Page 1224 – RTO Insider

November 13, 2017

Wildfires Color California PUC Utility Decisions

By Jason Fordney

SAN FRANCISCO — Utilities are dealing with several wildfire-related proceedings at the California Public Utilities Commission, which is exploring taking a larger role in responding to natural disasters and emergencies.

CAISO PUCO Colorado Public Utilities Commission withholding — The CPUC passed a series of electric-related emergency measures for utility customers | © *RTO Insider*

The commission Nov. 9 unanimously approved a series of emergency protections for electric ratepayers affected by the wildfires, but it delayed until Nov. 30 a decision on whether San Diego Gas & Electric (SDG&E) will be a permitted to recover costs from fires occurring a decade ago.

Up to 30 separate fires raged in Northern California in October, prompting PUC President Michael Picker to discuss an increased role for the commission in responding to such events, such as sending out recovery teams to help residents.

“There seems to be more effective things we can do as people move into recovery,” Picker said. “I am curious to see whether we can institutionalize this in a more formal way.”

The commission’s decision requires utilities to waive deposits for residents re-establishing residential electric and gas service and stop billing homes that cannot receive service. It also disallowed disconnections for nonpayment and extended payment options, among other protections.

“It’s not as if this is the only catastrophe that we are going to have to respond to,” Picker added. “They are clearly increasing more in frequency and severity.” The PUC also heard about widespread loss of telephone service during the emergency because of power outages and structural damage.

“Acting quickly to protect consumers that have been affected by these tragic fires is very important,” said Commissioner Liane Randolph, highlighting the suspension of customer referrals to collection agencies.

Commissioner Martha Guzman-Aceves noted that utilities “are already acting on many of these under their own discretion,” and “it is one of those positive incidences where everyone is working towards the same end.”

Commissioner Carla Peterman suggested exploring a set of standard protections and memorandum accounts to track costs. She also thought protections for small businesses and institutions should be explored.

California Public Utilities Commission CPUC California Wildfires — Rechtschaffen | © *RTO Insider*

“These are quick responses — we may need to do much more,” Commissioner Clifford Rechtschaffen added.

At the meeting, the PUC also temporarily waived the regulatory requirement that Pacific Gas and Electric charge affected customers for electric service related to wildfires. The utility asked for permission to waive the cost of estimated installation and remove costs to provide temporary power. It will instead include the costs in a future application under its Catastrophic Event Memorandum Account.

PG&E Fights Wildfire Lawsuits

PG&E is already fending off legal action related to the most recent fires. The utility on Nov. 9 asked the Judicial Council of California for a stay of 15 lawsuits by residents regarding fires that occurred within 12 counties. The company said that preliminary investigation shows that one blaze, the Tubbs fire, could have been caused by utility equipment installed by a third party not named in the suits.

“Although plaintiffs have rushed to file complaints while the fires are still burning, the reality is that no one knows what caused any of the fires,” PG&E said. “For the fires that cause can be determined, the cause could be a variety of factors.”

It said the fires had many different locations, causes and damages.

“Plaintiffs’ effort to lump the fires together, both in their complaints and with respect to coordination, is an attempt to diminish their burden of proof with respect to causation,” PG&E said.

PG&E Files to Close Diablo Canyon

The commission is due to vote next month on whether to allow PG&E to retire the Diablo Canyon nuclear power plant in San Luis Obispo by 2025.

The PUC’s interim chief administrative law judge, Anne Simon, issued a proposed decision on Nov. 8 allowing the utility to retire the 2,240-MW plant and collect about $1.8 billion in costs from ratepayers. About $1.3 billion of that amount is to implement energy efficiency measures to replace the plant’s capacity.

PG&E first filed with the commission in August 2016 to retire the plant, submitting a proposed settlement between the utility, San Luis Obispo County, several local cities and environmental groups regarding the closing of the facility. (See PG&E Files Diablo Canyon Shutdown Request.)

The company proposes to close both units at the plant upon the expiration of their licenses: Nov. 2, 2024, for Unit 1 and Aug. 26, 2025, for Unit 2. The utility said there is less need for the plant because of new energy efficiency, distributed generation, renewable generation and customers moving to community choice aggregators and direct access.

“In fact, PG&E believes that the continued operation of Diablo Canyon beyond 2025 would exacerbate overgeneration, requiring curtailment of renewable generation,” Simon said in the decision. “PG&E’s analysis indicates that there is no need to replace Diablo Canyon in order to maintain system reliability.”

The proposed decision found that electricity procurement to replace the capacity should be obtained through the state’s integrated resource planning proceeding.

PG&E has requested approval to procure three tranches of greenhouse gas-free resources to partially replace the plant’s output; retention, retraining and severance for Diablo Canyon employees; and recovery of other costs.

