Page 1189 – RTO Insider

April 10, 2018

PJM Operating Committee Briefs: April 3, 2018

VALLEY FORGE, Pa. — With the exception of three nor’easters, system operations in March were relatively uneventful, PJM’s Chris Pilong told attendees at last week’s Operating Committee meeting.

Pilong reviewed the monthly operations report, noting there were no spinning reserve events during the month. The load forecasting error was 1.53% overall. The error during off-peak hours was 1.48%, 0.1% above the same metric in March 2017, but the on-peak error was 1.58%, down 0.16% from a year ago.

There were 45 excursions for a total of 99 minutes outside PJM’s frequency target range, down from 106 excursions for 257 minutes in March 2017. Unplanned outages, planned emergencies and the total outage average by percentage were all lower than the same period a year ago. The forced outage average by percentage, along with the forced and total outage averages by megawatts, were up slightly.

Stakeholders considered operational issues last week at PJM’s Operating Committee meeting. | © *RTO Insider*

“We’re starting to ratchet up the planned outages,” Pilong said. In previous years, April and May have been the second- and third-highest months for outages, behind only October.

PJM estimates production-cost savings of more than $11 million in 2018, almost all of which occurred in March.

Gen Transfer Vote Postponed

PJM postponed a planned vote on approving stricter requirements for notifying the RTO about generation ownership transfers, but the RTO’s Rebecca Stadelmeyer said ongoing discussions with owners remain productive. The two sides hope to have a mutually acceptable proposal prepared for a vote at May’s OC.

Both sides recently engaged in a four-hour discussion, and a final call is scheduled for this month, Stadelmeyer said. Generation owners in February objected to rules proposed by PJM that they felt were too onerous, but at last week’s meeting, they appeared to agree that the consensus was likely. (See “Generation Transfer,” PJM MRC/MC Briefs: March 22, 2018.)

Storage

PJM’s Scott Baker highlighted progress being made by the Distributed Energy Resources Subcommittee on determining how combined storage and generation resources should measure and account for the differences between wholesale and retail power sales. The subcommittee has developed potential definitions for wholesale-retail delineations during complicated transactions, such as when a storage resource is charging from both the grid and a co-located resource and discharging to the grid while the generation resource is also injecting directly to the grid.

Baker also outlined the non-wholesale information PJM believes it needs from DERs and the communication and data-validation channels that will likely be necessary to properly oversee storage resources.

Black Start Fuel Assurance

As part of the current black start procurement, PJM is looking to add rules that ensure plants have fuel when needed. The RTO’s David Schweizer introduced a plan for “restoration fuel assurance,” which it hopes to implement in the third quarter of this year and apply to any black start resource procured after 2018.

The changes would include a transition plan for existing units, including those picked up in the current procurement. The plan will also address fuel-assurance issues — including dual-fuel capability, onsite fuel storage and units having connections to multiple gas lines — and compensation mechanisms.

Schweizer said he received preliminary proposals from 90 different sites in its current procurement, which PJM undertakes every five years. Staff have sent notifications for detailed proposals to about 25 of the 90. PJM is planning to award contracts to any successful proposals by the end of May. There are currently about 150 black start units RTO-wide.

Schweizer said the new rules are in response to the fleet becoming significantly more gas-heavy. He noted that the current rules require that black start units be back online within three hours, and that gas travels in pipelines at 20 mph on average. Gas pipeline operators have assured the RTO that the lines are packed sufficiently to supply black start units if necessary, but “increased reliance on natural gas means increased need for black start ability,” he said.

CIR Revisions

PJM’s Jerry Bell presented additional analysis on summer performance of wind and solar units and how that relates to providing capacity injection rights (CIRs). The work is part of PJM’s ongoing effort to revise Manual 21, which covers procedures for determining changes to generators’ capability. (See “Limiting Meetings Causing Stakeholder Strain,” PJM PC/TEAC Briefs: March 8, 2018.)

Bell said staff analysis found that the average peak hour, which is used for determining capability, is a good approximation of the median for solar units but not for wind. The study found that average wind performance during the peak hour of demand is likely to reflect the actual amount of production only 36% of the time. The median was about half as much, and wind production was zero in two of every seven peak summer hours, Bell said.

For the May OC meeting, PJM plans to provide more analysis on whether the current June-August testing period is appropriate, and if simultaneous testing would be more indicative of the true capability of plants that have common load spread across multiple units.

Stakeholders remained skeptical of the potential changes, noting concerns that ranged from how unit testing will be conducted, to whether there’s an appeals process for PJM’s determinations, to how the rights planned for units in the interconnection queue would be handled if they are not brought online before the rules change.

