Page 1221 – RTO Insider

January 21, 2018

DC Circuit Rejects New England Scarcity Pricing Challenge

By Rich Heidorn Jr.

The D.C. Circuit Court of Appeals on Friday rejected New England generators’ challenge to FERC orders on scarcity prices, saying the commission had properly considered their complaints (16-1023, 16-1024).

The New England Power Generators Association had asked the court to review two FERC orders related to ISO-NE’s scarcity pricing rules and the peak energy rent (PER) adjustment, which is used to claw back some revenues earned by capacity suppliers when prices in the real-time energy market are very high.

Adjustment Events

ISO-NE each day calculates a strike price set just above the marginal cost of the RTO’s most expensive generation. It also estimates PERs — essentially the difference between the real-time energy price and the strike price — for any hour in which the real-time price exceeds the strike price (“adjustment events,” the court called them).

FERC ISO-NE scarcity prices NEPGA — Dynegy’s 827-MW Lake Road combined cycle plant, Dayville, Conn. | *Alstom*

The PER value is deducted from each capacity supplier’s monthly payments, regardless of whether it sold energy in the real-time market at the high price. NEPGA says most capacity suppliers clear their electricity offers in the day-ahead market, receiving the day-ahead market price, rather than the real-time price on which the adjustment is based.

The commission has acknowledged that this is a “potential inefficiency” and has approved elimination of the adjustment for the 2019/20 capacity commitment year.

Procedural Failure

The D.C. Circuit dismissed on procedural grounds NEPGA’s challenge to FERC’s May 2014 order rejecting a joint filing by ISO-NE and the New England Power Pool Participants Committee.

That “jump ball” filing contained two alternate proposals to address generator performance problems. The commission said neither proposal was sufficient alone, ordering ISO-NE to submit a modified version of its proposal along with increased scarcity prices suggested by NEPOOL (ER14-1050, EL14-52).

The D.C. Circuit said NEPGA lacked standing to seek review of the order because it had not previously sought rehearing from the commission.

Not Arbitrary or Capricious

The court did act on the merits of NEPGA’s complaint alleging that the interaction between the scarcity prices and the PER is unjust and unreasonable.

FERC said the group had not met its burden under Section 206 to prove that the existing Tariff provisions were unjust and unreasonable (EL15-25). The commission said NEPGA’s evidence — data from a Dec. 4, 2014, adjustment and a back-cast analysis — failed to consider the likelihood and size of future adjustments. It also said NEPGA did not address whether increases in day-ahead energy prices and capacity price floors might offset expected increases to the PER. (See FERC Denies Rehearings on ISO-NE Pay-for-Performance.)

The court said the commission’s rejection of the complaint was not arbitrary and capricious, noting that “because we are dealing here with technical and policy-based determinations, the commission’s judgment is entitled to judicial respect.”

Second Complaint

NEPGA said the court should overturn the commission’s rejection of its complaint because of the outcome of the group’s second complaint challenging the PER, filed in September 2016.

In that filing, NEPGA provided an additional 20 months of data in arguing that the PER had become unjust and unreasonable because of the increased scarcity rates.

The commission granted the complaint in part in January 2017 and set the case for hearing and settlement proceedings (EL16-120). (See ISO-NE Scarcity Rules Unfair to Generators, FERC Says.)

An uncontested settlement in that docket is pending before the commission. It would require ISO-NE to increase the daily PER strike price hourly based on the difference between actual five-minute reserve shadow prices and the pre-December 2014 scarcity prices for 30-minute operating reserves and 10-minute non-spinning reserves ($500/MWh and $850/MWh, respectively). The adjusted PER strike price would be effective Sept. 30, 2016, through May 31, 2018, when the PER is abolished.

“We note that any settlement would not fully moot this case because the second complaint proceeding has a refund effective date of Sept. 30, 2016, whereas the complaint in this case requested a refund effective date of Dec. 3, 2014,” the court said.

January 21, 2018

FERC Denies Louisiana PSC Clarification on Entergy ROEs

By Tom Kleckner

FERC last week denied the Louisiana Public Service Commission’s request for clarification on one matter related to a sprawling Entergy-related case before the federal commission.

The PSC was seeking to learn what specific proceeding would determine the return on equity that would apply to amended power purchase agreements that were the subject of an August 2016 order (ER16-1251). It requested the clarification following a January 2017 FERC order denying its request for a rehearing of the 2016 ruling. FERC had said the proceeding regarding the amended PPAs was not the right forum for determining the appropriate ROEs to be applied under a replacement tariff, finding the issues raised by Louisiana regulators to be outside its scope.