November 13, 2017

MISO’s Plans for Wintertime Offer Caps Stalled by FERC

By Amanda Durish Cook

CARMEL, Ind. — FERC on Thursday rejected MISO’s Order 831 compliance filing just hours after the RTO told stakeholders it would head into winter with a $1,000/MWh soft cap and a $2,000/MWh hard cap on energy.

MISO FERC IRPs Conservation Law Foundation — Hansen | © *RTO Insider*

MISO’s changes were to go into effect Dec. 1, according to Markets System Analyst Chuck Hansen, who spoke at a Nov. 9 Market Subcommittee meeting before the FERC order was released later that day.

The commission ordered the RTO to make a new compliance filing within 60 days (ER17-1570).

Order 831, issued a year ago, required RTOs to cap energy offers at the higher of $1,000/MWh or a price based on Market Monitor-verified costs (soft cap), and to cap those cost-based offers at $2,000 (hard cap). While cost-based offers above the hard cap — or those above the soft cap but unable to be verified before the market clears — would be excluded from setting LMPs, generators making those offers would still be eligible for make-whole payments once their costs were verified (RM16-5). (See New FERC Rule Will Double RTO Offer Caps.)

However, FERC determined that MISO completely prohibited resources from submitting cost-based offers above the hard cap.

“Although Order No. 831 requires that such offers are prohibited from being used to set LMP, resources with verified costs exceeding $2,000/MWh must be eligible to recover costs above $2,000/MWh through uplift,” FERC said. “Although MISO proposes to increase the maximum incremental energy offer from $1,000/MWh to $2,000/MWh, there does not appear to be any mechanism, outside of proxy offers, that would allow a resource to make a cost-based incremental energy offer above $2,000/MWh. We therefore find that MISO has not met this requirement of Order No. 831.”

But based on Hansen’s statements at the subcommittee meeting, it appears the RTO did not foresee a problem with its filing.

“It’s possible that you can have costs even above $2,000/MWh and have those costs verified and be eligible for make-whole payments, but payments over $2,000/MWh will not be available to set price,” Hansen said.

Such offers will be verified by the Independent Market Monitor after market close, Hansen said. The Monitor will also continue to review generator energy offers above $1,000, he said, before they can be used to calculate LMPs. Hansen also said the processing of offers under $1,000 will remain unchanged in MISO’s market system.

MISO offer cap — MISO’s proposed offer cap process | *MISO*

Those statements are all in compliance with Order 831. In its ruling, however, the commission said MISO didn’t satisfactorily explain what factors would be considered when verifying offers, and whether those factors would be new to the RTO’s existing mitigation measures. MISO also failed to lay out a process for dispensing uplift payments when an offer in excess of $1,000/MWh is verified after market close or detail how a resource’s reference level may factor into that verification, although the RTO’s revisions suggested a relationship between reference level and uplift payment, FERC said.

Order 831 was a response to the 2014 polar vortex, in which a severe cold snap sent natural gas prices soaring. Many generators complained they were unable to recover their fuel costs because of grid operators’ hard $1,000/MWh offer caps.

Resource-Neutrality, External Transactions

The order also stipulated that offers be resource-neutral, and that external and virtual transactions also be capped at $2,000/MWh.

MISO’s market currently automatically blocks all offers above $1,000/MWh. The RTO’s new proposal was to block energy offers above $9,999/MWh from generators, Type I demand response resources and external asynchronous resources, as well as virtual offers and those from Type II DR r and price-sensitive demand resources above $2,000/MWh.

However, FERC found that MISO failed to show how its verification process applies to DR and that, with the exception of external asynchronous resources, the RTO was “silent with regard to import and export transactions or the requirement that external transactions be able to make offers up to $2,000/MWh without verification.”

For the last two winters, FERC has granted MISO a waiver of its $1,000/MWh offer cap for verifiable offers, although MISO has not needed to use it. (See MISO Granted Winter Waiver on Offer Cap.)

Other RTOs

Where MISO failed, other RTOs succeeded — mostly.

FERC found that NYISO (ER17-1561), PJM (ER17-1567) and SPP (ER15-1768) complied with its directives on bifurcating their offer caps and showed that their existing verification processes were sufficient and resource-neutral.

However, NYISO and PJM failed to specify that any price adders included in cost-based offers be limited to $100/MWh, another stipulation of Order 831. Such adders also can’t be recovered through uplift payments.

In PJM’s case, the RTO acknowledged this and laid out further revisions in an answer to a protest filed by its Independent Market Monitor.

In NYISO’s, FERC found the ISO also incorrectly included opportunity costs as an adder. As it explained in its clarification order, “verifiable opportunity costs should not be subject to the $100/MWh limit on adders above cost because opportunity costs are legitimate short-run marginal costs and not adders above cost.”

“NYISO’s proposal prevents resources from recovering opportunity costs through uplift when NYISO is unable to verify these costs before the close of the relevant market,” the commission said. “Accordingly, we direct NYISO to ensure that opportunity costs for bids exceeding $1,000/MWh are eligible for uplift, even if they are not verified before the close of the relevant market, if such costs are submitted as part of the resources’ bid, those costs were timely submitted and supported with documentation, and that those costs were verified by NYISO after-the-fact.”

