Power Markets at Risk from State Actions, Speakers Tell FERC

By Rich Heidorn Jr. and Michael Kuser

WASHINGTON — RTO capacity markets are in serious danger from state renewable procurements and subsidies for nuclear plants, speakers told FERC on Monday.

FERC RTO Capacity Markets — Bentz | © *RTO Insider*

Jeffrey W. Bentz, director of analysis for the New England States Committee on Electricity, said failing to coordinate ISO-NE’s capacity market with state renewable procurements will lead to oversupply and excessive costs to ratepayers in the region.

“Maybe that’s not in the next three to five years,” he said on the first day of a two-day technical conference on the impact of state electricity policies on ISO-NE, NYISO and PJM. “But down the road, clearly we can see that train wreck coming and it would probably be the end of the markets as we know them today.”

New Hampshire Public Utilities Commissioner Robert R. Scott also had a warning: “It is not possible to fully preserve the benefits of competition … with a market design that seeks to replace low-cost resources with resources that cost more,” he said in his written testimony.

FERC scheduled the conference out of concern that the RTO/ISO energy and capacity markets could lose relevance — or have their pricing signals undermined — because of state plans to procure out-of-market renewable power and prop up nuclear generators (AD17-11).

The conferees discussed the grid operators’ efforts to address state-market conflicts, including white papers by PJM, and the New England Power Pool’s Integrating Markets and Public Policy (IMAPP). The conference also came as FERC has pending before it challenges to zero-emission credits for nuclear generators in New York and Illinois.

FERC staff indicated the high stakes posed by increasing tensions between state policies and RTO/ISO resource adequacy efforts, asking witnesses to consider whether there will be “a diminished role for the RTO/ISO.”

Taking Matters into Their Own Hands

During the hearing, some state officials said they had taken power procurement into their own hands because the capacity markets haven’t delivered the types of resources they desire.

Among the problems: the lack of a price on carbon emissions and no recognition of the value of fuel diversity.

“The market was only delivering one product: natural gas [generation],” said Robert Klee, the commissioner of the Connecticut Department of Energy and Environmental Protection, who said the dependence on gas caused reliability concerns during the winter peaks, when generators must compete for fuel with heating customers. “We’ve been pretty lucky to have mild winters the last few years. We don’t want to go back to the polar vortex.”

Klee said difficulties getting additional gas pipelines to supply the region’s generators had heightened state officials’ concerns.

Still, he suggested state procurements likely won’t provide all of the new power supplies needed for New England states planning to electrify transportation and building heating. “That’s a lot of growth,” he said.

Angela M. O’Connor, chair of the Massachusetts Department of Public Utilities, said the markets “have provided tremendous benefits” and that the capacity market has produced new generation to maintain reliability.

“But we are at a crossroads, and what the legislature requires us to do, we have to do,” she said, referring to mandates to reduce greenhouse gas emissions by 80% below 1990 levels by 2050, and procure hydropower and offshore wind.

“The wholesale markets [are] … not going to get us our large-scale hydro or the offshore wind — or, frankly, gas pipelines.”

Susanne DesRoches, deputy director of infrastructure policy for New York City, agreed. “We support the wholesale markets, but we see that innovation is needed,” she said.

Scott Weiner, deputy for markets and innovation at the New York State Department of Public Service, said the state is at an “inflection point.”

“Is there a role for the markets? Absolutely. Is it going to change? Probably. … The energy markets will always be there. The capacity market may not be.”

Seth Kaplan, senior manager of regional government affairs for EDP Renewables, said the markets were constructed with gas turbines in mind at a time when renewables had little market share. Given the changes since then, he said, “it’s not surprising that a square peg doesn’t fit into a round hole.”

Grid Operators Respond

Matt White, chief economist for ISO-NE, insisted the RTO had no intention of relinquishing its role as the guarantor of resource adequacy standards.

“We believe that resource adequacy requires a single point of responsibility and accountability. ISO-NE currently bears this responsibility. Another option is for the states to take on this role through local utilities; to date, however, the New England states have not expressed interest in assuming this role,” the RTO said in its written testimony.

NYISO CEO Brad Jones said that while the ISO supports New York’s ZECs, the program needs to be incorporated into the market. He said it could take three years to work out a solution.

Generators’ Concerns

That was too long for witnesses representing independent power producers.

“The challenge before the commission, the states and all other stakeholders is no less than the question of whether the power industry will continue to use competitive markets as the basis for investment decision-making,” Peter Fuller, vice president of market and regulatory affairs for NRG Energy, said in his written testimony.

In his response to questions, Fuller was a bit more optimistic: “We believe the markets can be adapted to give the states what they need … and figure out a way for those resources to have their role in the markets while not undermining the markets for those of us who have invested strictly on the basis of market revenues.

“I don’t think we’re are the tipping point yet,” Fuller said. “But if we don’t move fairly quickly [to] … ensure that markets can actually support the … renewable-based future … then we could very well tip over.”

John Reese, senior vice president of Eastern Generation, said the issue is particularly acute in NYISO, which has a one-year forward capacity auction, unlike the three-year auctions in PJM and ISO-NE. Eastern Generation operates almost 5,000 MW of generation in NYISO and PJM, including 18% of New York City’s capacity.

“I can’t wait for seven years or eight years for this to work out,” he said. “Regardless of which model we end up with, we need to be sending investment signals now!”

Déjà vu

John Shelk, CEO of the Electric Power Supply Association, lamented that policymakers had not accomplished more since FERC’s September 2013 technical conference on the Eastern capacity markets. (See Capacity Market Attracts Praise, Criticism at FERC.)

“The one area of agreement is exactly the place that we’re headed to that everyone said four years ago, ‘Don’t go there,’ which was tranches: ‘Let’s pick X amount of nuclear, X amount of coal, X amount of gas.’ Now it’s worse. Now we’re not just picking fuels, we’re picking specific [generating] units that otherwise would have exited.

“This may have started in New York last year … but in short order it was adopted in my home state of Illinois and as everybody knows, it’s now being actively considered in Ohio, Pennsylvania and New Jersey and Connecticut. So this isn’t just a threat to the market in New York.” (See related story, PJM Stakeholders Offer Vastly Different Takes on Markets’ Viability.)

Without changes, Shelk said, his members may have to seek state approval of “flexible energy credits” to support generators that provide the ramping needed to support variable resources.

New York regulator Weiner also called for urgency. “We’ll be having this same discussion two years from now unless there’s a recognition that things have changed,” he said.

LaFleur: FERC Will Act

In opening remarks Monday, acting FERC Chair Cheryl LaFleur acknowledged, “I’m very well aware that the wholesale markets … only can exist and continue through the buy-in of the states.

