FERC on Thursday again rejected a challenge to Ameren Illinois’ formula rate while tamping down a rehearing request from Ameren itself (EL16-1169-001).
| Ameren Illinois
The ruling denying rehearing lays to rest a challenge by Southwestern Electric Cooperative and Southern Illinois Power Cooperative to Ameren’s 2015 $214.4 million projected net revenue requirement. FERC largely upheld the rate in a September 2016 order while ordering Ameren to change how it accounts for contributions in aid of construction; include net operating loss carryforward in its rate base; and exclude some charges for allowance for funds used during construction from its 2016 true-up. (See FERC Finds No Significant Problems in Ameren Rate Filing.)
Both Ameren and the cooperatives sought rehearing of the 2016 ruling, with the company arguing that FERC should have dismissed the cooperatives’ first challenge outright because of “nebulous and undocumented assertions.” The cooperatives said FERC had broken with commission precedent that allows “parties to challenge the inputs to the formula rate in the same way as they can challenge costs in a stated rate case” because the commission declined to investigate whether the challenged costs were recoverable.
FERC rejected both arguments. “The commission’s power to dismiss a pleading summarily is discretionary, and declining to exercise that power here is therefore not legal error,” it told Ameren. It told the cooperatives that their interpretation of commission precedent was inapplicable because they were challenging the rate itself and not seeking “after-the-fact corrections and updates.” Finally, the commission refused the cooperatives’ request to expand the proceeding into a broader investigation of Ameren’s expenses. Initiating such an investigation, FERC said, would be beyond the scope of the complaint.
Louisiana regulators are questioning why MISO called a maximum generation event and issued instructions for conservative operations in its South region during an extreme cold snap last week.
Eric Skrmetta, chair of the Louisiana Public Service Commission, told The Advocate that he’ll seek an investigation into last week’s actions in MISO South, saying there was “no reason in the state of Louisiana for electricity to become short.” Commissioner Craig Greene said the agency would examine the electricity supply during the cold snap and look to identify ideas for better utility response in future frigid weather.
Reached by phone, a member of the PSC’s staff told RTO Insider that they were in the process of reviewing the event and declined to comment further.
MISO spokesperson Mark Brown said the RTO was able to maintain grid reliability even as extreme temperatures gripped the South and multiple generation outages posed challenges.
The RTO declared conservative operations and a cold weather alert for MISO South — which spans Arkansas, Louisiana, portions of Mississippi and part of eastern Texas — beginning Jan. 15, when most of Louisiana was under a winter weather advisory. It cautioned operators in the natural gas-heavy region to prepare for fuel restrictions.
The region set a new winter demand record of 32.1 GW on Jan. 17 as temperatures dipped to about 30 degrees Fahrenheit below normal and winter storm warnings were issued in Louisiana. The region’s all-time summer peak is 32.6 GW.
That same day, Entergy Louisiana reported that about 32,000 homes and businesses had lost power because of the winter storm, and it later thanked customers for responding to the conservation plea.
Entergy crews in snow | Entergy
The South region resumed normal operations late on Jan. 18, after the Louisiana PSC had issued a public appeal on behalf of MISO and Entergy Louisiana asking customers to conserve energy by lowering thermostats, sealing households against outside air as much as possible and postponing laundry and bathing during the unusually cold temperatures.
Louisiana tops all other U.S. states in energy consumption per capita, in part because of the number of oil refineries and manufacturing plants on the Gulf Coast, according to a report last year by the U.S. Energy Information Administration.
MISO South Executive Director of External Affairs Kent Fonvielle said the RTO shared the Louisiana PSC’s concerns about reliability.
“In extreme conditions such as this week’s bitter cold in the South, MISO delivers the value of a large footprint with a diverse energy mix and greater redundancies to address various challenges to operations,” Fonvielle said in an email to RTO Insider. “As the generation resources available to serve these extreme load conditions become strained, MISO has a set of procedures to ensure adequate supply and to keep the transmission grid stable.”
He added that, in such situations, MISO South calls on support from MISO Midwest and makes purchases from other RTOs. It’s also common for MISO to request that members activate their load control programs and issue public appeals for conservation, he said.
“It is rare for MISO to ask for conservation efforts, but ultimately those conservation efforts help protect the larger grid,” Fonvielle said. “Our role is to coordinate the best use of the power resources available across the MISO footprint so that it is reliable and cost-effective.”