PJM also failed to address external and virtual transactions — both of which have $2,700/MWh hard caps — in its filing, the commission found.

FERC directed PJM and NYISO to submit further compliance filings by Dec. 9. It accepted SPP’s revisions in full, with an effective date of April 1, 2019 — the day the RTO estimates it will launch its new settlement system software.

The commission itself, however, did not rule on ISO-NE’s compliance filing. Instead, its Office of Energy Market Regulation accepted the RTO’s changes under delegated authority (ER17-1565). This was because, unlike the other grid operators’ filings, no intervenors filed any comments or protests to ISO-NE’s.

The RTO was also granted an Oct. 1, 2019, effective date by staff. Like SPP, ISO-NE said this was needed to give it time to implement software changes necessary to comply. Unlike SPP, however, ISO-NE needs to start from scratch.

“ISO-NE anticipates that it will take approximately 18-24 months to design, develop, implement and fully test the necessary software and process changes to implement the Order 831 revisions,” it told FERC in its May compliance filing. “The requested effective date of Oct. 1, 2019, is aggressive and assumes that each phase of the implementation goes smoothly and is not delayed due to demands from competing priorities.”

CAISO in May asked FERC for an extension until May 1, 2018, to submit a proposal for implementing Order 831, saying it doesn’t currently have market mitigation measures in place to verify cost-based offers prior to market clearing. The commission has not yet ruled on that request.

MISO VoLL also Rejected

MISO’s plan to similarly raise the limit on its operating reserve demand curve was likewise rejected by FERC because of its reliance on the RTO’s offer cap revisions (ER17-1571).

“We agree with MISO that changes to MISO’s operating reserve demand curves may be necessary to accommodate the requirements of Order No. 831,” FERC wrote in its brief order. “However, because MISO’s proposal relies upon definitions and provisions that are not part of MISO’s effective Tariff, we reject this filing without prejudice to MISO submitting another filing as may be necessary to accommodate Tariff revisions made in its future compliance filing for Order No. 831.”

MISO was planning to maintain its $3,500/MWh cap on the value of lost load (VoLL) for the time being, with staff acknowledging that it still needs to conduct analyses to update it. This year, Market Monitor David Patton recommended that the cap be increased to almost $12,000/MWh to create a more sloped contingency reserve demand curve. (See MISO Board Hears State of the Market Recommendations.) MISO’s proposed curve is much flatter, hovering at $2,100/MWh unless the RTO clears less than 8% or more than 96% of its requirement level.

“In principle, we agree with potentially looking at the value of lost load, but we wanted to take some time, not rush into anything and get stakeholder input because this does impact prices,” MISO’s Hansen said.

Jeff Bladen, MISO executive director of market design, said the existing VoLL is a “historical artifact at this point.”

Michael Brooks, Michael Kuser and Robert Mullin contributed to this report.

November 13, 2017

FERC Rejects SPP Change on Network Resource Upgrades

By Rich Heidorn Jr.

FERC last week issued rulings in three SPP transmission cases, mostly siding with the RTO but rejecting its proposal to change the conditions for classifying service upgrade costs for designated resources.

SPP’s Tariff allows service upgrades associated with new or changed designated resources to be classified as base plan upgrades, subject to regional cost allocation, if the load-serving entity’s resulting capacity does not exceed 125% of its projected system peak responsibility.

SPP said its proposed wording changes clarify and update its rules and have “no practical or detrimental effect” on its study process.

The commission disagreed, saying the proposed Tariff language was inconsistent with SPP’s representation of how it calculates customers’ “highest hourly load” (ER17-1795).

It also took issue with the RTO’s plan to calculate “highest hourly load” on an aggregate basis for network customers with multiple service agreements that include the same designated resources. The commission said SPP had not proven that its proposal was not unduly discriminatory to customers with multiple agreements that do not include the same designated resources.

Z2 Waiver Upheld

The commission denied rehearing requests on its July 2016 order waiving the one-year limit for adjusting payment obligations and revenue distributions for transmission projects under Tariff Attachment Z2. (See SPP MOPC Recommends 5-Year Timetable for Resolving $849M Z2 Bill.)

SPP FERC KEPCo upgrade costs — Member Coops | *Kansas Electric Power Cooperative*

FERC said the challengers — American Electric Power, Xcel Energy, Kansas Electric Power Cooperative (KEPCo) and Southern Co. — incorrectly applied the commission’s criteria for granting waivers (ER16-1341-001).

“Specifically, the arguments made on rehearing conflate the waiver’s scope (i.e., the provisions to be waived) with its potential consequences,” FERC said. “The parties on rehearing also ignore the waiver’s purpose because they assert that SPP must demonstrate that it will implement the crediting mechanism correctly before the waiver can be granted. The purpose of the waiver is to remove barriers to implementation. The process of implementation itself is beyond the scope of this proceeding.”