PMUs to Monitor IROLs

PJM is considering using its growing synchrophasor network to monitor interconnection reliability operating limits (IROLs). The RTO’s Shaun Murphy explained that phasor measurement units (PMUs) could offer redundant monitoring of the IROL interfaces. Past issues with PJM’s emergency management system have required manual monitoring of IROLs. Implementing the plan would require installing 14 PMUs and modifying four.

The proposal is the most recent initiative in PJM’s effort to exploit the opportunities created by its synchrophasor network. (See “Synchrophasors Backup,” PJM Operating Committee Briefs: Sept. 12, 2017.)

University Park RAS Done

Commonwealth Edison’s Alan Engelmann announced plans to end the company’s remedial action scheme at its University Park North Energy Center. The RAS will be disabled by July 1 and physically removed by the end of the year.

The plan trips generators for certain delayed-clearing multi-phase and single-phase faults to prevent instability, Engelmann said. Incremental reinforcements, such as circuit breaker replacements and protection system redundancy, have made the plan unnecessary.

— Rory D. Sweeney

April 10, 2018

Perry Hints DOE Won’t Grant FES ‘Emergency’ Request

By Rich Heidorn Jr.

NEW YORK — Energy Secretary Rick Perry insisted again Monday that coal and nuclear generation is essential to electric resilience but indicated he was not likely to declare an emergency to keep FirstEnergy Solutions’ struggling power plants operating.

FirstEnergy DOE Rick Perry FES — Perry | © *RTO Insider*

FES asked the Department of Energy last month to issue an emergency order directing PJM to compensate coal-fired and nuclear power plants that have 25 days of onsite fuel with “full recovery” of their costs and a “fair return on equity.”

The company asked Perry to act under Section 202c of the Federal Power Act, which allows DOE to declare emergencies “during the continuance of any war in which the United States is engaged, or whenever [FERC] determines that an emergency exists by reason of a sudden increase in the demand for electric energy, or a shortage of electric energy.”

FES said the closing of its nuclear and coal generation would undermine the reliability of PJM’s grid, a contention the RTO dismissed, saying “there is no immediate emergency.” (See FES Seeks Bankruptcy, DOE Emergency Order.)

Perry spoke Monday at Bloomberg New Energy Finance’s (BNEF) Future of Energy Summit, where Ethan Zindler, head of Americas for BNEF, asked him to define “emergency.”

“When you flip on the lights and nothing happens,” Perry responded.

Would FES’ request qualify as an emergency that deserved intervention? Zindler asked.

“That is an issue in front of DOE that is being looked at as we speak,” Perry said. “My job is to find solutions to challenges that face us. The 202c may not be the way that we decide what is the most appropriate, most efficient way to address this. It’s not the only way.”

Perry did not elaborate on what path DOE might take, but he reiterated his longstanding position that an “all of the above” fuel strategy, including the retention of coal and nuclear, was essential to reliability. He also repeated his response to those who have complained that the emergency order — and the Notice of Proposed Rulemaking he sought from FERC last year to boost such generators — would undermine markets.

“Nobody was using the term ‘free market’ when we were talking about renewables and the subsidies that came from the government,” he said. “The reality is government affects the market every day.”

In an earlier session at the BNEF Summit, former FERC Commissioner Nora Brownell said granting FES’ request would be a “tragedy” for capitalism, markets and ratepayers. Noting the FPA’s reference to war or shortages, she predicted any emergency declaration would be overturned by the courts.

In January, FERC rejected Perry’s NOPR, which would have directed RTOs and ISOs to compensate the full operating costs of generators with 90 days of onsite fuel. The commission instead opened a new docket to receive input on the resilience issue. (See RTO Resilience Filings Seek Time, More Gas Coordination.)

April 9, 2018

CAISO Developing New CRR Proposal

By Jason Fordney

FOLSOM, Calif. — CAISO is advancing into the second phase of reforms to its congestion revenue rights auction, focusing on implementing a structure that provides only a partial congestion hedge rather than a full one.

The ISO is moving through auction reforms in stages after its Department of Market Monitoring called for disbanding the program; it found the transactions have led to losses in the hundreds of millions for ratepayers. (See CAISO Monitor Proposes to End Revenue Rights Auction.) Financial entities and traders have objected to the changes, leading to a complex debate over the current structure and whether it is fair for ratepayers. Similar discussions are going on in other organized markets over financial transmission rights.

The ISO has already completed “Track 1A” of its CRR auction changes, unanimously approved by the Board of Governors last month. (See CAISO Moves Ahead With Market Changes.) At the meeting, board members agreed with the Monitor’s contention that the CRR market as currently devised it is not a real auction because it does not involve willing buyers and sellers.

Auction participants can currently purchase CRRs at generator locations, load locations, trading hubs, pricing nodes, and import and export scheduling points, but the changes proposed in Track 1A limit CRR sources and sinks to only the combinations needed to hedge congestion costs associated with delivering supply. The revisions also established a deadline for reporting transmission outages prior to the auctions to more accurately estimate transmission capacity available for CRR purchases.