The PSC said “that if the appropriate ROE … is outside the scope of the instant proceeding, it does not appear the ROE will be addressed in any [FERC] proceeding.”

In its Jan. 18 ruling, FERC told the PSC it had explained in the 2016 order that issues concerning the application of ROE under Entergy’s unit power sales and PPAs are pending in the massive ER13-1508 docket. FERC also noted that it had already dismissed concerns by the PSC about applying a generic ROE to the amended PPAs.

FERC LPSC Entergy Power Purchase Agreements PPAs — MISO North and MISO South | *MISO*

FERC last week also approved an uncontested partial settlement related to adjustments in MISO Tariff transmission formula rate templates for Entergy’s operating companies (ER17-2579), directing the company to file a revised rate template in eTariff and terminating four related dockets (ER17-2579, ER16-1528, ER15-1453 and ER15-1436).

Entergy Services had objected to FERC trial staff’s October 2017 recommendation that it file a revised rate template for Entergy Gulf States Louisiana, but a settlement judge in November certified the partial settlement as uncontested.

The settlement memorializes adjustments to three items in the Entergy operating companies’ rate templates: excess accumulated deferred income taxes; certain permanent differences in income taxes; and the Entergy operating companies’ post-retirement benefit costs other than pensions for 2014 and 2015.

January 21, 2018

FERC Denies New England Tx Owners ROE Rehearing

By Michael Kuser

FERC on Thursday denied requests by New England transmission owners and the Edison Electric Institute for rehearing of its September 2016 ruling regarding complaints over the TOs’ base return on equity.

Since September 2011, numerous parties have filed complaints seeking reductions in the New England TOs’ base ROE.

The commission’s 2016 order established hearing and settlement judge procedures and a refund effective date for a complaint filed by an ad hoc group of municipal utilities, Eastern Massachusetts Consumers-Owned Systems, which contended that the New England TOs’ 10.57% base ROE (11.74% including incentives) should be reduced to 8.78% and 11.38%, respectively.

iso-ne roe return on equity — | *ISO-NE*

The commission’s Jan. 18 order rejected every argument made by the TOs, saying it “has repeatedly rejected the assertion that every ROE within the zone of reasonableness must be treated as an equally just and reasonable ROE in [a Federal Power Act] Section 206 proceeding” (EL16-64-001).

FERC in October rejected a bid by the TOs to increase their ROEs to the levels before they were lowered by a 2014 commission order vacated by an appellate court in April 2017. The commission said it would address the actual rate in a later remand order (ER15-414, EL11-66). (See FERC Rejects New England Tx Owners on ROE.)

The TOs also argued that constant litigation over the ROEs introduces risk and uncertainty in the ratemaking process.

They contended that the 15-month refund limitation in Section 206, as amended by the 1988 Regulatory Fairness Act, requires the commission to deny a complaint when a similar complaint is already pending.

“While Congress’ adoption of a 15-month refund limitation in the Regulatory Fairness Act gave public utilities some rate certainty in FPA Section 206 proceedings, the New England TOs misinterpret the level of certainty that Congress provided,” the commission said.

Following such logic “would prohibit any party from challenging a utility’s ROE as long as there is another complaint involving that utility’s ROE pending before [FERC], the commission said. “The language of FPA Section 206 does not support such a finding.”

The commission also rejected the TOs’ assertion that it had ignored “countervailing evidence regarding the cost of equity capital and the fact that the capital markets continue to remain unusual,” insisting it “had reviewed the pleadings and evidence submitted by all parties and found that the evidence raises issues of material fact that could not be resolved based upon the record before the commission. The hearing and settlement judge procedures established in the September 2016 order are the product of that review and are the appropriate vehicle to resolve the dispute.”

January 21, 2018

FERC Denies Bear Swamp Waiver on Affiliate Info

FERC on Thursday denied Bear Swamp Power’s request for a waiver of the requirement to include certain affiliate information in its market-based rate filings (ER17-603).

Bear Swamp, which is controlled by Brookfield Renewable Energy Group, operates the 600-MW Bear Swamp Pumped Storage Development and the 10-MW Fife Brook Development on the Deerfield River in northwestern Massachusetts.

In December 2016, the company filed a notice of change in status, reporting that Nova Scotia-based Emera had acquired an indirect 50% ownership in the company. Bear Swamp requested a waiver of the requirement to include Emera generation and transmission assets in its change-in-status notice and future market-based rate filings.

The company argued that Emera’s affiliates should not be included in its horizontal market power analysis and other filings because its generation capacity is fully attributed to Brookfield, and Brookfield is not privy to Emera’s acquisition activities. Emera affiliates include Emera Maine and Tampa Electric.