Split Decision in KEPCo Dispute

The commission partially granted KEPCo’s November 2016 complaint in a separate transmission dispute with SPP (EL17-21). The commission also denied some claims and set settlement judge procedures on others.

FERC rejected KEPCo’s allegation that SPP inappropriately directly assigned the cooperative $6.2 million in costs for network upgrades in violation of four network integration transmission service (NITS) agreements and the filed rate doctrine.

“Even though the NITS agreements did not list any network upgrades for which KEPCo would be directly assigned cost responsibility, KEPCo knew that … there may be possible Attachment Z2 revenue credit payment obligations and also that SPP was in the process of developing the [Crediting Process Task Force] white paper, with a methodology that would identify the network upgrades with more certainty,” the commission said.

FERC also rejected KEPCo’s claim that SPP’s allocation of upgrade costs was made too late under its Tariff. “To the extent SPP’s original analysis did not capture certain creditable upgrades, we also find it is reasonable to permit SPP to make corrections to the list of network upgrades so that upgrade sponsors are compensated for transmission service that their sponsored upgrades have facilitated, and which KEPCo has received,” it said.

SPP also prevailed on KEPCo’s claim that it violated the “but for” test in directly assigning costs for certain network upgrades.

The commission agreed with KEPCo that SPP had “improperly applied” its cost allocation rules in one instance but said the violation had no impact on the costs allocated to the cooperative.

Finally, FERC set hearing and settlement judge procedures to resolve whether KEPCo’s transmission service requests had a material impact on the Rice-Circle transmission project — a new Rice substation and an upgrade of the 28-mile line between it and the Circle substation to 230 kV from 115 kV.

“The specific issue is whether, according to a transfer distribution analysis, KEPCo’s transmission service requests cause at least a 3% impact on the Rice-Circle facility, and therefore, are considered to impact the facility and should be assigned costs for that facility,” the commission said.

— Tom Kleckner contributed to this article.

November 13, 2017

MISO Seeks to Gauge Risk of Peak Season Planned Outages

By Amanda Durish Cook

CARMEL, Ind. — Facing an increased number of outages from an aging fleet of baseload generators across the footprint, MISO officials are examining how they can capture the risk of planned and maintenance outages occurring during peak load.

maintenance outages miso peak load — Westphal | © *RTO Insider*

Ryan Westphal, MISO resource adequacy coordinator, said an investigation by the RTO’s Loss of Load Expectation Working Group suggests a need to account for intentional outages, but stakeholders have not yet reached consensus on how to proceed.

“Every year [since 2012], we saw some number of both planned and maintenance outages that happen on peak,” Westphal said during a Nov. 8 Resource Adequacy Subcommittee meeting.

Westphal said MISO has looked into incorporating a combined average volume of planned and maintenance outages into its loss-of-load-expectation (LOLE) calculation, which would bump up the RTO’s predicted 17.1% planning reserve margin by about 0.4% in the 2018/19 planning year. The increase would lead to an additional 600 MW being cleared in this year’s capacity auction, MISO estimated.

MISO currently does not model any planned and maintenance outages at peak load, assuming such outages are optimized and not occurring during peak demand, but the RTO may want to revise its LOLE study to include the probability that some outages will occur during the peak, Westphal said.

“It leads us to think that all the risk isn’t being captured in our planning reserve margin today,” he said. Over the last several years, MISO has carried a sufficient reserve margin to cover outages that occur on peak, he added.

During July 2016, MISO experienced about 3.4 GW of planned outages and 1.8 GW of maintenance outages. The following month saw planned and forced outages of 2.4 GW and 4.2 GW, respectively. While those outages combined were nowhere near the volume of forced outages in the summer (12 GW in July, 10 GW in August), they helped nudge total outages above 16 GW during both months, a benchmark that was surpassed only once before in August 2015.

Duke Energy’s Brian Garnett asked how a maintenance outage occurs that’s not already planned or forced.

MISO defines maintenance outages as less severe mechanical issues that don’t result in an immediate outage trip but must be scheduled for repairs, Westphal said.

Indianapolis Power and Light’s Ted Leffler asked if the new calculation will be applied universally across the footprint or target individual units.

“I would caution that not every generation unit that has planned outages has load,” Leffler said.

Westphal said MISO would discuss the proposal again next month, and asked stakeholders to send written feedback before the Thanksgiving holiday.

November 13, 2017

MISO Stands by Load Forecast Confirmation Method

CARMEL, Ind. — MISO is defending its methods for validating utility load forecasts after Dynegy last month charged that Ameren Illinois miscalculated its summer peak load forecast.