“I have said very many times there are three ways this could go: a designed market solution, a litigated outcome or a planned change in the regulatory construct of how we handle resource adequacy. The fourth outcome — an unplanned change in the regulatory construct, or unplanned and piecemeal regulation — is one that I think we should avoid because I think it would be a bad outcome for customers and market participants.

“Once we restore our quorum, this commission will almost certainly have to decide litigated complaints that are already pending before us, even as regions may be working on market solutions to file with us,” she continued. “While we can’t decide anything immediately because we lack a quorum, we must shape options and recommendations for a FERC 2.0 based on the record we develop today and tomorrow.”

[Editor’s Note: RTO Insider will have full coverage of the technical conference later this week and in the May 9 newsletter.]

May 2, 2017

FirstEnergy Hopeful on State, Federal Support

By Jason Fordney

FirstEnergy is encouraged by possible new state and federal support for nuclear and coal-fired plants, but the company said it has not changed its plan to divest its merchant generation and become a fully regulated company by the middle of next year.

“There is absolutely no change in the strategic direction that we want to take this company in,” FirstEnergy CEO Charles Jones said during an April 28 call to discuss first-quarter earnings. “We do not want to be exposed to commodity-exposed generation any longer than we have to be.”

In light of a $164 million first-quarter charge over unfulfilled coal delivery contracts, the Ohio-based utility holding company is eyeing a proposed nuclear subsidy from its home state and signals from U.S. Energy Secretary Rick Perry that federal policies toward coal generation could change.

The company reported earnings of $205 million in the quarter on revenues of $3.6 billion, including the charge related to coal delivery contracts. In the first quarter last year, the company earned $328 million on revenue of $3.9 billion.

Subsidiary FirstEnergy Solutions recently reached a $109 million settlement with BNSF Railway and CSX over long-term coal delivery contracts it terminated. The payments, guaranteed by FirstEnergy, are set to have begun on May 1, the company told the U.S. Securities and Exchange Commission in an April 27 filing. If that settlement is not completed — or a similar dispute with BNSF and Norfolk Southern Railway is not settled — damages could be much higher and lead FES to file for bankruptcy.

Coal supplier Tunnel Ridge also filed suit against First Energy subsidiary AE Supply over a terminated coal supply contract, which the company said could “be material.”

FirstEnergy executives are hopeful that a bill for a proposed “zero-emission nuclear resource program” will reach Ohio Gov. John Kasich’s desk by the end of June. The legislation would require electric distribution companies to secure the credits from qualified generation resources and recover the costs from ratepayers. Awarded according to nuclear output, the credits would gain FirstEnergy about $300 million/year.

“That amount in and of itself, I don’t think, is enough to necessarily avoid a FES bankruptcy,” Jones said. “It would be enough potentially for those assets to emerge from bankruptcy and for a reputable nuclear operator to be willing to take them on and run them forward.”

FirstEnergy touts the proposal as helping the state meet its energy goals, but critics say it is a bailout for the company’s nuclear plants. Ohio Citizen Action said the money should instead be invested in renewable energy and energy efficiency projects.

FirstEnergy owns the 889-MW Davis-Besse nuclear plant near Toledo and the 1,231-MW Perry plant near Cleveland, but the company wants to close or sell them.

Jones said that as the company assesses the implications of a FES bankruptcy, it is closely monitoring whether a new Energy Department study will lead to some type of support for coal plants.

Perry last month ordered his department to present by mid-June its evaluation of the premature retirements of baseload power plants, which is in part intended to determine whether energy markets adequately compensate the reliability benefits they provide. It is unclear what initiatives might flow from the process.

Perry’s memo mentioned “the market-distorting effects of federal subsidies that boost one form of energy at the expense of others” and said the study would provide “concrete policy recommendations and solutions.”

Jones said the Bulk Electric System is being overlaid on a congested and “not robust” natural gas delivery system, and problems with the natural gas system will flow to the electricity system.

FirstEnergy last quarter entered into an agreement to sell about 1,500 MW of AE Supply’s gas and hydro assets for $925 million, a deal expected to close in the third quarter. A $40 million agreement to sell property and assets at the Hatfield’s Ferry power station is expected to close in the third quarter of next year. Mon Power in March agreed to purchase the Pleasants power plant from AE Supply for $195 million.

May 2, 2017

PJM Markets and Reliability and Members Committees Briefs

Stakeholders Defer Vote on Regulation Revisions

WILMINGTON, Del. — John Horstmann of Dayton Power and Light expressed concern that PJM’s proposed regulation changes will have a “huge impact” on existing Reg D providers and noted that complaints have been filed at FERC opposing the changes PJM implemented in January. (See “New Regulation Rules Improving ACE Control,” PJM Operating Committee Briefs.)

Based on the potential issues, Horstmann made a motion at Thursday’s Markets and Reliability Committee meeting to defer a vote on the package until June, which would allow for the comment period at FERC to close. Members approved the delay in a 3.76 sector-weighted vote.

The package, jointly developed by PJM and the Independent Market Monitor, would replace the benefit factor with the “regulation rate of technical substitution,” and the effective megawatt calculation would be the area under its curve. The mileage ratio from the regulation performance credit would be replaced with the “marginal rate of technical substitution” (MRTS), which will be added to the regulation capacity credit. Bowring said later that PJM meeting rules prevented him from responding to comments from Horstmann that he believed to be inaccurate.

The 24-month transition period will have a minimum MRTS of .65 for the first year, followed by a floor of .5 for the last year. The minimum allowable participation threshold will be raised from 40% to 50%.

“The transition offer by PJM, while a nice gesture, [is] not really compensatory for existing Reg D providers,” Horstmann said.

CCPPSTF Charter Approved

The MRC approved the charter for the Capacity Construct/Public Policy Senior Task Force, declining to adopt language changes proposed by Market Monitor Joe Bowring.

Bowring suggested that one of the group objectives in the charter, which calls for “modifications to [the Reliability Pricing Model] that could accommodate/address both capacity construct objective and state actions,” wasn’t consistent with the charter’s mission to “ensure potential state public policy initiatives and Reliability Pricing Model objectives are not at odds.”

Bowring found no members willing to take up his suggested edits, and the charter passed with one objection and two abstentions.

The task force’s three meetings since its formation in January have revealed deep differences between stakeholders. (See PJM Capacity Task Force Debates the Value of Price Transparency.)