“Bear Swamp has not presented any compelling reason for its request,” the commission said in its Jan. 18 order. “The facts that Brookfield and its affiliates are not privy to the acquisition activities of Emera and its affiliates, and that a Brookfield affiliate controls day-to-day operations of Bear Swamp’s generation facility, [do] not affect the affiliate relationship between Emera and Bear Swamp.”

The commission directed the company to submit an updated market power analysis including Emera affiliates within 30 days.

Under FERC’s market-based rate regulations, any company controlling 10% or more of another company is considered an affiliate.

— Michael Kuser

January 21, 2018

FERC Nixes SMECO Request to Pre-empt Md. Solar Rules

FERC last week denied a request by Southern Maryland Electric Cooperative (SMECO) to rehear a petition asking it to rule that Maryland Public Service Commission regulations on acquiring power from community solar facilities run afoul of the federal Public Utility Regulatory Policies Act (EL16-107).

FERC SMECO solar maryland — Centreville, Maryland Solar Array | *Paradise Energy Solutions*

SMECO and Choptank Electric Cooperative had asked FERC in 2016 to issue a declaratory order that the PSC’s rules covering from which facilities and at what price state utilities must buy solar is pre-empted by PURPA. FERC declined at the time, arguing that the action was premature because the program was voluntary and neither cooperative had indicated it planned to enter into the program.

The cooperatives in December 2016 then asked the commission to grant a rehearing of the request or otherwise clarify that the ruling was without prejudice so that they could bring their complaint again if the PSC failed to address their concerns. They also requested that the filing fee be waived the second time around. Last October, SMECO filed a motion to supplement the record to include a proposed solar tariff it had filed with the PSC, along with the PSC’s recommendations in response and subsequent letter denying the proposal.

SMECO argued this showed its intent to enter into the program and that it had exhausted all of its state law remedies, but FERC was not persuaded.

“SMECO’s motion does not allege any change to the facts relied upon by the commission in dismissing the petition, particularly, that the community solar systems program remains voluntary and that SMECO is not subject to the program’s regulations,” the commission wrote in denying the rehearing.

The order did clarify that the denial was without prejudice but did not waive the filing fee. Commissioner Robert Powelson didn’t participate in the order.

— Rory D. Sweeney

January 21, 2018

‘Creative’ Settlement Approved in VEPCO Revenue Spat

By Rory D. Sweeney

Despite complaints from PJM’s Independent Market Monitor, FERC last week approved a settlement in a yearslong fight over how much revenue Virginia Electric and Power Co. should receive for its reactive energy supply fleet.

FERC VEPCO reactive energy — Bowring | © *RTO Insider*

The commission’s ruling said “the IMM’s concerns are too attenuated to outweigh the bargained-for benefits of the settlement, which include rate certainty and reduced litigation costs” (EL16-89, EL17-40, ER06-554, ER17-512).

The settlement between VEPCO, North Carolina Electric Membership Corp., Old Dominion Electric Cooperative and Northern Virginia Electric Cooperative came after FERC initiated a review in July 2016 of VEPCO’s rates for reactive services under Section 206 of the Federal Power Act.

The settlement maintains VEPCO’s fleetwide annual revenue requirement of $27.5 million but maintains a list compiling the revenue requirements for each generating unit totaling nearly $40 million. When VEPCO files to retire a unit, it will remove the unit’s associated revenue from the compiled list. However, its fleetwide revenue requirement will remain the same, and the other parties agreed not to contest the filing until the compiled list totals less than $27.5 million.

The Monitor argued that VEPCO, a Dominion Energy subsidiary, should have to itemize how much of the $27.5 million is attributable to individual units each year. The Monitor said the information would help with calculating several of the plants’ market positions, including their cost-based offers, but FERC dismissed the requests.

In a separate case, FERC also approved a settlement in the reactive rate requirements for Talen Energy’s West Deptford facility (EL16-100, ER14-1193).

January 19, 2018

FERC Approves Transfer of New Jersey Plants

FERC on Thursday gave energy investment firm Ares EIF Management the go-ahead to transfer its ownership in two New Jersey cogeneration facilities to Excalibur Power (ER16-2217, ER17-2515).

Ares EIF Management Excalibur Power — Logan Cogeneration Plant | *Google Maps*

Ares owns a 242-MW facility in Logan Township and has a 60% stake in the 285-MW Chambers cogeneration facility in Carneys Point. Atlantic Power owns the other 40% of the latter plant. Both plants have FERC-approved rate schedules to provide reactive power to PJM.

The commission also granted a request to waive the 90-day notice period for transferring the plants, although Ares and Excalibur had sought to obtain the waiver by Dec. 15.