Partially funded CRRs

CAISO is now developing changes under “Track 1B,” targeted for June approval by the board and implementation in time for settlement of the 2019 CRR auction. Under consideration for this track is a switch from fully funded CRRs — in which the auctioned rights provide a complete hedge and always receive a full difference in marginal congestion components — to a partial funding arrangement.

CAISO CRR congestion revenue rights — Servedio | © *RTO Insider*

Other ISOs and RTOs only partially fund FTRs, relying on a system in which auctioned rights share in payment shortfalls and do not provide a complete hedge, CAISO Market Design Policy Developer Perry Servedio said Thursday in a presentation to the ISO’s Market Surveillance Committee (MSC).

CAISO also plans to develop a “Track 2” set of rule changes consisting of more comprehensive changes to be implemented in time for the 2020 CRR auction.

The ISO is considering two approaches to partially funding CRRs. One is an ex ante approach in which the ISO derates CRRs prior to the day-ahead market. This would allow market participants to adjust their forward energy positions prior to the day-ahead market to hedge final supply delivery.

Another ex post approach would charge CRR holders for shortfalls after the day-ahead market, which could eliminate incentives by market participants to “game” modeling differences between the CRR market and day-ahead market, CAISO said.

Other approaches are also under consideration, including lowering the percentage of system capacity released in the CRR process, eliminating use of the whole transmission system in the auction or implementing reserve prices.

CAISO Considers MSC Viewpoints

CRR congestion revenue rights caiso — Harvey | © *RTO Insider*

At Thursday’s meeting, Scott Harvey of FTI Consulting briefed Servedio and other CAISO staff with a presentation on what he said could be other factors contributing to CRR auction revenue inadequacy, including the fact that CRRs are allocated and auctioned based on auction shift factors but are settled based on day-ahead shift factors.

MSC members James Bushnell, of the University of California Davis, and Ben Hobbs, of Johns Hopkins University, also raised issues with one CRR proposal developed by Southern California Edison and the Monitor that would eliminate using the available transmission system in the CRR auction, saying the move would have technical, institutional and legal implications.

“Even if there is large-scale willing participation by sellers, forming desired new CRRs out of offered counterflow CRRs may be difficult or unlikely,” they said.

After the Track 1B process is complete, CAISO says it will embark on Track 2 in time for the 2020 auction with “potential comprehensive changes.” The ongoing overhaul indicates the current CRR process is due to change significantly in coming years.

April 9, 2018

Interior Plans Would Boost Mass., NY Offshore Wind

By Michael Kuser

Offshore wind got a boost on two fronts Friday when U.S. Interior Secretary Ryan Zinke announced two new proposed offshore wind leases for Massachusetts, while the Interior Department’s Bureau of Ocean Energy Management issued a call for commercial interest in four wind energy areas in the New York Bight.

“The Trump administration supports an all-of-the-above energy policy and using every tool available to achieve American energy dominance,” Zinke said.

BOEM on Apr. 11 will publish in the Federal Register a proposed sale notice for the Massachusetts leases and a call for information and nominations on the New York areas.

BOEM Ryan Zinke Offshore Wind — Offshore Wind Platform | *Deepwater Wind*

Massachusetts later this month will select one of three bids received in December for up to 800 MW of offshore wind energy projects, with contracts to be submitted at the end of July. The bidders include Bay State Wind, a joint venture between Orsted and Eversource Energy; Deepwater Wind; and Vineyard Wind, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners.

All three developers have purchased renewable energy leases off Martha’s Vineyard from BOEM. (See Mass. Receives Three OSW Proposals, Including Storage, Tx.)

OSW, Yes; Offshore Drilling, No

The proposed lease areas offshore from Massachusetts total 460 square nautical miles.

Interior Counselor for Energy Policy Vincent DeVito said in a statement that the federal government had worked “with a broad community of engaged stakeholders, including fishing communities,” to identify “areas that can support a large-scale commercial wind project, while minimizing the impacts to fishing habitats, marine species and other uses” of the outer continental shelf.

The proposed “call areas” being considered in the New York Bight — a region of the Atlantic Ocean between Long Island and the New Jersey coast — are named Fairways North, Fairways South, Hudson North and Hudson South, and comprise 2,047 square nautical miles.

BOEM Acting Director Walter Cruickshank said in a statement that the bureau and stakeholders will look at the potential impacts of offshore wind in New York.

“For example, commercial and recreational fishing are important cultural and economic activities that must be considered,” Cruickshank said.

New York in January released its master plan for 2,400 MW of offshore wind development, which includes an initial phase of solicitations this year and next for at least 800 MW. (See NY Offshore Wind Plan Faces Tx Challenge.)