Stakeholders Push Back on Paying for Frequency Response

PJM markets and reliability committee frequency response — Schweizer | © *RTO Insider*

PJM’s David Schweizer presented a first read of the RTO’s plan to address FERC’s recent Notice of Proposed Rulemaking on frequency response. PJM’s proposal has suggested that it might consider compensating units for maintaining primary frequency response, even though the NOPR is silent on the topic. (See “PJM Wants to Study Frequency Response,” PJM Operating Committee Briefs.)

John Farber of the Delaware Public Service Commission staff took issue. “If we’re purchasing this premium [Capacity Performance product], it should include this primary frequency response,” he said.

He asked that the problem statement and accompanying issue charge include language that the compensation would be considered “if appropriate or necessary.” Schweizer said the documents were developed to allow dialogue on the topic while designing proposed solutions.

He said he will be seeking the Operating Committee’s approval on Wednesday and asked that any proposed changes be submitted as soon as possible.

Manual Changes OK’d

Stakeholders endorsed by acclamation two manual revisions:

Manual 14B: PJM Region Transmission Planning Process. The changes correcting wording in the baseline thermal analysis section to match analytical procedures and replace all occurrences of “special protection system” with “remedial action scheme” per a change to the NERC glossary of terms.
Manual 18: PJM Capacity Market. The revisions conform to FERC’s March 21 order tentatively approving PJM’s “enhanced aggregation” plan to allow seasonal capacity participation as CP resources. Stakeholders deferred sunsetting the Seasonal Capacity Resources Senior Task Force until the May meeting so they can be informed of any action on the seasonal capacity filing at FERC. (See PJM Outlines Aggregation Rules for Upcoming Capacity Auction.)

Members Committee

Members Endorse Pricing Revisions

The Members Committee endorsed revisions to PJM’s Tariff and Operating Agreement to address shortage pricing through the operating demand curve. (See “Shortage Rule Takes Effect amid FERC Silence,” PJM Market Implementation Committee Briefs.)

The committee also endorsed changes to Manual 15 regarding fuel-cost policies. (See PJM Fuel-Cost Policy Changes to Take Effect in May.)

Both changes had received substantial discussion in previous meetings, so members had little to say about them Thursday. Bowring reiterated concerns he has mentioned previously about PJM’s approach to handling fuel-cost policies.

– Rory D. Sweeney

May 2, 2017

Soapbox: ESA Explains Complaint on ‘Regulatory Dissonance’

By Matt Roberts

The Energy Storage Association recently filed a complaint with FERC seeking a review of PJM’s prior unilateral changes to its market for frequency regulation. Electricity markets are founded on the principle that practices affecting rates won’t be changed arbitrarily, which ensures fair treatment of companies that invest in and operate electric resources. This is particularly important to ensure new resources like advanced energy storage enter markets and increase competition. For this reason, the decisions impacting tariffs that PJM has made must be submitted for review by FERC.

PJM was the first market to use the near instantaneous response time and precisely controlled input and output of storage systems as a cost-effective tool to ensure short-term grid stability. PJM’s fast frequency regulation service (RegD) was designed for dynamic electric supply assets that are high-power, duration-limited and fast-responding, matching the moment-to-moment deviations of supply and demand to maintain the frequency of the electric grid. In contrast, PJM’s conventional frequency regulation service (RegA) continued to enable the participation of traditional electric supply resources, which have slower response times and ramp rates but can sustain service indefinitely.

As a result, more than 265 MW of advanced energy storage are currently deployed in PJM — nearly all of it competing in the regulation market. These energy storage systems have lowered costs and generated value for the millions of customers in PJM.

Regulation Market Certainty & Unilateral Changes

Over the course of 2015, larger system conditions were leading PJM to call on its energy storage resources to sustain longer-duration service regularly. Because RegD service was designed to be short-duration, PJM decided to make changes to the frequency regulation market while convening a stakeholder consultation process. In late 2015, PJM artificially capped how much RegD service can be provided, and in early 2017, PJM changed the parameters of RegD service, including ending its use for only short-duration needs.

The changes to the parameters of RegD service undermine its original purpose — to provide efficient response to short-term deviations of system frequency (typically measured in minutes). Keeping the grid in balance over longer periods — up to an hour or more — is the role of energy markets or, in emergencies, reserves. In effect, PJM has decided to rely on regulation resources to correct prolonged system imbalances rather than address their root causes. Additionally, the parameters of RegD service also determine how market participants are compensated, and these changes constitute a substantive modification to the actual rates.

Typically, when changes of a magnitude that impact market structures and compensation are being considered, the market operator submits these changes to FERC for review and approval. This review is an important step and is a legal requirement because it ensures that our nation’s wholesale electricity markets remain fair and accessible and that capable assets of all types are rewarded for their performance.

That is why ESA has submitted a Section 206 filing with FERC: to review the decisions made by PJM and enable the changes to RegD service to be considered as a formal tariff change. Moreover, without such review, nothing stops PJM from making changes of similar magnitude again in the future — creating significant uncertainty for energy storage market participants.

It is important to note that PJM staff were presented with proposals to address the broader system challenges that prompted the review of the frequency regulation market design — including proposals from ESA and its members — designed to meet PJM’s needs as the grid operator while enabling energy storage owners to adapt to new conditions.

After much discussion, these proposals from many different stakeholder groups were not put into place, and instead PJM decided to implement the rule changes opposed in our complaint — changes that have obstructed advanced energy storage system owners, operators and developers, and substantively impacted the market tariffs and resulting compensation.

The Path Forward

We very much agree with PJM staff and other stakeholders that the rules and parameters applicable to RegD service can continue to be improved and can also be adapted (or be a model for future markets) to address broader system challenges at PJM like overgeneration and the need for more fast-responding, medium-duration reserves on the system. To date, PJM has done an effective job of addressing these challenges and has not seen any significant change to relevant system reliability metrics (e.g., NERC Control Performance Standard scores) since RegD service was implemented.

However, the root causes of system conditions that led PJM to seek longer-duration response from regulation resources in the first place have not been explored. In effect, PJM has sought to solve a larger system reliability issue through the regulation market. It is important that PJM staff investigate what appears to be a consistent oversupply issue that is leading to the prolonged system imbalances — and specifically calling on RegD resources to be continuously charging over extended periods of time.

Further review by FERC will ensure that the broader influences of these changes on market tariffs and performance are considered holistically, and that PJM will continue to be a leading innovator in creating the model for competitive energy marketplaces. We look forward to working with PJM staff, regulators and a broader group of grid stakeholders on developing a better strategy for ancillary services and applications for energy storage, and by undergoing a more formal process, we can ensure that PJM customers don’t miss out on the ultimate objective — affordable and reliable energy, from increasingly sustainable sources.