Fonvielle said MISO appreciated the cooperation it received from South members, stakeholders and consumers to conserve energy during the peak conditions. He added that the RTO would perform its own review of the week’s events and have staff discussions on possible areas of improvement.
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).
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.
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.
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.
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.
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
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.”
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.
Bear Swamp Project Map | Brookfield
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 Reservoirs | Google Maps
“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.
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).
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.
Hebron, Maryland Solar Array | Paradise Energy Solutions
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.
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.
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).
WASHINGTON — FERC on Thursday proposed to adopt several reliability standards intended to mitigate cybersecurity risks posed by the global supply chain of grid operation tools.
Multiple entities around the world may participate in the development of software or technology used by utilities to manage their reliability duties, exposing them to potential corruption.
In a Notice of Proposed Rulemaking (RM17-13) FERC indicated its intention to approve a NERC critical infrastructure protection standard (CIP-013-1) that would require utilities to consider several cybersecurity issues when procuring these products for their medium- and high-impact systems. These issues include:
disclosure of known vulnerabilities in the products;
security event notifications;
coordination of vendor remote access;
notification when vendor employee remote or onsite access is terminated;
coordinated response to vendor-related cybersecurity incidents; and
verification of integrity and authenticity of all software and patches.
NERC noted that the standard does not “require that every contract with a vendor include provisions for each of the listed items.” Rather, utilities would need to “ensure that these security items are an integrated part of procurement activities, such as a request for proposal or in the contract negotiation process.”
The actual terms and conditions of utilities’ contracts with vendors are outside the scope of the standard, as are the activities of the vendors themselves. “A responsible entity should not be held responsible under the proposed reliability standard for actions (or inactions) of the vendor,” NERC said.
Reliability officials would evaluate and reapprove utilities’ procurement processes every 15 months under the standard.
FERC also proposed to adopt two additions to existing NERC standards, both to support the requirements in CIP-013-1. One (CIP-005-6) would require utilities to develop a method for identifying active remote access sessions by vendors. The other (CIP-10-3) would require utilities to verify the source of all software and patches before installing them.
Broader Scope, Tighter Deadline
NERC developed the standards in response to a FERC directive in July 2016, marking only the third time the commission has taken such initiative. (See FERC Orders NERC to Develop ‘Flexible’ Supply Chain Standard.) The organization submitted the proposed standards last September.
FERC found that NERC had generally satisfied the four objectives it had laid out in its order: software integrity and authenticity; vendor remote access; information system planning; and vendor risk management and procurement controls. The commission had also directed that the standard be flexible, leaving it to utilities to determine the best way to comply.
However, the commission directed NERC to include Electronic Access Control and Monitoring Systems (EACMS) — firewalls, authentication servers, security event monitoring systems and intrusion detection systems, for example — as part of the scope of the standard.
It also instructed NERC to evaluate the risks posed by Physical Access Control Systems (PACS) — such as motion sensors, badge readers and electronic locks — and Protected Cyber Assets (PCAs) — networked printers, file transfer servers and local area network switches — as part of a supply chain cybersecurity study the organization’s Board of Trustees ordered last August.
FERC also proposed to tighten the implementation deadline for the standards, shortening NERC’s proposed 18 months after commission approval to 12.
Commissioners: Good First Step
Commissioner Cheryl LaFleur, who had dissented from FERC’s earlier order, issued a lengthy concurrence to explain her vote. She had called the July 2016 directive too broad and lacking in guidance. She had also said the timeline for developing the standards was too short given the lack of stakeholder input.
At the commission’s open meeting Thursday, LaFleur said she still had some of those concerns, calling the standards “quite general.” But, she said, “I agree that they are an improvement over the status quo.
“I do not believe that remanding these standards or the larger supply chain issue to the NERC standards process would be a prudent step at this point,” she said. “Rather, I believe the better course of action at this time is to move forward with these standards and … improve them over time as needed.”
Her colleagues had similar sentiments.
“While the standard is not a panacea, it is an important step forward to tackle a tough problem,” Commissioner Neil Chatterjee said. “It will be particularly important to revisit the standard after several years of experience to see what is working and what aspects could be improved. But again, today’s order is a good step in the right direction.”