Gov. Andrew Cuomo released a statement Friday welcoming BOEM’s support in advancing the state’s offshore wind plan but added he remains “deeply concerned by the federal government’s proposal to allow new offshore oil and gas drilling.”

“New York has formally requested to be excluded from this offshore drilling plan, and we believe offshore wind is a better direction for our economy, for our environment and for our energy future,” Cuomo said.

April 9, 2018

FERC Approves Change to Eliminate Gaming in SPP Markets

FERC last week overruled a stakeholder’s objections in approving SPP’s proposed Tariff revisions to eliminate a gaming opportunity related to regulation deployment adjustments (ER18-757).

The commission found that SPP’s modifications to the regulation deployment adjustment charge and payment calculations to be just and reasonable, accepting them to become effective May 1.

FERC said that by allowing the use of mitigated energy offer curves or as-dispatched energy offer curves in regulation deployment adjustment calculations, the Tariff revisions “help ensure that the regulation deployment adjustment amount will compensate resources for their output associated with regulation deployment.”

The RTO’s Market Monitoring Unit had pushed for the change (MWG-RR243), saying manipulation of regulation-down offers has cost the SPP market more than $1 million in recent years.

FERC disagreed with Westar Energy’s argument that the revisions represent a “fundamental change” in the incentives for market participants’ selection between the energy or regulation markets. It also disagreed with Westar’s complaint that incorporating resources’ mitigated energy offer curves as a component of the regulation deployment adjustment’s calculation is unjust and unreasonable — noting that market participants perceiving any inequity between the markets can modify their regulation offers accordingly.

SPP FERC Regulation Deployment Adjustment — Westar Energy’s headquarters | *Seeking Alpha*

The commission said it agreed with the MMU that closing the gaming opportunity outweighed concerns that the Tariff revisions would extend the use of the mitigated energy offer curve beyond local market power mitigation.

“We find that using the mitigated energy offer curve when calculating the regulation deployment adjustment amount should limit gaming opportunities and also helps ensure that the resources deployed to supply regulation recover their costs,” FERC said.

Westar contended that the proposed revisions would automatically cause all regulation deployment adjustment payments to be based on the type of offer (mitigated or market-based) that causes credits to be minimized. It said SPP was proposing a solution that “inappropriately and unreasonably affects all resources, when SPP should instead narrowly address the few bad actors believed to be economically withholding.”

The utility proposed that SPP be required to apply some type of economic withholding evaluation instead. SPP responded that Westar had confused gaming with economic withholding, and said that its market-clearing engine co-optimizes energy demand and regulation requirements with energy and regulation offers while ensuring resources are agnostic relative to selection for energy or regulation.

Commission Denies Golden Spread’s Rehearing Request

The commission denied Golden Spread Electric Cooperative’s rehearing request for its 2017 approval of SPP’s Order 825 compliance filing (ER17-772).

FERC’s September order accepted Tariff changes made to comply with Order 825, which requires RTOs to settle real-time energy, operating reserves and intertie transactions in the same time interval it dispatches, prices and schedules them, respectively. (See FERC Approves SPP Shortage Pricing Changes.)

Golden Spread argued that SPP’s filing did not comply with Order 825 because it did not address the RTO’s practice of committing additional capacity through the reliability unit commitment (RUC) process or through manual operations that can prevent scarcity pricing events. The commission said the protests were outside the proceeding’s scope and encouraged the cooperative to address its concerns through SPP’s stakeholder process.

In its appeal, the cooperative argued that FERC’s dismissal of its concerns as beyond the scope “effectively overlooks the fact that SPP’s current, unchanged practices purposefully and fundamentally mask the presence of market scarcity and subvert the primary goals of Order No. 825.”

The commission noted that its September ruling found that Order 825 did not require Golden Spread’s suggested modifications to SPP’s RUC or manual commitment processes. “The absence of such requirements places these SPP practices beyond the scope of a compliance filing,” FERC said.

The commission has “stated on numerous occasions” that the sole relevant issue in reviewing compliance filings is whether they comply with the directions in the order requiring them, it said. It also pointed out that it will not consider arguments raised in a compliance proceeding “that are not responsive to the narrow issue of the filing utility’s compliance.”

FERC Accepts ITC Midwest’s Interconnection Agreement

FERC accepted ITC Midwest’s third restated interconnection agreement with Corn Belt Power Cooperative and Interstate Power and Light (IPL), effective April 7 (ER18-801).

The agreement adds a substation as an additional point of interconnection between IPL and Corn Belt. The interconnection was expected to be in service in the first quarter of 2018.

Corn Belt and IPL are parties to other dockets (consolidated under ER15-2028) before the commission involving Corn Belt’s entry into SPP as a transmission owner and the resulting implications for existing agreements between the utilities.