Matt Roberts is executive director of the Energy Storage Association, the voice of the energy storage industry, representing manufacturers, utilities, grid operators, developers and technology companies, and working to promote the adoption of competitive and reliable energy storage systems. More info is available at www.energystorage.org.

May 2, 2017

PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition

By Rory D. Sweeney

WILMINGTON, Del. — Solutions for reducing uplift charges have been more than four years in the making, so PJM members at last week’s Markets and Reliability Committee meeting were largely unconvinced when financial traders argued that voting on the solution’s third phase was being rushed.

Financial stakeholders campaigned unsuccessfully for more than an hour to change the proposal.

Stakeholders then approved a package designed by PJM “to strike a balance between retaining the theoretical benefits of virtual trading while eliminating opportunities for virtual transactions to profit from the market without providing those benefits.” It limits incremental offers and decremental bids to “locations where the settlement of physical energy occurs,” where they compete directly with physical assets or trading hubs, where traders can take forward positions.

Up-to-congestion transactions would be limited to hubs, zones and interfaces — locations that are large aggregates. PJM said the change will address concerns that some UTC trades “do not benefit the market at a level commensurate with the profitability of the transactions.” (See “Members Approve Uplift Proposals,” PJM Markets and Reliability and Members Committees Briefs.)

Financial stakeholders mounted several efforts to influence the vote. They first called for deferring it until FERC has acted on Phase 2, which failed in a sector-weighted vote with 1.04 in favor. The MRC requires a two-thirds sector-weighted vote (3.33 out of 5). Only the Other Supplier sector — which includes financial traders — was in favor of the delay, with the other sectors almost unanimously opposed.

Attorney Ruta Skucas, who represents the Financial Marketers Coalition, called for the deferral, which was seconded by Joe Wadsworth of Vitol. Skucas said the proposal was changed significantly shortly before it went to vote and never received vetting at the Energy Market Uplift Senior Task Force, where the issue had been hashed out for years. The changes eliminated all but 41 nodes for UTCs, she said.

Wadsworth described the proposal as taking “a sledgehammer to the market,” saying the root issue was modeling errors that could be addressed by a more “surgical” approach, such as eliminating trading at locations where the day-ahead and real-time models can’t be aligned.

“When we start removing what traders can do in managing their portfolios on a day-ahead and real-time basis, we’re going to take away the uniqueness traders bring that leads to competition in the markets,” he said.

Bruce Bleiweis of DC Energy also supported a delay, saying he’s been involved with PJM for 21 years, and “this is the first time we’ve come to a rush to judgment.”

PJM MRC virtual transactions — Bleiweis (left) and Wadsworth | © *RTO Insider*

Other stakeholders disagreed.

“My clients would have a different opinion of that,” said attorney Susan Bruce, who represents the PJM Industrial Customer Coalition. “This is a solution that’s a long time coming.”

Direct Energy’s Jeff Whitehead took exception to the accusations of rushed voting.

“I believe this issue has seen its day in court. There are buses that are available to virtual traders on the system today … where there are modeling issues between the day-ahead and real-time market. And because those modeling issues ostensibly can’t be corrected by PJM, arbitrage opportunities exist that simply cannot be converged between the two markets,” he said. “If traders are simply trading with themselves at points that cannot converge, I don’t call that a market.”

“The purpose of the markets is to provide real power to real customers at the lowest possible cost,” said Joe Bowring, PJM’s Independent Market Monitor. “To the extent that virtual transactions are not contributing to that, it’s not appropriate to allow them to continue.”

PJM’s Adam Keech agreed, saying that rules for virtual trading are designed to have the “highest probability of adding the most to the system.”

PJM staff said it’s not clear when the proposal will be filed with FERC because contested filings require a quorum of commissioners to resolve, and the filing seemed likely to attract protest. Noha Sidhom, a financial trader who doesn’t participate in the virtual market, then proposed bifurcating the package into separate filings so that the noncontroversial portions — the limits on INCs and DECs — could be approved by FERC staff and implemented, while the UTC changes — which likely will receive protest — can wait until the commission has a quorum.

Stakeholders debated for some time whether that proposal should be considered prior to voting on the original package, and eventually determined that it should not. The original proposal passed with a 4.07 sector-weighted vote, with all but the Other Suppliers in support.

May 2, 2017

ERCOT TAC OKs Changes to CRR Calendar, Communications Rules

ERCOT’s Technical Advisory Committee last week unanimously approved changes to the ISO’s congestion revenue rights (CRR) activity calendar and its Nodal Operating Guide.

Both votes were conducted by email following an April 24 information session. The TAC canceled its regularly scheduled meeting due to a lack of voting items.

The first change updates ERCOT’s CRR calendar following the Board of Directors’ approval earlier in April of a nodal protocol revision request (NPRR). NPRR808 extended the CRR auction process into the third year forward — with one monthly and one long-term auction each calendar month — and revised the percentages sold in its long-term sequence. It also aligned modifying load zones to the timetable.

ERCOT tac congestion revenue rights crr — Power Traders | *SearchforEnergy.com*

“This should be a huge benefit to our market, and I’m excited to see it implemented,” Morgan Stanley’s Clayton Greer emailed his fellow TAC members after the vote.

ERCOT’s Carrie Bivens, manager of forward markets, said during the information session that the TAC’s approval was required by May 1 in order to be ready for the long-term auction that begins this fall. She said staff has not yet completed testing to ensure the credit monitoring and management system can handle the additional inventory.

“We believe we can, but the risk remains out there,” Bivens said.

The change to the Nodal Operating Guide (NOGRR167) revises it to be consistent with NPRR776, which was also approved by the board in April and aligns the protocol language with currently used verbal communication practices between transmission service providers, qualified scheduling entities and generation resources. The TAC had tabled NOGRR167 during its March meeting.

The committee is scheduled to meet again May 25.

– Tom Kleckner

May 2, 2017

No Consensus for SPP on Zonal Price Shifts

By Tom Kleckner

TULSA, Okla. — The issue of cost shifts within transmission pricing zones may soon surpass transmission upgrade credits as one of the most vexing problems facing SPP stakeholders.

Strategic Planning Committee Chair Mike Wise said last week that his committee has been unable to reach consensus on a more equitable means of determining cost shifts when new members join existing transmission pricing zones despite talks that began in January.

zonal price shifts spp — SPP’s Board of Directors and Members Committee | © *RTO Insider*

Kansas City Power and Light called for revising SPP’s policy after the RTO put the City of Independence, Mo., into the utility’s transmission pricing zone, increasing costs for KCP&L customers. (See Strategic Planning Committee to Continue Work on Tx Cost Shifts.)

