he said.
“We share PG&E’s urgency about getting after these RMR reforms,” Casey said.
CAISO is in the midst of developing a package of enhancements to the RMR/CPM process, which is proving to be a contentious proposal among market stakeholders. (See CAISO, Stakeholders Debate RMR Revisions.)
FERC on Thursday approved a package of modifications to improve market efficiency developed by CAISO for the Western Energy Imbalance Market (EIM). It also issued several other decisions related to Western states and energy markets.
The commission said the EIM measures would improve efficiency by automating manual processes, providing greater transparency into bilateral transactions and enabling increased participation in both the EIM and CAISO.
The approved changes include automated matching of import/export schedule changes between resources inside and outside the EIM, as well as the ability to automate changes to mirror system resources at intertie scheduling points between CAISO and an EIM entity (ER18-461).
“We find that the automated matching and the automatic mirroring functionalities will result in more efficient EIM market outcomes by automating manual processes that are prone to errors and better maintain balance between resources and load following intertie schedule changes,” FERC said.
The EIM Governing Body approved the package of changes in November, after CAISO had scaled down the initiative based on consultations with stakeholders. (See EIM Governing Body Approves ‘Consolidated’ Initiatives.) The changes also facilitate bilateral settlements and improve the market’s modeling accuracy by expanding the functions of non-generator resources.
CAISO had requested approval of the measures by Feb. 15 to allow for the participation of Powerex and Idaho Power in the EIM on April 4.
Deseret Earns MBR Authority
The commission last week also approved Deseret Generation & Transmission Co-operative’s updated market power analysis for the Northwest region, granting the utility market-based rate authority effective Sept. 12, 2016. Utah-based Deseret became a public utility in 1996 after paying off its debt related to rural utility service (ER16-2186).
Deseret owns the 458-MW Bonanza coal-fired plant and a 25% interest in the 430-MW Hunter 2 coal-fired unit, both in the PacifiCorp balancing authority area.
FERC Approves PG&E/Port of Oakland Agreement
The commission also approved an interconnection agreement between Pacific Gas and Electric and the Port of Oakland but suspended the agreement and subjected it to hearing and settlement judge procedures (ER17-2536).
The Port of Oakland is a major container shipping facility and a municipal electric supplier.
The port acts a municipal electricity supplier that serves customers located at the Oakland International Airport, which it owns and operates, using PG&E’s transmission and distribution facilities.
Last year, the port submitted an application to convert its Cuthbertson substation from retail service to wholesale interconnection service under PG&E’s transmission owner tariff, but PG&E identified an issue with the tariff based on the substation’s power factor, which it said has to be resolved before it can provide wholesale service.
The port contends that PG&E’s sales for resale to it are subject to FERC jurisdiction and that it is concerned about provisions in the interconnection agreement referring to matters under the jurisdiction of the California Public Utilities Commission. The port argues that PG&E is attempting to “improperly impose” CPUC-jurisdictional exit fees on it and protests language describing the change to wholesale service as a notice of departure from PG&E, subjecting the port to departing load fees.
The port also contests that certain aspects of the agreement are unreasonable and unduly discriminatory compared with other PG&E interconnection agreements.
FERC set a public hearing subject to settlement procedures to be held within 15 days.
GridLiance Rehearing Request Rejected
FERC rejected GridLiance West’s rehearing request contending the commission erred when it failed to approve the company’s proposed use of an actual capital structure related to incentive rates for facilities it sought to acquire from Valley Electric Transmission Association (ER17-706). GridLiance West said the proposed capital structure was comparable to similarly situated transmission companies.
In its order denying rehearing, the commission said it made no final determination regarding the proposed capital structure but “found that its preliminary analysis indicated that the proposed TO Tariff had not been shown to be just and reasonable and raised issues of material fact that could not be resolved on the record before the commission.”
Idaho Commission Complaint Headed to Court?
FERC also declined to act on a petition for enforcement filed by Franklin Energy Storage against the Idaho Public Utilities Commission (EL18-50, et al.). The company argued the state commission had improperly classified its energy storage facilities as solar qualifying facilities, preventing them from being eligible for the PUC’s stated electricity rate under the Public Utility Regulatory Policies Act. The rate is available to non-wind and non-solar QFs of an average capacity of 10 MW or less.
The decision will allow the company to bring an enforcement action against the Idaho commission in the appropriate court, FERC said.
FERC on Thursday granted a waiver request from Public Service Company of New Hampshire (PSNH), allowing ISO-NE to accept its restoration plan for the Lost Nation generating unit, which the company submitted one business day after the deadline under the RTO’s Tariff (ER18-465).
Eversource Energy, PSNH’s parent company, in January completed the sale of its fossil-fuel generation units in New Hampshire to Granite Shore Power.
On Oct. 20, ISO-NE flagged the oil-fired combustion turbine in Groveton, N.H., for having a significant decrease in capacity below its cleared capacity supply obligation (CSO) of 13.97 MW for the RTO’s 2018-2019 capacity commitment period.
Covered bridge over the Upper Ammonoosuc River next to the 18-MW Lost Nation plant in Groveton, NH.
Under the rules governing the RTO’s annual reconfiguration auctions, Lost Nation had 10 business days to either purchase additional capacity to replace the shortfall or submit a restoration plan showing how it would be able to meet its obligation.
PSNH said the decrease in capacity occurred because a summer seasonal claimed capability audit was not performed. An Eversource employee intended to file a restoration plan showing that Lost Nation was dispatched four days in September 2017 and thus should be capable of supplying output to meet its awarded CSO.
The utility said that two events caused the delay in submitting the restoration plan.
First, the mother of the employee charged with submitting the plan died on Oct. 29, 2017, while the plan was out for review. Then, after a strong storm tore through the state on Oct. 30, the employee was called to storm duty and performed three consecutive 13-hour shifts until being released on Nov. 2. He was then given leave to prepare for his mother’s Nov. 4 memorial service.
Lost Nation Turbine | Eversource
The combination of events distracted the employee from submitting the restoration plan by the close of the Friday, Nov. 3 submission window; he submitted the plan the morning of Monday, Nov. 6. The RTO said it could not unilaterally waive the Tariff-imposed deadline.
In its Feb. 15 decision, the commission found that “PSNH acted in good faith by submitting the restoration plan as soon as possible after it discovered the omission.” The commission also noted that PSNH’s waiver request was uncontested.