Michael Robinson, MISO principal adviser of market design, said the RTO’s Tariff obligates it to draw a random sample of load-serving entity demand forecasts to “assess credibility” of the forecasts. For the LSEs selected for the sample, MISO performs an ex post review of their previous year’s forecast and works with them to reconcile differences between their forecasts and those produced by Purdue University’s State Utility Forecasting Group.

MISO FERC Dynegy summer peak Ameren — Left to right: Mike Robinson with RASC Chair Chris Plante and RASC liaison Shawn McFarlane | © *RTO Insider*

“Ameren was a draw in the random sample last year,” Robinson confirmed at a Nov. 8 Resource Adequacy Subcommittee meeting. “We did have to come back and ask them for additional documentation. Some of their documents were a bit sketchy, I guess, but they gave us everything we needed.”

Last month, Dynegy called on MISO to develop a new process for verifying load forecasts produced by LSEs, claiming Ameren’s forecasts led to under-procurement in the capacity auction for Zone 4. (See Dynegy: MISO LSE Load Forecasts Require Tune-up.)

MISO said it found no evidence of systemic bias in forecasts. Robinson said Zone 4 was slightly hotter than normal at coincident peak this summer and all local resource zones were within two standard errors of their forecast values.

“The way we design this is the LSEs are the experts in the sense that they know when customers are building. They certainly have more information than we do,” Robinson said. “We don’t forecast ourselves on the zonal level for the coincident peak. We don’t have that kind of information.”

— Amanda Durish Cook

November 13, 2017

Chatterjee to Push Interim ‘Lifeboat’ for Coal, Nukes

By Rich Heidorn Jr.

FERC Chairman Neil Chatterjee said last week he will seek an interim “lifeboat” to ensure the survival of struggling coal and nuclear plants while the commission ponders long-term rule changes.

FERC ISO-NE Cheryl LaFleur Neil Chatterjee — Chatterjee | © *RTO Insider*

He laid out his plans in remarks at an industry conference and in an interview Thursday on Bloomberg television.

Chatterjee has said the commission will take action by Dec. 11 on Energy Secretary Rick Perry’s call for “full recovery” of coal and nuclear plants’ costs in RTOs with energy and capacity markets, including PJM, ISO-NE and NYISO. More than 700 comments were filed in response to the Department of Energy’s Notice of Proposed Rulemaking (RM18-1). (See NOPR Backers, Foes Seek Last Word at Comment Deadline.)

In a meeting with reporters last month, Chatterjee said FERC’s options include initiating its own rulemaking, convening a technical conference or issuing a final rule based on DOE’s NOPR.

Now, facing legal and political obstacles to winning approval of a final rule, Chatterjee said he is seeking a short-term plan to rescue as many plants as possible while the commission does additional fact-finding.

“What I don’t want to have is plants shut down while we’re doing this longer-term analysis, so we need an interim step to keep them afloat,” Chatterjee told the S&P Global Platts Energy Podium in D.C. “I don’t know that we can get everybody in the lifeboat,” he added.

“My approach is going to be one of no regrets,” he said in the Bloomberg interview. “The worst-case scenario would be we do the long-term analysis, we figure out we actually did need these plants, but they’re gone. They’re offline and we can’t get them back.”

He said his plan will not alter RTO dispatch practices or distort markets.

Chatterjee also disclosed he had met with FirstEnergy CEO Chuck Jones “to really kick the tires on what they proposed [in their comments on the DOE NOPR] and challenge them on some of what they had put forward.” FERC’s ex parte rules, which bar commissioners from private discussions with parties in “case-specific, contested proceedings,” do not apply to rulemakings, according to a 2010 presentation by FERC Associate General Counsel Lawrence R. Greenfield (18 CFR 385.2201(a), (b), (c)(1)(ii)).

FirstEnergy proposed that the commission require RTOs and ISOs adopt a pro forma Resiliency Support Resource (RSR) tariff agreeing to make monthly payments to “fuel-secure, resilient generators.” The payments would be “equal to its full costs of operation and service” and a “and a fair return on equity,” minus its revenues for capacity, energy and ancillary services.

Chatterjee, a native of coal state Kentucky and a former aide to Senate Majority Leader Mitch McConnell (R-Ky.), has made no secret of his desire to aid coal generators. Commissioners Robert Powelson, a Republican, and Cheryl LaFleur, a Democrat, have reacted more warily to the Perry proposal, expressing concern it could damage wholesale markets.

Republican Kevin McIntyre and Democrat Richard Glick, who were confirmed to FERC by the Senate on Nov. 2, are awaiting their swearing-in and have not commented publicly on the proposal. Chatterjee told Bloomberg that he had not discussed the NOPR or his interim proposal with McIntyre, who will replace him as chairman.

“Kevin is somebody with a lot of expertise. He’s a smart, thoughtful guy. … And I hope that he will ultimately be persuaded to follow the course that I’ve laid out,” Chatterjee said.