The SPC held two special meetings during April — a month in which it doesn’t normally meet — trying to reach consensus on a staff proposal for a “symmetrical” cost/benefit analysis and a phase-in process for regulatory assets that evaluates the time value of money.

“During discussion, it became clear we still didn’t have agreement on staff’s proposal,” Wise told the Board of Directors and Members Committee last Tuesday. “It’s concerning to me that in the stakeholder process, we couldn’t come to a conclusion on this.”

The SPC last met April 20 in Dallas, where it voted on a motion to adopt part of staff’s proposal, rejecting calls to end the discussion entirely. The motion included a reference to “the understanding that the SPC does not endorse the outcome of any staff zonal placement decisions.”

“Basically, [we] just approved a staff process for communication of potential zonal placements,” KCP&L’s Denise Buffington said.

She said in January her company would likely file a complaint with FERC if the SPC doesn’t resolve the issue “to our satisfaction and in a timely manner.” Stakeholders did agree to the first steps in the process, which begin with the applicant transmission owner (ATO) notifying SPP of its intention to join the RTO. Staff would then request data from the ATO, study the zonal placement and cost analysis, and facilitate discussions between the ATO and the transmission zone’s incumbents.

Staff’s straw proposal suggested that the ATO be given an opportunity to negotiate cost shifts with the other transmission owners and network customers in the affected zone, with any resulting agreements filed with FERC.

If no agreement is reached, SPP proposed filing a cost-shift mitigation plan if the shift increased network customers’ baseline costs under Schedule 9 of the Tariff by more than 2.5%.

But staff now say there is little consensus for having a cost-shift threshold. Several stakeholders were adamant that they did not want SPP deciding what costs would be placed upon their customers.

“The problem is not with the mitigation, but the zonal placement criteria,” Buffington said. “The criteria lead to the zonal placement, and it’s the zonal placement that leads to cost shifts. The criteria that [dictate] the placement [are] the problem.”

Staff has suggested using the following criteria in determining whether to place the facilities in a new zone:

Whether the transmission facilities’ annual transmission revenue requirement (ATRR) is less than the minimum zonal ATRR benchmark;
The extent to which the transferring facilities substantively increase the SPP regional footprint; and
The extent to which the transferring facilities’ load received network service or long-term firm point-to-point service within existing zones prior to the transfer.

If the facilities are not placed in a new zone, staff would apply the following criteria in determining the existing zone in which to place the facilities:

The extent to which the facilities are embedded within an existing zone;
The extent to which the facilities are integrated with an existing zone; and
The extent to which the facilities load received network service or long-term firm P2P service within each existing zone prior to the transfer.

Buffington has been leading the work on a revision request (RR172) that she said would establish a bright line between the costs of legacy transmission and new facilities planned by SPP to protect customers from paying for facilities that were not jointly planned. That work has been on hold, pending the SPC discussions.

Wise agreed the SPC would return with another update for the July meeting in Denver.

“This cannot die where it is,” Board Chair Jim Eckelberger said.

May 2, 2017

SPP Board of Directors/Members Committee Briefs

TULSA, Okla. — SPP Strategic Planning Committee Chairman Mike Wise said the committee’s Export Pricing Task Force agrees with staff’s determination that even building additional transmission will not guarantee the RTO can deliver its ample wind power outside its footprint.

In the group’s most recent meeting in March, SPP staff said a market exists for renewable resources, but “rate stress” from building additional transmission and uncertainty that the energy would be deliverable led it to its conclusion. (See “Renewable Exports Unlikely, Task Force Concludes; Readies Final Report,” SPP Briefs.)

“We’re choking on wind,” Wise told the Board of Directors meeting last week. “We run up against the export threshold [about 2,500 MW] on a continued basis.”

Westar Energy’s Kelly Harrison wondered aloud whether transmission is so expensive that it makes wind energy uneconomic to export.

“We’re looking for a business proposition to mitigate that,” Wise responded.

Harrison then asked whether SPP should leave it up to Clean Line Energy to move the wind energy. Clean Line’s Plains & Eastern Clean Line would deliver wind-generated power from the Oklahoma Panhandle through Arkansas to Memphis, though it has met opposition. (See Arkansas Landowners Seek to Stop Plains & Eastern Clean Line Project.)

“That’s why we’re still meeting, until we can get a business proposition that makes sense,” Wise said.

The task force will meet again in June, after several members pushed back against staff’s recommendation to end the group’s work.

Board Asks MOPC to Revisit Mitigated Offers

The board directed the Markets and Operations Policy Committee to revisit a revision request it had passed despite stakeholder concerns it needed more work (MRR214). (See “MWG Closing out MMU’s Recommendations,” SPP Markets and Operations Policy Committee Briefs.)

Board Chair Jim Eckelberger asked Nebraska Public Power District’s Paul Malone, MOPC chair, to expand the discussion to look at the use of rapid-starting units “almost like ping-pong balls” and coal units.

“The way those units are being used is not being reflected in the market,” Eckelberger said.

The change would allow market participants to use a 10% adder for mitigated offers, giving them more margin for error when submitting a mitigated offer curve. The Market Working Group also said the change would improve price formation in SPP’s markets by removing a penalizing feature that may be suppressing offered prices today.

However, MWG Chair Richard Ross of American Electric Power said additional information since the MOPC meeting — where the request received seven “no” votes — had caused him to change his mind. Working with staff, Ross said, he realized the change would modify a mitigated offer as it was cleared, so that when units were dispatched above their minimum bids, it would affect LMPs.

spp markets and operations policy — AEP’s Richard Ross (far right) explains stakeholders’ recommendation to Director Harry Skilton (left) and SPS’ David Hudson. | © *RTO Insider*

“We didn’t appreciate [that] those units on the margin, and sometimes not on the margin, needed cost recovery under the [make-whole payments],” Ross said. “Technically, [MRR214] does what it says, but it’s impacting the LMPs. It wasn’t until we looked into things and said, ‘Wait a minute. You may get everything you’ve set out to get in the request, but you don’t settle the make-whole payments.’”

Ross said that while the change wouldn’t affect the “lion’s share” of the market, he said the MWG didn’t give the revision request “the full scrutiny we probably should have.”

“These RRs are developed by the members and looked at by staff,” said Dogwood Energy’s Rob Janssen, a former MOPC chair. “You expect to catch everything, but sometimes you don’t.”

The board did approve MRR125, which removes a day-ahead must-offer requirement the Market Monitoring Unit deemed unnecessary in its 2014 State of the Market report. The measure received opposition from three members; two more abstained.

“The day-ahead must-offer has limited value in this market,” MMU Director Alan McQueen said. “This market is very robust in the day-ahead. Our analysis shows this [offer] doesn’t really matter. Whether subjected to day-ahead limited must-offers or not, we see the same patterns.”