— Rory D. Sweeney

January 19, 2018

Report: Fuel Security Key Risk for New England Grid

By Michael Kuser

A new ISO-NE report finds that New England’s grid is vulnerable to a season-long outage of any of several major energy facilities, such as the 688-MW Pilgrim nuclear plant in Plymouth, Mass., which went offline during a recent cold snap after the loss of a power line leading to the plant.

That incident resulted in no reliability issues for the RTO.

ISO-NE LNG electricity imports natural gas — Pilgrim Nuclear Station Control Room | *Entergy*

“Maintaining reliability is likely to become more challenging, especially if current power system trends continue,” the RTO’s Operational Fuel-Security Analysis report said.

The most concerning trend: the increasing reliance on natural gas for power generation, which has led to supply constraints during times of peak load. Under normal conditions, New England relies on natural gas for about half its electric power generation, up from 15% in 2000.

The grid operator began the study in late 2016 to quantify the region’s future fuel security risk. It planned to issue the report last fall but delayed publication until the furor died down over Energy Secretary Rick Perry’s proposed rulemaking to financially support coal and nuclear generators (RM18-1). (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)

“The goal was to understand the future implications of several significant trends already affecting grid operations,” ISO-NE CEO Gordon van Welie said. “The results aren’t a prediction, but they do shine a light on the potential reliability consequences of retirements of generators with stored fuels and the significance of liquefied natural gas, imports, renewables and oil inventories at dual-fuel power plants.”

The study grew out of the RTO’s experiences operating the system through challenging winter conditions and was undertaken to ensure that power plants have, or are able to procure, the fuel they need to meet demand and maintain power system reliability.

Scenarios and Risks

The study created 23 scenarios and focused on five key variables: retirements of coal- and oil-fired power plants; availability of LNG; oil tank inventories at dual-fuel generators; electricity imports from neighboring power systems; and the addition of renewable resources.

The report highlighted the concern that New England’s system reliability is heavily dependent on LNG and electricity imports. While dual-fuel capability for plants can provide a key contribution to reliability, permitting for construction and emissions is difficult. All but four scenarios resulted in fuel shortages requiring rolling blackouts, indicating the trends affecting the system may intensify the region’s fuel security risk.

RTO planners concluded that developing renewable resources could help reduce the fuel security risk but will also likely drive more coal- and oil-fired generators into retirement, requiring increased LNG imports to counteract the loss of stored fuels. At the same time, higher levels of LNG, electricity imports and renewables can minimize system stress and maintain reliability. But delivery assurances for LNG and electricity imports, and transmission expansion, will be needed to attain those levels, the report said.

Recent and impending retirements of oil, coal and nuclear power plants will translate into 4,600 MW of retirements by June 2021, representing more than 10% of the region’s total installed capacity, the report said.

The RTO noted that about 13,500 MW of new generation was in its interconnection queue as of Dec. 1.

“Proposed wind farms make up just over half the proposals, or about 7,300 MW,” the report said. “The queue also includes 1,000 MW of proposed solar (8% of the total) and 400 MW of battery storage (3% of the total). Not all these projects will be constructed; historically, about 68% of the megawatts proposed are never built.”

Massachusetts Sierra Club Director Emily Norton took issue with those numbers.

The report “inexplicably underestimates the amount of renewable energy — i.e. solar and wind — that we know will be coming online in coming years,” Norton said in a statement.” Yet even a report rigged against clean energy shows that New England can affordably and reliably replace most of its old, dirty, dangerous and uneconomic power plants without spending billions of dollars on unnecessary gas pipelines.”

ISO-NE plans to discuss the results of the analysis with stakeholders, regulators and policymakers throughout 2018 to determine the level of fuel security risk they are willing to tolerate.

January 19, 2018

MISO Readies Retirement Change

By Amanda Durish Cook

CARMEL, Ind. — MISO is close to completing a plan that would give generators three years to submit a decision to retire after signaling their intention, but some stakeholders think the changes could allow unit owners to “game the system” for allocating transmission costs.

MISO FERC generator retirements — Joe Reddoch | © *RTO Insider*

Joe Reddoch of MISO’s retirement planning group said the proposal — slated for a March filing with FERC — will close out a longtime recommendation from the Independent Market Monitor to allow generators to time their retirements according to Planning Resource Auction timelines.

Under the proposal, generation owners considering or planning a shutdown will still submit an Attachment Y notice to MISO, but the RTO will now treat all such notices as a request for suspension. Owners would no longer have to decide between a permanent retirement and a temporary shutdown with an estimated return-to-service date.