Commissioner Richard Glick also called the standards “an important first step,” but “I think more needs to be done.”
Comments on the proposal to adopt the standards are due 60 days after its publication in the Federal Register.
EOP Reliability Standards
FERC on Thursday also approved several updates to emergency preparedness and operations reliability standards proposed by NERC last March (RM17-12).
The revisions streamline existing standards and remove redundant language. The commission said they will ensure accurate reporting of events to NERC’s event analysis group; delineate the roles and responsibilities of entities involved in system restoration processes; and identify the elements required in plans for continuing operations when primary control functionality is lost.
FERC did not make any changes to the EOP standards since it proposed to adopt them last September, nor did stakeholders propose any. (See FERC OKs Rules on Balancing, Interconnection, Remedial Actions.) They will go into effect 60 days after their publication in the Federal Register.
FERC on Thursday denied FirstLight Hydro Generating’s request to change reservoir levels this winter at a Massachusetts hydroelectric plant, citing inadequate time to assess the impact on the endangered shortnose sturgeon (P-2485-076).
Shortnose Sturgeon
FirstLight requested the temporary amendment to increase operational flexibility at its 1,167-MW Northfield Mountain Project in anticipation of potential reliability challenges in New England this winter. ISO-NE supported the request but did not say the extra capacity would be critical to reliability.
FERC sympathized with FirstLight’s intentions, but ultimately sided with the shortnose.
“While we are very sensitive to the need to take all feasible steps to ensure the reliability of the electric grid, and accordingly have approved previous amendment requests by FirstLight, the presence of an endangered species in the project reservoir that may be affected by the amendment is a significant new circumstance,” the commission said. “We could not lawfully approve the current amendment before completing consultation with the [National Marine Fisheries Service], a process that would require the gathering of information, followed by NMFS review and action.”
In comments filed with FERC last October, NMFS indicated the sturgeon had been found in Northfield Mountain’s lower reservoir, which was historically above the recognized upstream extent of the species’ range.
The commission ordered that “any future proposal of a similar nature should be filed a sufficient time before the winter season such that any necessary efforts with respect to [Endangered Species Act] consultation can be completed in a timely manner.”
Under federal regulations, NMFS has 135 days to complete a consultation. The commission said that “it did not appear possible” that the consultation process could be completed before March 31, the end of the period for which FirstLight requested the temporary amendment.
Technical Limits
FirstLight proposed reducing Northfield Mountain’s minimum reservoir elevation from 938 mean sea level (msl) feet to 920, and bumping up the maximum from 1,000.5 msl feet to 1,004.5, increasing the potential operating range from 62.5 feet to 84.5 and available storage from 12,318 acre-feet to 15,327. The company also sought unrestricted use of the extra capacity.
According to FirstLight, the additional 3,009 acre-feet of storage would increase the facility’s maximum daily generation by 2,050 MWh, or an additional 1.8 hours of generation at full load. Within current limits, it is capable of generating 8,729 MWh/day during peak load conditions.
But FERC signaled that it would seek limits on the flexibility offered by the adjustments. In its decision, the commission ordered that “any future proposal should be restricted to use during ISO-NE discretionary actions taken during emergency operations … unless FirstLight can provide sufficient evidence why a broader amendment is appropriate.”
The commission has previously granted six temporary amendments for the facility. The first three allowed FirstLight to modify operations only when ISO- NE declared an energy emergency, triggered by a forecast showing electric demand could exceed capacity reserves. The fourth and fifth did not restrict FirstLight’s use of the additional storage, but the sixth, most recent amendment also restricted the use of the additional storage to declared emergencies.
Connecticut River at Turners Falls
Northfield Mountain includes an upper reservoir, an underground powerhouse containing four reversible pump-turbine generators and an intake/outlet structure in the Turners Falls reservoir. The 22-mile-long reservoir on the Connecticut River serves both Northfield Mountain and the Turners Falls Hydroelectric Project, for which FirstLight also holds the license.
Northfield Mountain Environmental Impact Study | FirstLight Hydro
Northfield Mountain, Turners Falls and three other hydroelectric facilities directly upstream are all currently undergoing relicensing. As part of that process, the licensees are required to conduct studies for the five facilities to analyze interrelationships in project operations and environmental effects.