Wise said stakeholders should work to clarify the market’s use of physical withholding but received little support.

MMU Nears Compliance with FERC Audit

Oversight Chair Joshua W. Martin III told the board and members that SPP is on pace to complete the changes recommended by FERC’s audit of the MMU. The audit, which took 17 months to complete, said the unit “should strengthen its independence and enhance its separation from” the RTO. (See FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence.)

Martin said the project is almost completed and that testing had just begun of the card-access system that will separate MMU staff from RTO staff. MMU staff had worked alongside other RTO staffers, most in open cubicles.

Eric Callisto, an attorney with Michael Best & Friedrich who has served as the MMU regulatory counsel for two years, said much of the work was “already being implemented while the audit was ongoing.” He said two more compliance reports will be filed by the end of July to wrap up FERC’s recommendations.

Callisto pointed to the Oversight Committee’s 2015 position statement on the MMU’s independence, which opened by requiring the unit to “function independently of the RTO to avoid actual or apparent conflicts in its oversight role.”

“One of the key items was the MMU had the resources to make comments to FERC at any point, even if it disagreed with the position that came through the stakeholder process,” Callisto said.

He said the MMU now holds executive sessions with the committee and without SPP staff present, but still holds other executive sessions with SPP executives when relevant to the OC.

“It’s that dialogue with the Oversight Committee that gives the MMU its independence,” Callisto said. “The keystone of the relationship is having the ability to go into that confidential forum, talk about ideas and get confirmation of ideas.

“The last two years, we have seen the MMU file at FERC more often than it has in the past. I believe the MMU is more independent now than it was a year and a half ago,” he said.

Among other changes, Callisto said, is the Oversight Committee’s use of a non-SPP staff secretary when meeting with the MMU, the unit’s logging of non-routine interactions with SPP executives and stakeholders, the MMU’s use of outside counsel and a separate IT budget, and its “awareness that its role is advisory.”

SPP Releases 2016 Annual Report: ‘Forward’

SPP celebrates a milestone year with its 2016 annual report, which it distributed to the Board and Members Committee and posted online last week. The RTO once again used a single word as the report’s title: “Forward.”

“That’s a good word to reflect on all that occurred in 2016,” SPP CEO Nick Brown told directors and members.

The report harkens back to the organization’s 75th anniversary and celebrates the many wind generation records SPP set last year, reaching the Integrated Marketplace’s $1 billion mark for total savings and lowering its planning reserve margin from 13.6% to 12%.

“Given such a banner year, we could all be forgiven for wanting to rest on our laurels or to indulge a bit longer in nostalgia,” Brown and Eckelberger write. “As SPP crosses the threshold into the next quarter century of our existence, then, we look not back but forward. We believe … the facts and figures presented here do more than chronicle a year of our company’s ongoing story: They point ahead to the next chapter.”

That next chapter could include adding the Mountain West Transmission Group’s membership, which should be determined by year-end. (See Mountain West, SPP Tout RTO Membership to Colo. PUC.)

Members Committee Approves 3 New Members

In a special members meeting, the board and members approved the nomination of three new representatives to the Members Committee and bylaw changes related to the Regional Entity.

Brent Baker (Empire District Electric), Kevin Noblet (Kansas City Power & Light) and Aundrea Williams (NextEra Energy Resources) will join the committee. They replace Kelly Walters (Empire) and Scott Heidtbrink (KCP&L), who retired, and Mark Tourangeau, who recently left NextEra.

Stakeholders also approved changing RE General Manager Ron Ciesiel’s title to president, and adding a vice chair position to the RE’s trustees. According to the Corporate Governance Committee’s recommendation supporting the changes, the RE said Ciesiel’s title change was “more appropriate and indicative of the position,” and that the vice chair would ensure a “more consistent transition” should the chair be unable to complete his or her duties.

Board, Members Honor Skilton’s Service

SPP’s directors, the Members Committee, staff and other stakeholders honored long-time Director Harry Skilton with a standing ovation before adjourning the board meeting, his last as vice chair. Skilton, who remains on the board, stepped down after 13 years as the board’s vice chair, a position in which he has been Eckelberger’s steady right-hand man.

“For the last 13 years, Harry has been my sidekick,” Eckelberger said, turning to Skilton. “I’d like to acknowledge my personal appreciation for what you have done.”

Eckelberger and Skilton both joined the SPP board in 2000. The board has added three new members in the last year and is working to bring in the new blood.

Larry Altenbaumer, who joined the board in 2005, has replaced Skilton as vice chair and chair of the Finance Committee.

Board Approves Seams Policy Paper, ITPNT Portfolio

The board approved revisions to the Seams Projects Policy Paper and the 2017 ITP Near-Term assessment’s portfolios. Both had been endorsed by the MOPC two weeks earlier.

The revised seams policy expands the definition of seams projects to include 100-kV and above solutions involving a tie line between SPP and its neighbor or transmission projects that do not cross regional boundaries. It also documents cost allocation policy decisions previously approved by the Regional State Committee and board in 2014.

ITC-Great Plains opposed the motion, saying the revisions did not clarify “the interaction between SPP’s Order 1000 processes and the proposed Seams Transmission Project process.” NextEra Energy Resources and Dogwood Energy abstained.

The board unanimously approved the 2017 ITPNT portfolio, which also passed the MOPC and the Transmission Working Group without opposition. The final portfolio included 15 new reliability projects and one modified project that solve 108 thermal and voltage needs, at a total cost of $60.3 million.

The board also unanimously approved a consent agenda that included a number of proposals previously approved by the MOPC:

Bylaw changes for the nomination and selection of organizational group chairs and vice chairs, and their staggered term lengths. (See “Org Chairs also may See Changes,” SPP Markets and Operations Policy Committee Briefs.)
Staff’s expedited re-evaluation of the need date for Basin Electric’s Roundup-Kummer Ridge 345-kV project, to reflect lower load growth forecasts. (See “MOPC Endorses Re-evaluation of Basin Electric Project,” SPP Markets and Operations Policy Committee Briefs.)
A 50-MVAR reactor at the City Utilities of Springfield, Mo.’s 345-kV Brookline substation. The project was identified last year in a joint study with Associated Electric Cooperative Inc. (AECI).
Regional funding for a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a connecting 161-kV line at an estimated $9.2 million. The project is contingent on reaching an agreement for compensating AECI, which would not see reliability benefits from the project even though it sits within its service area.

The consent agenda also included 15 revision requests.