Instead, they would have three full planning years to prepare a return to service or decide to make the suspension permanent, providing additional time to decide whether to participate in the capacity auction. Suspended generators would lose interconnection service after three planning years if they don’t resume operations.

“By removing the return date [requirement], we can actually consider them in our planning processes,” Reddoch said during a Jan. 17 Planning Advisory Committee meeting.

Reddoch said MISO plans to continue its practice of passing pro rata transmission upgrade costs needed to maintain baseline reliability to unit owners who rescind their decision to retire.

Wind on the Wires’ Natalie McIntire pointed out that unit owners cause unnecessary costs for new interconnection customers by deciding to suspend and then come back online after an interconnection customer has shouldered the entire cost of interconnecting to make up for the lost generation.

“We have concerns about this,” McIntire said. “This treatment sort of creates an opportunity to game the system.”

“They could play games right now, but they don’t. They’re simply looking at the viability of their assets,” Reddoch said. “Right now, we create a false sense of security by modeling their return date when most of them never return.”

Reddoch said the proposal will not require changes to the planning process, as planning models already assume all retiring and formerly suspended units will be offline within 36 months. MISO last year deferred the proposal while it looked into possible modeling implications stemming from the change. (See MISO Defers Retirement Process Changes.)

MISO Director of Planning Jeff Webb said the plan improves the auction because owners uncertain about retiring a generator can still choose to participate in auctions, but the RTO’s Interconnection Planning Task Force could still explore the possibility that interconnection customers could be left holding the tab on an ultimately ineffectual network upgrade.

Other stakeholders said generation owners could potentially game the system by vacillating in and out of three-year suspensions. Reddoch pointed out that MISO’s Tariff limits total suspension times to three years in a five-year period.

January 19, 2018

FERC Rejects Challenge to PJM CP Rules on Coal Plants

By Rich Heidorn Jr.

FERC on Thursday rejected an Illinois Municipal Electric Agency challenge to PJM’s Capacity Performance rules for coal plants, saying it had dealt with IMEA’s concerns in its June 2015 order approving the program (ER15-623-010, et al.).

IMEA asked for rehearing on two aspects of the commission’s May 2016 follow-up CP order on compliance, arguing that the order will “unduly disadvantage coal-fired generation owners like IMEA who separately bid in their minimal level of output and megawatts,” according to FERC’s summary.

PJM Capacity Performance CP IMEA — IMEA owns 12% of LG&E and KU’s Trimble County 1, a 514-MW coal-fired unit between Louisville and Cincinnati. | *LG&E-KU*

Created in 1984, IMEA comprises 32 municipal electric systems and one cooperative in Illinois. It owns a 15% stake in two 800-MW supercritical units at the Prairie State Generating Co. in Southern Illinois, and 12% of Trimble County 1 (a 514-MW coal-fired unit) and Trimble County 2 (a 750-MW super-critical, pulverized coal-fired unit) located between Louisville and Cincinnati.

Nonperformance Charge Exemption

IMEA said FERC should have approved PJM’s compliance filing — a response to the June 2015 order — proposing to exempt generators from nonperformance charges “if the relevant resource is not scheduled by PJM, or is online but scheduled down, subject to a determination by PJM that such an action is appropriate” under its economic dispatch.

The agency said the May 2016 order was thus inconsistent with commission precedent recognizing the longer ramp-time needs of coal units.

But FERC ruled that “IMEA effectively seeks rehearing of the initial June 2015 order, not the May 2016 order.”

“Having failed to seek rehearing of the June 2015 order on this issue, IMEA may not raise these issues on rehearing of the May 2016 order addressing PJM’s compliance filing,” the commission said.

Operating Parameter Constraints

PJM IMEA Capacity Performance CP — IMEA Members | *IMEA*

The commission also rejected IMEA’s argument that PJM’s compliance proposal on operating parameter constraints failed to provide sufficient specificity or transparency.

IMEA said “it is critical that PJM be required to explicitly document the specific operating limitations it will impose on a given resource and the reasons justifying those limitations,” FERC explained.

In response, the commission reiterated its May 2016 order, finding that PJM’s provision of timelines and details specifying how the RTO will implement its process for reviewing unit-specific parameter limited schedules is sufficient.

The commission cited “provisions of PJM’s Tariff allowing for an annual review of unit-specific parameter limitations and a case-by-case procedure through which a resource can justify operating outside of its unit-specific parameters for purposes of receiving make-whole payments. The May 2016 order further interpreted PJM’s obligation to notify a seller in writing regarding PJM’s determination as a commitment to provide sufficient detail regarding its determination.”

Chairman Kevin McIntyre and Commissioner Robert Powelson did not participate in the ruling.