The original agreement with ITC dates to 1956 but was designated as a grandfathered agreement (GFA) under MISO’s Tariff. ITC said that because of its possible GFA status under SPP’s and MISO’s Tariffs, Corn Belt and IPL had declined to execute the agreement.

The commission dismissed concerns by Missouri River Energy Services (MRES) that the proceeding’s outcome could affect cost allocations in its transmission zone, finding the proceeding “not to be relevant” to ITC’s proposed addition of the substation.

“We therefore are not persuaded to consolidate this proceeding with [ER15-2028] or otherwise hold it in abeyance,” FERC said. It said its acceptance of the agreement does not affect the ongoing proceeding in that docket.

East River Co-op Granted Waiver to Revise Tx Rates

The commission granted East River Electric Power Cooperative’s request for a one-time waiver to revise its 2018 update and associated informational filing for its formula rate template and protocols under SPP’s Tariff (ER18-860).

The waiver allows East River to reclassify the Groton-Ordway 115-kV transmission project, which it said it had initially understood should be classified as a base plan upgrade eligible for recovery through zonal and regionwide charges. The project will now be included in the cooperative’s annual transmission revenue requirement as part of its zonal charges.

East River is a wholesale electric power supply cooperative serving 24 rural electric cooperatives and one municipally owned electric system in eastern South Dakota and western Minnesota. It became a TO member of SPP in 2015 as part of the Integrated System.

— Tom Kleckner

April 9, 2018

Experts Predict EV Adoption, Charge Management in Illinois

By Amanda Durish Cook

Electric vehicle experts last week descended on the Illinois Commerce Commission to discuss the eventual adoption of EVs in the state and the need to manage customers’ charging patterns to avoid stressing the grid.

The ICC held the policy session in Chicago to learn more about the relationship between EVs and the grid. Panelists agreed that widespread EV adoption is years away and said state policymakers will eventually devise ways to stagger charging.

Illinois now has 15,000 EVs, with 100,000 projected to be on the road in the coming years, said Katie Bell, Tesla’s energy policy and business development manager. A recent study by the Illinois PIRG Education Fund and Frontier Group predicted Chicago will have 81,000 EVs by 2030. The ICC predicts that widespread EV adoption could bring Illinois up to $43 billion in benefits by 2050, “stemming from reduced utility bills, carbon pollution and fuel and vehicle expenses.”

EV Electric Vehicle Charging Stations Illinois — Tesla Supercharger station | *Tesla*

Bell said Tesla is working to make its cars more affordable and examining how to site new charging stations, as well as ways to encourage owners to charge during off-peak hours.

“We’re trying to give customers a better option than what’s available today,” Bell said.

EVs are expected to drive 54% of new car sales by 2040, according Bloomberg. The ICC says that Illinois currently ranks sixth in the nation in terms of numbers of plug-in EVs.

“Currently, Illinois’ framework is light in that it doesn’t heavily regulate electric vehicles,” said energy attorney Elizabeth McErlean of law firm McGuireWoods.

McErlean said the question still remains whether EV charging station owners should be regulated as public utilities, though the Illinois General Assembly in 2012 exempted station owners from the definition of utilities. With Illinois keeping regulations light to encourage the development of private EV charging stations, McErlean said charging providers can grow unfettered and experiment to find best practices.

“Fossil fuels have enormous impact on our climate and health,” said Christie Hicks, manager of clean energy implementation for the Environmental Defense Fund. “Electric vehicles offer the greatest emissions reduction in the transportation sector. … It’s not a matter of when electric vehicles are coming, but how. … The future is electric.”

But Hicks acknowledged that fears of low travel range, scarce inventory and high upfront costs remain a barrier to widespread adoption.

Citizens Utility Board Executive Director Dave Kolata said there’s “a lot of momentum for transportation electrification.” He noted that charging patterns must be optimized, and that if all EV owners charge at night when wind generation creates negative electricity prices, it will eventually create a new peak. Kolata said he supported using time-of-use rates for charging and predicted that EVs will ultimately be automated to respond to price signals while charging.

When Illinois Senior Assistant Attorney General Susan Satter asked the room who owned an EV, she was greeted by a show of four or five hands.

“I have an EV,” Satter said. “Eighty percent of charging is done at home, in the garage. When we talk about charging stations, we’re talking about filling in for the times when we’re not at home.”

Satter said consumers have a lot of options for the fill-in charges: employers, city-owned free or low-cost charging stations, and stations placed at shopping centers to attract customers. Satter said states must be careful of developing policies that only consider utilities’ charging projects.

“We’re at the beginning of the EV revolution,” she said.