Perry’s Sept. 28 proposal requested that FERC issue a final rule within 60 days. But even if Chatterjee won the two additional votes he needs to approve a final rule in December, it could be vulnerable to court challenges on the grounds that it was rushed through without sufficient notice to the public and proper evaluation by the commission.

November 13, 2017

FERC to Examine DTE Reactive Rate Reduction

FERC last week opened a fresh settlement proceeding to determine the fairness of DTE Electric’s decreased revenue requirement for reactive power services, an issue already under scrutiny by the agency (ER17-2465).

DTE in April asked the commission to approve an $11 million annual revenue requirement for reactive supply in the ITC transmission pricing zone, down 14% from the current $13 million requirement (ER17-1414). The Detroit-based utility submitted the revised request in September to account for an additional $118,000 decrease stemming from the Nov. 14 retirement of St. Clair Unit 4, an aging coal-fired generator. The first request had been under settlement proceedings for four months by the time of the second filing (EL17-71).

FERC MISO revenue requirement DTE — St. Clair Power Plant | *Inland Mariners*

The company cited seven retirements, increased investments in generation units that provide reactive service, and the replacement of its total revenue requirement with unit-specific revenue requirements as reasons behind the rate decrease.

FERC said preliminary analysis shows that DTE’s rate schedule may still be unreasonable even with the $118,000 decrease, and consolidated the newly opened settlement proceeding with the existing one under a new docket, EL18-23.

“Because DTE Electric is proposing a rate reduction, but a further rate decrease may be appropriate, we will institute a Section 206 proceeding,” FERC wrote.

— Amanda Durish Cook

November 13, 2017

FERC OKs SPP Scarcity Pricing Change

By Rich Heidorn Jr.

FERC last week approved SPP’s proposal to change the way it prices regulation and operating reserves but said the RTO should respond to complaints that it overuses out-of-market procedures to avoid scarcity pricing.

The ruling, effective May 11, 2017, finalized a tentative approval granted by FERC staff in August before the commission regained its quorum (ER17-1092).

The changes were in response to FERC’s June 2016 ruling (Order 825) requiring RTOs and ISOs to align their settlement and dispatch intervals and implement shortage pricing during any shortage period. (See FERC Issues 1st RTO Price Formation Reforms.)

SPP previously set a single administrative scarcity price for each reserve product regardless of the severity of a shortage. Under the new rules, the RTO will use segmented demand curves with higher degrees of scarcity resulting in higher prices. It is also renaming its operating reserve demand curve as the contingency reserve demand curve.

In approving the changes, the commission rejected a complaint from Golden Spread Electric Cooperative that the regulation demand curves should begin with a steeper slope to incentivize units to provide regulation earlier.

“We find that SPP has supported the structure of the proposed contingency reserve demand curve, which is based on NERC requirements for SPP to carry reserves to protect against loss of the largest online resource in its footprint and based on the contingency reserve the [Reserve Sharing Group] procures to protect against the loss of half of the second largest online resource in the SPP footprint,” FERC said.

However, it directed SPP to add to its Tariff definitions and other details of the new rules, which the RTO had planned to include in its Marketplace Protocols. “The commission has found that provisions that are used to calculate a rate should be included in the Tariff because they significantly affect rates, terms and conditions of service,” the order said.

The commission also rejected Golden Spread’s complaint that SPP has prevented the implementation of shortage pricing by overusing out-of-market actions such as reliability unit commitments and manual commitments.

FERC SPP scarcity pricing — Golden Spread Electric Cooperative complained that SPP’s shortage pricing rules are insufficient, depressing prices for plants that can respond quickly to scarcity conditions. Its Antelope Station, near Abernathy, Texas, can reach its full 168-MW output in five minutes. | *GSEC*

Although the commission said Golden Spread’s call for market design changes regarding such actions was outside the scope of the proceeding, it said the cooperative had “raised an important issue that SPP should consider exploring through its stakeholder process.”

“We understand that there may not be sufficient data available to stakeholders to facilitate these discussions, as the commission noted in its Notice of Proposed Rulemaking in Docket No. RM17-2,” the commission said, referring to its January 2017 proposal to reduce uplift, allocate it more accurately and increase transparency. (See FERC Seeks More Transparency, Cost Causation on Uplift.)

“While further commission action in Docket No. RM17-2 may result in additional transparency, we encourage SPP to work with its stakeholders and provide them with the data necessary to aid in any discussions about this issue.”

November 13, 2017

Early Adopter Pa. Worried by Retreat from Competitive Markets

By Rich Heidorn Jr.

CAMP HILL, Pa. — Pennsylvania, which was among the first states in the U.S. to abandon cost-of-service electric regulation, now finds itself at ground zero of a debate that could largely reverse the process. So last week’s 7th Annual Pennsylvania Energy Management Conference couldn’t have been more timely.

zero-emission credits DOE NOPR — Pugliese | © *RTO Insider*

FERC Chief of Staff Anthony Pugliese, who grew up just a few miles from here, praised the Department of Energy’s Notice of Proposed Rulemaking to support struggling coal and nuclear generators, while promising it would not destroy PJM’s competitive market.