CPWG-RR218: Adopts a $50 million unsecured credit allowance, a raise from $25 million, to reduce the costs of capital for utilities. SPP is the last RTO to adopt a $50 million limit.
MWG-RR200: Removes bilateral settlement schedules at hubs and generation settlement locations from the over-collected losses (OCL) distribution calculation. Only schedules at a withdrawal point would be included in the OCL calculation.
MWG-RR203: Adds a “last-chance” second set of auction revenue rights nominations in the monthly ARR process, where any source-sink path can be nominated.
MWG-RR205: Allows the implementation of jointly owned units (JOU) registered under the combined-resource option to include the minimum regulation-capacity operating limit in its offers, and adds resource offer parameters that can be changed daily for a JOU’s minimum physical capacity and physical-regulation capacity operating limits.
MWG-RR216: Reinstates Tariff language omitted from RR173 related to eligibility of multiconfiguration resources for regulation-up or regulation-down service.
MWG-RR217: Removes Tariff language related to violation relaxation limits to make the section consistent with a compliance filing in response to FERC’s Order 825 on shortage pricing.
MWG-RR219: Ensures language in SPP’s Tariff meets FERC requirements for enhanced combined cycle units.
ORWG-RR213: Creates a new appendix to the operating criteria that defines how the SPP reliability coordinator will operate voltage stability limited system constraints, as recommended by the Wind Integration Study.
RTWG-RR202: Responds to FERC guidance on SPP’s disparate treatment of point-to-point and network integration transmission service (NITS) during redispatch. NITS would be eligible for ARRs during limited times of the year and only for the service not subject to redispatch, but would not be eligible for long-term congestion rights. (See SPP Hopes Congestion Rights Rule Change Wins FERC OK.)
RTWG-RR208: Implements the Transmission Planning Improvement Task Force’s white paper for new regional planning processes by replacing current planning schedules with an annual transmission expansion plan; creating a standardized scope; establishing a common planning model for use across the various planning processes; and creating a staff/stakeholder accountability program. (See “SPC, MOPC Approve Improvements to SPP’s Tx Planning Process,” SPP Strategic Planning Committee Briefs.)
RTWG-RR211: Establishes a $3 million minimum cost threshold for competitive projects.
TRR223: Revises the Tariff to extend the timeline for conducting regional cost allocation reviews from three years to six.
TWG-RR215 and TWG-RR186: Eliminates redundant requirements.
TWG-RR224: Aligns the existing criteria with NERC’s new definition of “special protection schemes” as “remedial action schemes.” Also cleans up planning criteria language coinciding with changes made to the operating-horizon system operating limits methodology.

– Tom Kleckner

May 1, 2017

State Climate Policies and Markets: Irreconcilable Differences?

By Michael Kuser and Rich Heidorn Jr.

Executives from PJM, NYISO and ISO-NE will gather with stakeholders, state officials and others at FERC this week to seek ways to incorporate state policies on greenhouse gases into wholesale markets.

FERC scheduled the two-day technical conference out of concern that the RTO/ISO energy and capacity markets could lose relevance — or have their pricing signals undermined — because of state plans to procure out-of-market renewable power and prop up nuclear generators (AD17-11).

The conference will build on the grid operators’ initiatives, including white papers and the New England Power Pool’s Integrating Markets and Public Policy (IMAPP). It also comes as FERC has pending before it challenges to zero-emission credits for nuclear generators in NYISO and PJM.

The first day of the conference devotes two panel sessions to each of the three grid operators, with one session for state officials to offer their perspectives and one for stakeholders and RTO/ISO officials. The second day will include one panel dominated by state regulators and generating company executives; a second featuring economists and consultants; and a final one giving RTO/ISO officials an opportunity to respond to what they’ve heard.

Below, based on interviews and a review of filed testimony by the witnesses, is a preview of the issues to be discussed.

Incorporating Carbon Costs

Changing the energy resource mix is complex and often controversial, said the Brattle Group’s Judy Chang, an energy economist with a background in electrical engineering, whose clients include NYISO. “Anytime you change the rules, someone is not going to be happy, because rule changes affect revenue,” she said in an interview. An energy economist with a background in electrical engineering, Chang advises clients, including NYISO, on transmission, resource and strategic planning.

ISO-NE Chief Economist Matthew White said New England states are more focused than most others on subsidizing new renewables to meet environmental goals.

“To date, stakeholders and ISO-NE have only identified one solution that would help the states ‘achieve’ their goals while simultaneously preserving the benefits of competitive markets — a carbon cap-and-trade system,” White said in his prepared comments.

Carbon pricing could efficiently price the environmental attributes sought by the states, providing a market framework to select resources based on the least cost. White said that despite the potential advantages of carbon pricing, “there are significant jurisdictional and political issues regarding the implementation of such a carbon pricing mechanism.”

NYISO CEO Brad Jones focused on the ISO’s search for a method “to incorporate the social cost of carbon into generation offers and reflect that cost in energy clearing prices.”

“A generating unit that may appear uneconomic based on its electricity market revenues alone may nevertheless be viable if it could capture the economic value of its environmental attributes,” Jones said. “The problem we face is that current wholesale market designs function well to send economically efficient market signals needed to maintain reliability, but they do not value externalities such as environmental attributes [that] are at the heart of certain state policies.”

Energy and Capacity Markets Implicated

RTO Insider asked Chang whether FERC and the RTOs have the same agenda for the technical conference. “That’s a really good question,” she responded. “The commission wants to ensure that the market functions properly. If FERC is smart, and they are, they’ll recognize that these things cannot stay static. There’s a lot of change going on these days. Policymakers, to succeed, need the market to shift with policy, to improve and adapt.”

Susanne DesRoches, deputy director of infrastructure policy for New York City, said that energy market changes provide only part of the solution. “Changes also are needed to the capacity markets to ensure that developers of renewable resources are able to recover their non-operating costs. At present, the capital costs of many renewable technologies are greater than the cost of a gas-fired plant, but the installed capacity demand curves are not designed to take into account such costs.”

state climate policies greenhouse gases — Indian Point Nuclear Plant

Improvements need to take place because the wholesale electricity markets are only about a decade old, at a time when coal-fired generation dominated in many regions and renewables had little market share. “The designers had no conception of what the world would look like 15 or 20 years later,” Chang said. (See EBA Panel: States Acting on CO2 Because Markets Can’t.)

NEPOOL Chairman Thomas W. Kaslow referred the commission in his prepared comments to a new paper issued by ISO-NE, “Competitive Auctions with Subsidized Policy Resources,” which proposes coordinating the entry of subsidized new resources with the exit of unsubsidized existing capacity resources. Under the proposal, ISO-NE would use a two-stage, two-settlement process in its Forward Capacity Auctions to provide “financial incentives for existing, high-cost capacity resources to transfer their capacity obligations to subsidized new resources and to permanently exit the capacity market.”