Satter said the growing number of EV owners will increasingly need to understand energy pricing and peak demand in order to select the lowest-price charging times. Panelists generally agreed EV owners will eventually need to be pushed to charge at off-peak times to avoid stressing the grid.

Satter pointed out that EV owners are still early adopters that earn well above the national median income and cautioned utilities about providing these owners incentives when they’re already high earners.

“What is an incentive? It’s giving people more money,” Satter said. “When we get past the early adopters and into the mass market, it’s going to be cheaper.”

Other panelists urged policymakers to be cognizant that EV owners today tend to be wealthier and less in need of subsidies.

“Many of the communities that stand to benefit the most from electric vehicles don’t have access to them,” Hicks said. She urged policymakers to subsidize charging stations and develop more local pilot programs.

Kolata agreed that incentives for EV adopters should not come at the cost of other economic classes of customers.

But Ryan Schonhoff, Ameren supervisor of rates, said lack of a “holistic charging system” is hindering growth of EVs.

Chicago Transit Authority analyst Kate Tomford said a solar and storage combination could work well in the city’s bus garages. She said that while the city owns two electric buses now, it plans to have a fleet of 20 in the “near future.”

Commonwealth Edison Vice President of Regulatory Policy and Strategy Jane Park said EVs in the U.S. are set to reach cost parity with internal combustion engine vehicles in seven years and credited growing popularity with “a confluence of technology advancements and national and internationally policy.” States with the highest EV adoption offer a “portfolio” of purchase incentives, dynamic pricing programs, infrastructure plans and a plan for access for low-income communities, she said.

Park said it’s not quite the time to place strict regulations on EV ownership because policymakers don’t yet understand how to strike the best balance of regulations.

April 9, 2018

California Utilities Propose New CCA Rules

By Jason Fordney

California’s three large investor-owned utilities asked state officials last week to change the rules to protect bundled customers from being saddled with expensive long-term renewable contracts as others defect for increasingly popular community choice aggregators (CCAs).

Much has changed in the state since CCAs were created in the wake of the California energy crisis of the early 2000s, the utilities argued. The CCAs didn’t start operating until 2010 but have pulled 40% of Northern California’s bundled load from Pacific Gas and Electric, and 35% of Southern California Edison’s retail load is in the process of CCA formation. The two utilities, along with San Diego Gas & Electric, filed a 363-page proposal with the California Public Utilities Commission. They noted that 85% of their load could move away by the mid-2020s.

“The combination of these two developments leaves high-cost, long-term renewable contracts in the IOUs’ bundled service customer portfolios that are far in excess of their need,” the utilities said. The situation has also brought the utilities’ procurement of large-scale renewable projects to a halt.

The cost of renewable power has decreased significantly since the legacy contracts were signed, which the IOUs say “transformed the renewables market consistent with state policy and commission direction.”

The more than 200 legacy contracts representing hundreds of millions in costs were the topic of a hearing at the Senate Energy Committee last summer, at which Chairman Ben Hueso expressed concern about creating an ungovernable system. (See California CCAs Spur Worry of Regulatory Crisis.)

CCA Long-Term Renewable Contracts — California’s utilities proposed a new regulatory regime for CCAs to the CPUC | © *RTO Insider*

The PUC got some pushback from CCAs in February when it fast-tracked new regulations for new and expanding CCAs over resource adequacy concerns. (See CCAs Oppose CPUC Decision, Process.)

The April 2 IOU proposal would restructure the power charge indifference adjustment (PCIA), which is meant to ensure that bundled customers are not affected financially by other customers deciding to join CCAs.

The IOUs had previously proposed that the benefits and costs of previous IOU procurement be allocated to customers for whom those assets had been procured or constructed, a process called the portfolio allocation methodology (PAM).

Despite their new proposal, the utilities “still support their original PAM proposal as being a viable and relatively straightforward methodology to implement to ensure an equitable and efficient allocation of benefits and costs among all customers should the commission wish to consider it,” they said.

The new proposal uses two allocation mechanisms: the “green allocation mechanism” (GAM) for renewable portfolio standard-eligible resources and large hydro, and a “portfolio monetization mechanism” (PMM) including gas, nuclear, non-pumped hydro and energy storage.

“The joint utilities’ proposal of combining the allocation of [renewable energy credits] and [resource adequacy] from RPS and large hydro-electric resources (GAM) with a cost-based allocation approach for other resources (PMM) balances the resource technology concerns of a number of CCA parties while ensuring compliance with state law and continued support of state policy objectives,” they said.

The IOUs proposed that all contracted and utility-owned resources subject to the current methodology be considered eligible for GAM or PMM.

April 9, 2018

MISO Looks to Address Changing Resource Availability

By Amanda Durish Cook

CARMEL, Ind. — MISO is kicking off an effort to examine its changing resource availability in the face of increasing generation retirements, poor outage coordination, growing volumes of emergency-only capacity and rising use of intermittent resources.