Exelon’s Kathleen Barron continued her ongoing debate with NRG Energy and other critics over subsidies for the company’s nuclear plants. (See EBA Panelists Talk ‘Wacky’ NOPR, ‘Modest’ ZECs, ‘Rent Seeking’.)

And PJM Independent Market Monitor Joe Bowring, who shared a panel with Barron and NRG’s Abe Silverman, continued his attack on the RTO’s proposed alternative. (See related story, NOPR Reply Comments Bring More Criticism of PJM Proposal.)

Stranded Costs

Pamela C. Polacek, an attorney with McNees Wallace & Nurick, one of the conference’s sponsors, joined in the criticism. Her firm has long represented industrial customers and was central to Pennsylvania’s move — following California and Massachusetts — to customer choice in 1996.

Pennsylvania consumers paid $12.3 billion in stranded costs to Exelon’s PECO Energy and other nuclear plant owners between 1996 and 2010 as part of the bargain to unbundle generation from distribution. Polacek said subsidies for all of Pennsylvania’s nuclear plants could cost $1.2 billion per year — raising the annual electric bill for a small industrial user (12 million kWh/year) by more than $100,000, and that for a steel mill (330 million kWh/year) by $2.8 million.

“We can’t afford this in Pennsylvania,” she said. “We rank 48th in manufacturing job creation. … We can’t continue to pile costs onto our industrials. Right now, our average industrial electric rate is about the middle [of the states]. But remember, we did this [retail choice] back in 1996 to get competitive advantage, not just to be in the middle.”

Polacek said Three Mile Island Unit 1, the only planned nuclear retirement in Pennsylvania, doesn’t deserve a rescue.

“As Joe has said, other Pennsylvania nuclear plants continue to clear the [capacity] auction. For the most part, they are not at risk of retirement.”

Investment

She acknowledged that as a single-reactor plant (following the partial meltdown of Unit 2 in 1979) TMI does not have the labor economies of scale of multi-unit plants. But she said saving TMI’s 750 workers would cost jobs in manufacturing because of higher electric rates.

“Three Mile Island didn’t really take the opportunities to do upgrades that other Pennsylvania-based plants did. So those plants were looking at investing in their infrastructure to expand their capacity, to be more efficient. And Three Mile Island didn’t do that.”

Exelon, which purchased the plant from GPU in 1999, said in May it would shutter TMI in September 2019 “absent needed policy reforms.” (See Seeking Subsidy, Exelon Threatens to Close Three Mile Island.)

Barron disputed Polacek’s claim of underinvestment. “I can tell you we continue to invest very heavily in Three Mile Island, having replaced the steam generator … and [made] other investments,” she said.

She cited a Brattle Group study that predicted early retirement of the state’s nine nuclear generators would increase prices by $788 million per year, a 5% increase.

Resilience

The two also sparred over nuclear power’s value to the grid’s resilience.

“Looking at the idea of having onsite fuel supply as being something that is going to help us if all four gas pipelines serving the Northeast go down, I have to ask: Well if the terrorists do that, what’s going to stop them from also targeting the nuclear plants, which would seem to be a pretty attractive, World Trade Tower-type targets?” Polacek said.

Barron said nuclear plants’ defenses against terrorists are second to none. “We are so heavily regulated by a number of regulators, including the [Nuclear Regulatory Commission], on this specific point, on the amount of security we have to have in our plants and the ways that we need to protect them,” she said. “There are more people who [are carrying] guns than people who are operating the plant. … We do not have anywhere near that kind of protection on the natural gas supply system.”

That is beside the point, responded Bowring, saying the vulnerabilities of gas pipelines also apply to electric transmission. “It doesn’t matter what the fuel type is if the transmission grid is not there,” he said. “So, you have to be careful how far you extend this argument.”

ZECs

ZEC DOE 7th Circuit Court of Appeals PJM 2015 Annual Meeting — Silverman | © *RTO Insider*

NRG’s Silverman said that he agreed with the DOE on the need for price-formation reforms. But he said zero-emission credits for nuclear plants are not a good solution. ZEC prices in New York and Illinois will produce half as much carbon-free electricity as equivalent spending on renewables, he said.

He was critical of a Brattle study commissioned by NYISO and state regulators to evaluate the impact of ZECs. (See NYISO Study Sees Little Cost Impact from Carbon Charge.)

“It completely ignores the energy market response. Completely ignores the power of competition to find cheaper solutions and drive down the price,” he said.

“We have these price-formation initiatives at FERC that have now been pending, in some cases, for four or five years. They need to be acted on. I mean come on guys, yes or no.”