PJM Looks to Value Resiliency

Reducing carbon emissions is the major driver for New York and the New England states, all members of the Regional Greenhouse Gas Initiative.

That’s not the case in PJM. Although most of the RTO’s 13 states have renewable portfolio standards, only two — Maryland and Delaware — are in RGGI.

In Ohio, state initiatives have been focused not on reducing emissions but on preserving coal-fired generation.

In March, PJM released a study, “PJM’s Evolving Resource Mix and System Reliability,” in response to stakeholder concerns that the system is losing too many traditional baseload resources as coal plants retire and nuclear assets struggle to remain profitable. The study concluded the RTO can maintain reliability with a generation fleet almost entirely composed of natural gas units, but that a capacity mix of more than 20% of solar would unacceptably increase the risk of loss-of-load events. (See PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)

Seeking 90% from the Markets

Chang said the states aren’t seeking a confrontation with the RTOs.

“It’s not one or the other, not who has the upper hand,” she said. “It would not be in the state’s interest to always work outside a competitive, centralized marketplace. And it’s not in the grid’s interest to maintain the status quo. We want to get to the point where state policymakers can rely on the market to accomplish 90% of what they want. Coordination is key; otherwise, ratepayers could end up paying for something twice. You let some resources retire just because they’re not efficient, and at the same time you set price incentives to encourage development of clean energy. They have to go hand in hand.”

Jeffrey Bentz, director of analysis for the New England States Committee on Electricity, in his prepared remarks referred the commission to a recent NESCOE study on IMAPP. Not only does NESCOE not support an additional carbon-pricing mechanism to be run by ISO-NE and regulated by FERC, but the member states are concerned about the risks of a FERC-jurisdictional tariff reflecting carbon pricing.

Specifically, New England states are concerned that such a tariff poses “risks to states’ ability to make their own determination regarding the implementation of their carbon-reduction laws,” Bentz said. “For example, as illustrated in recent years, a few market participants with an appetite and budget to litigate matters could seek to disrupt a design over which ISO-NE, NESCOE and NEPOOL find agreement. FERC could also seek to direct changes on its own initiative.”

Absence of Federal Leadership

Will people be wasting their time changing capacity or energy markets to accommodate state clean energy policies after President Trump earlier this month ordered EPA to begin unwinding its Clean Energy Plan? On Friday, the D.C. Circuit Court of Appeals granted the Trump administration’s requests to hold in abeyance lawsuits challenging the CPP and EPA’s Mercury and Air Toxics Standards. (See DC Circuit Puts Hold on CPP, MATS Challenges.)

Chang said no. “New York and the New England states are going to push through their policies no matter what. Holding back on a FERC-approved action will not stop states from adopting cost-effective measures to meet their policy objectives. One could argue that the states are going to push harder in the absence of federal leadership.” (See RTOs Unfazed by Trump Climate Order.)

May 1, 2017

Utility Proposal Would Increase Legacy Costs for California CCAs

By Robert Mullin

Californians who receive their electricity service from one of the state’s growing number of community choice aggregators (CCAs) could face higher costs under a plan being proposed by the state’s three investor-owned utilities.

The proposal — filed jointly by Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — calls for the California Public Utilities Commission to adopt a new approach to apportioning the utilities’ costs for energy contracts among the departing and remaining customers.

community choice aggregator california utilities — Wind farm near Palm Springs, Cal. | © *RTO Insider*

Utility customers departing for CCAs and direct access arrangements “are not paying their full share of costs associated with the long-term contracts [for renewables], forcing other customers to pay more,” PG&E said in a statement. California’s direct access program allows nonresidential retail customers to purchase power from independent electricity suppliers.

The new plan would replace the PUC’s current formula for calculating those costs — the power charge indifference adjustment (PCIA) — with a new system the utilities call the portfolio allocation methodology (PAM).

The PCIA acts as an exit fee, requiring customers departing for CCA to pay for their estimated share of the contracts IOUs signed to meet California’s energy policy mandates, such as the renewable portfolio standard and energy storage requirements. The fees are assessed until the termination of the contracts. Departing customers also pay a competition transition charge (CTC) that represents their share of a utility’s costs for older fossil fuel generation.

‘Financially Indifferent’

The fees are designed to keep the IOUs’ remaining bundled service customers “financially indifferent” to the departure of CCA customers, the PUC has said.

The PCIA’s calculation relies on an estimate of “above-market” costs incurred by the IOUs for procuring or building policy-driven resources.

But the utilities see a problem with that approach. The PUC bases its “above-market” cost assessment on administratively defined benchmarks developed during a time when prices for renewable energy credits and resource adequacy were higher than they are today. That makes the IOUs’ portfolios appear cheaper than they actually are, the utilities contend.

“This directly translates into departing load customers paying PCIA and CTC rates that do not fully pay for their share of the actual above-market costs of the portfolios, which is contrary to law,” the utilities said.

Under the utilities’ PAM proposal, departing customers would be charged based on the “actual” costs for the contracts procured on their behalf. On the flip side, those customers would also be allocated the “actual value” of contract portfolios, including RECs, capacity credits and revenues generated from providing ancillary services.

Under the new methodology, rates for the contracts would be regularly trued-up in the same manner as those charged to the IOUs’ remaining bundled customers, although the utilities note that most of the agreements in question are fixed-cost.

The IOUs are proposing to implement PAM on a “vintaged-portfolio” basis that depends on the customer’s departure date, “ensuring that all customers are only assigned the costs and benefits of resources actually procured or built on their behalf.”

“We can achieve the state’s clean energy goals while also supporting customer choice and treating all customers fairly and equally,” said Steve Malnight, PG&E’s senior vice president of strategy and policy.

Consumer Protections Needed

Woody Hastings, renewable energy implementation manager for the Santa Rosa-based Center for Climate Protection, told RTO Insider his support for the proposal would in part depend on whether it contains adequate consumer protections. “We have long held that the PCIA is broken,” he said.

Hastings said that while his organization agrees with the concept of bundled ratepayer indifference, his assessment of the plan would come down to exactly what expenses the utilities would roll into the new methodology.

“We need some kind of assurance that avoidable costs are being avoided,” Hastings said. “A third-party audit should happen [in order] to show that the numbers being presented are valid.”

In their filing, the utilities said they will seek approval to develop a formal process to provide load-serving entities with access to portfolio and contract data as part of the PAM.

“PAM is transparent, objective and fully consistent with California law … and should be expeditiously adopted by the commission,” the utilities wrote.