“In the past, a [maximum generation event] occurred every year or two when MISO needed access to emergency-only resources. Now, there have been 12 since the start of the 2016/17 planning year, and they have occurred in all four seasons,” the RTO wrote in a white paper laying out the issue.

To remedy the situation, MISO is broadly proposing to increase transparency of resource availability times and energy requirements, revamp availability requirements, and improve price signals to attract generator response.

But it needs stakeholder feedback to develop the specific rules and market improvements needed to meet those goals, RTO staff said at an April 5 Reliability Subcommittee meeting.

‘Degrading Ability’

MISO resource availability — Bladen | © *RTO Insider*

Executive Director of Market Design Jeff Bladen said MISO is experiencing a “degrading ability to convert committed capacity” in a reliable fashion because of “more volatile supply and demand conditions,” forcing it to increasingly rely on resources not scheduled in the day-ahead market.

“There is less operational energy available through dispatch than the year before,” Bladen said. “Each succeeding year we’ve had fewer megawatts offered.”

MISO had 126 GW in average energy must-offers in the 2014/15 planning year, with about 17 GW of outages. In the 2015/16 and 2016/17 planning years, offers declined to 125 GW and 117 GW, respectively, while outages rose to 18 GW and roughly 23 GW.

Bladen said peaks are becoming less predictable and occur even in shoulder seasons: “It’s becoming apparent that this is a challenge we will face year-round, and not just in the summertime.” He said outages have played a role in most of MISO’s maximum generation events since late 2016, with the majority occurring during off-peak months.

The RTO could once confidently group outages in the spring and fall because it had a greater margin of error.

“That seems to be a fleeting confidence. We have to plan for more volatile loads,” Bladen said.

MISO’s “resource availability and need” topic evolved from a 2015 proposal to create seasonal capacity procurement requirements, a generally unpopular move among stakeholders. RTO officials now say the proposal is no longer as simple as applying separate clearing requirements in a two- or four-season capacity auction.

“In some cases, we may have jumped to conclusions on some of these challenges — opportunities, but challenges nevertheless. This topic is an evolving one,” Bladen said.

Staff have said solutions could include a capacity procurement requirement and an examination of whether current requirements and price signals must be revised in light of shifting availability, a product of tightening supply, more renewable energy participation, increasing instances of extreme weather events and an aging baseload fleet more susceptible to outages.

MISO is already considering whether to factor the effects of planned and maintenance outages on peak in its loss of load expectation study by the 2019/20 planning year, which could boost the RTO’s planning reserve margin requirement. (See MISO RASC Zeroes in on Priorities.)

resource availability miso — Peak loads shown in red versus supply over 2016 and 2017 | *MISO*

Customized Energy Solutions’ Ted Kuhn asked why MISO is regarding retirements as out of the ordinary given that they’ve always existed.

“The fleet in general is getting older in aggregate,” said Bladen, stressing that MISO’s current retirement rate is amplified when compared to the historical rate.

He said MISO’s expected renewable expansion combined with its aging baseload generation will only exacerbate reliance on emergency-only resources.

“The queue today gives us every indication that more intermittent resources are on the way,” he said.

Bladen added that individual load-modifying resources often don’t perform to the levels accredited to them in the annual capacity auction and can have long start-up times, up to 12 hours.

Madison Gas and Electric’s Megan Wisersky criticized some aspects of MISO’s longstanding rules for load-modifying resources. She noted the RTO has always required load-modifying resources to be available for both capacity and transmission emergencies and restricted them to being price takers in the market.

“It’s almost like this trend is self-fulfilling,” Wisersky said.

Bladen said MISO would be looking for stakeholder input on any changes to the treatment of load-modifying resources.

“The idea is that we give tools to our resources so they have the ability to cure,” he said. MISO’s load-modifying resources currently do not have a must-offer obligation for any time periods outside summer, and they can only be called on five times each summer during emergency declarations.

We Energies Tony Jankowski asked why MISO was hinting at the need for such drastic measures and cautioned against overbuilding the system. Other stakeholders in attendance also worried aloud that the RTO would use the white paper as justification for big changes.

Bladen said MISO’s 25% expectation that it will initiate emergency operating procedures sometime this spring belies the fact the RTO likely faces a nearly 100% chance of entering an emergency during the season.

“We’ve been in a max gen event 12 out of the last 11 quarters. We’re not saying the sky is falling, but we’re saying it’s cloudy, and we’re concerned,” Bladen said.

“Despite the odd way of saying it, our goal is to be adequate,” he added, smiling.

Last month, Reliability Subcommittee Chair Bill SeDoris said he expected the discussion on the topic to extend into 2020.