And he said the issue is broader than price formation. The challenge, he said, is creating incentives for what NRG calls the “four-product future,” which envisions renewables providing most energy, supported by storage, controllable demand and fast-ramping gas. NRG says it will reduce the carbon emissions from its generation 50% by 2030 and 90% by 2050.

“A [gas-fired] power plant built today is already going to be lasting until 2050 and [will] be emitting too much carbon” to address climate change, Silverman said. “So, we end up with this long-term stranded cost environment where today’s gas plants are tomorrow’s coal plants.”

November 13, 2017

NOPR Reply Comments Bring More Criticism of PJM Proposal

By Rich Heidorn Jr.

PJM’s proposed alternative to the Department of Energy’s proposed coal and nuclear price supports came under fire last week, as market monitors, regulators and other RTOs joined PJM Independent Market Monitor Joe Bowring in opposition.

PJM was harshly critical of the DOE Notice of Proposed Rulemaking, which would provide cost-of-service payments for coal and nuclear plants with at least 90 days of on-site fuel supply (RM18-1). Coal and nuclear generation is responsible for more than 50% of PJM’s winter fuel mix, more than any other region in the U.S., excluding VACAR South.

Instead, the RTO called on FERC to order it and other RTOs to file price formation rule changes within 180 days. It has proposed that inflexible generators be allowed to set LMPs. CEO Andy Ott says that by increasing energy prices and creating a steeper supply curve, the change would reduce uplift and increase incentives for following dispatch instructions. (See Critics Slam PJM’s NOPR Alternative as ‘Windfall’.)

At a conference in Camp Hill, Pa., on Wednesday, Bowring rejected Ott’s premise. “Clearly the supply curve is not too flat in PJM,” Bowring said. “PJM has been ensuring the reliability of the grid for the last almost 90 years and it continues to do so. The grid is reliable and resilient, although resilience remains to be defined.”

In reply comments last week, Bowring faulted the proposal on both substance and process, saying the RTO’s 180-day timeline “would unnecessarily truncate the PJM stakeholder process.”

PJM FERC Market Monitor Joe Bowring DOE NOPR — Place | © *RTO Insider*

Pennsylvania Public Utility Commission Vice Chairman Andrew Place was also critical, saying PJM’s “fast-track proposal for consideration of reforms to marginal cost and shortage pricing are inconsistent with its comments which document the sufficiency of PJM’s reliability.”

“Appropriate and cost-effective reliability and resiliency requirements can be developed through market-based mechanisms, rather than discriminatory, cost-based mechanisms,” Place said.

Robert Howatt, executive director of the Delaware Public Service Commission, joined with environmentalists, industrial customers and others in also opposing the PJM plan. “PJM’s request for a near-term directive to file a proposal it has not fully revealed to its stakeholders, and which has not received the appropriate (let alone any) vetting, inappropriately subverts the stakeholder process,” the group said.

ISO-NE, NYISO Seek Distance from PJM

Both ISO-NE and NYISO sought to distance themselves from PJM’s proposal.

“The region has already invested significant work in implementing major market improvements, including energy market offer-flexibility enhancements, sub-hourly settlements and Pay-for-Performance,” ISO-NE said.

NYISO said it “takes no position on PJM’s proposed reforms at this time other than to emphasize that they are not applicable to New York. Similarly, the NYISO takes no position on the question of whether the commission should initiate Section 206 proceedings in PJM, other than to note that doing so in PJM does not mean it needs to be done in New York. … Consequently, if the commission decides to initiate a Section 206 proceeding to consider PJM’s reforms, it should be a PJM-specific proceeding.”

Other Monitors Also Critical

The CAISO Department of Market Monitoring and Potomac Economics, which monitors MISO, ISO-NE, NYISO and ERCOT, also expressed opposition.

CAISO’s DMM did not submit initial comments on the DOE NOPR because it does not include CAISO, which lacks a centralized capacity market. But it said it was concerned PJM’s proposal could apply to CAISO because it would make changes to spot markets. “If applied to CAISO, the pricing proposed by PJM would undermine CAISO’s spot markets,” the department said. “PJM’s proposal is actually an administrative pricing rule that moves away from efficient spot market pricing.”

Potomac Economics said PJM’s proposal “will be highly inefficient and destructive to existing energy markets in the Eastern Interconnection.”

P3 Group Supports PJM Plan

PJM wasn’t completely lacking for allies. The PJM Power Providers Group (P3) said it “supports the framework that PJM [has] presented to resolve the shortcomings.”

But coal interests said it is too little, too late. FirstEnergy said PJM’s proposal is “nothing more than an argument for delay and will not lead to a remedy for current unlawful rates any time soon.”

“While PJM has not yet determined how much customers will have to pay under this construct and how much power plants would be paid, it almost certainly is not enough help to assure that power plants with resilience benefits through on-site fuel will remain in the market,” said the American Coalition for Clean Coal Electricity and the National Mining Association in a joint filing.

Michael Kuser contributed to this article.