April 9, 2018

SPP Seams Steering Committee Briefs: April 4, 2018

SPP and Associated Electric Cooperative Inc. stakeholders last week approved a scope for a joint study to determine the existence of any mutually beneficial transmission projects, enabling them to continue with their agreement to conduct a biennial study.

The SPP-AECI Interregional Planning Stakeholder Advisory Committee meeting was held April 4 during the Seams Steering Committee meeting in Dallas.

A joint planning committee will determine the cost allocation of any potential projects on a case-by-case basis, with costs assigned equitably based on the constraint being resolved.

Should any projects be identified, SPP will solicit detailed proposals, similar to those used for its Order 1000 competitive projects.

The groups’ 2016 joint study identified a pair of projects that is still awaiting final regulatory approval.

TSR Proposal

The seams committee also discussed a draft business practice for unreserved use of the transmission system. The draft envisions three days for entities to submit transmission service requests (TSRs) for unreserved use, allowing them to avoid usage charges. After three days of unreserved use, a TSR would be required.

February M2M Results in $3.97M Charge to MISO

SPP and MISO’s market-to-market (M2M) process resulted in a nearly $4 million payment to SPP for February, the seventh straight month, and the 15th of a total of 17 M2M months, that MISO has paid its seams partner.

SPP has now received almost $48 million in M2M payments since the two RTOs began the process in March 2015, staff told the SSC.

SPP’s Nashua-Hawthorn and Riverton-Neosho-Blackberry flowgates accounted for most of the charges, binding for a combined 430 hours in January because of high winds and outages. That resulted in $3.4 million of the MISO payments to SPP.

— Tom Kleckner

April 9, 2018

UPDATE: Vistra-Dynegy Merger Closes After FERC Nod

By Rich Heidorn Jr.

Vistra Energy said Monday it closed its acquisition of Dynegy following a FERC order concluding the $1.7 billion deal raised no competitive concerns (EC18-23).

The all-stock deal will create a power generation and retail giant owning 40 GW of capacity and serving nearly 3 million customers, mainly in ERCOT, PJM and ISO-NE. FERC’s April 4 approval was the last regulatory step required to complete the deal, which had already been cleared by regulators in New York and Texas.

Vistra-Dynegy Merger FERC — | *Vistra Energy*

Dynegy’s combined cycle gas turbine fleet and geographically diverse portfolio were a big attraction for Vistra, which owns 18,000 MW of generation capacity in ERCOT. Dynegy’s 27,000 MW will give it the following market shares in these organized markets:

CAISO: 2.96% (2.16% after accounting for capacity under long-term contracts).
ISO-NE: 12.1% (Rest of Pool zone); 11% (Northern New England zone).
MISO: 0.3%.
NYISO: 4.6%.
PJM: 6.9% (RTO-wide); 3% (MAAC locational deliverability area); 7% (PPL LDA).

FERC has no jurisdiction over the combined company’s generation in ERCOT. The Public Utility Commission of Texas declined a staff recommendation that it require Luminant, Vistra’s generation arm, to divest itself of at least 1,281 MW of capacity to keep the post-merger Vistra below the statutory cap of 20% of ERCOT installed capacity. (See Texas PUC Conditionally Approves Vistra-Dynegy Merger.)

FERC rejected a protest by Public Citizen, which argued that the applicants’ horizontal competitive analysis should have included generation owned by Dynegy’s major shareholder, Energy Capital Partners. Public Citizen noted that ECP is seeking to acquire Calpine.

But the commission ruled ECP’s generation did not have to be included in the analysis after its action in January to reduce its stake in Dynegy from 14.88% to 9.9%, below the 10% threshold that imputes control. ECP’s post-transaction ownership of the combined Vistra entity will be 1.7%, FERC said. “As such, under the commission’s regulations, Dynegy will not be affiliated with ECP, nor under its control,” FERC said.

The commission also said the Dynegy acquisition would not have an impact on vertical competition, saying the only transmission facilities controlled by the applicants in commission-jurisdictional markets aside from generator interconnections are Smoky Mountain Transmission — 86 miles of transmission connected to the Duke Energy Carolinas and Tennessee Valley Authority systems — and Electric Energy, six 8-mile-long parallel generation tie lines. Both provide service under commission-approved open access tariffs.

In related orders Thursday, FERC also set hearing and settlement procedures to review the reasonableness of the reactive service rates for Dynegy’s Illinois Power (ER16-233-001, EL18-133) and 15 other subsidiaries (ER15-1641, et al.).

Vistra CEO Curt Morgan’s executive team, including Chief Operating Officer Jim Burke and Chief Financial Officer Bill Holden, will lead the combined company, based at Vistra’s headquarters in Irving, Texas. The new board is expected to have 11 directors: the current eight members of the Vistra board and three members from Dynegy’s board.