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).
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).
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.
Carney’s Point Cogeneration Plant | Google Maps
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.
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.
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.”
| ISO-NE
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.
| ISO-NE
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.
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.
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.
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.
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
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.
In a win for PJM’s incumbent transmission owners, FERC ruled Thursday that transmission projects driven by TOs’ individual planning criteria are exempt from competitive bidding.
It also ruled against a competitive transmission developer’s request to allow bidding on some immediate-need projects (ER16-2401, EL16-96).
The order approved Tariff and Operating Agreement revisions PJM proposed in response to FERC’s July 2016 show cause order initiating a Section 206 proceeding over inconsistencies in the OA. (See FERC Rejects PJM Cost Allocation on Dominion Project.)
PJM made revisions suggested by the commission to clarify that projects driven solely by a TO’s Form 715 local planning criteria are not subject to PJM’s competitive process because all the costs are allocated to the zone of the TO. PJM’s competitive process is limited to regionally allocated projects.
In the revisions, PJM also said it will identify local planning criteria transmission needs at the monthly Transmission Expansion Advisory Committee meetings so stakeholders can review and comment on them. The RTO will present its solutions to the issues, identifying applicable criteria, the project’s zone, alternatives it considered and an explanation of the decision to assign the project to the incumbent TO.
LSP Challenge
LSP Transmission, an LS Power subsidiary, challenged both the 206 proceeding and PJM’s filing in response. It said the RTO’s proposed revisions stifle competition and overlap with issues outstanding in other dockets, including a request for rehearing on an order that Form 715 projects aren’t eligible for regional cost allocation (ER15-1387). It also cited a show cause order in August 2016 questioning whether PJM TOs’ procedures for planning supplemental projects provided stakeholders opportunity for “early and meaningful input and participation,” as required by Order 890 (EL16-71).
Neither has been decided. In December 2016, the commission did reiterate an earlier ruling that Form 715 projects are not eligible for regional cost allocation. (See FERC Rejects Challenges on Local Tx Cost Allocations.)
Defining ‘Immediate Need’
LSP also argued that FERC “got it backwards” in directing PJM to clarify the three-year threshold for immediate-need reliability projects. LSP said immediate-need projects should only be exempt from competition if the in-service date of a solution is within three years, rather than also exempting those with a need date within that period.
PJM responded that it “makes no sense” to delay a project that cannot be built within three years to conduct bidding.
FERC agreed, saying, “The fact that it may take longer than three years to build a solution to an immediate reliability need is not a persuasive justification for potentially further delaying the solution.”
RTEP Approvals
In a related order, FERC on Thursday confirmed its approval of PJM’s cost allocations for projects added to its Regional Transmission Expansion Plan in March 2017 (ER17-1236). Commission staff had approved the allocation tentatively in June 2017 while the commission was without a quorum.
FERC denied a protest and request for rehearing from Dominion Energy, which had argued it shouldn’t be allocated all costs for two 500-kV facilities in its zone to address its Form 715 criteria. Dominion is appealing the order that allocated all Form 715 project costs to zones in which the criteria apply (ER15-1387).
Commissioner Cheryl LaFleur issued a separate concurrence, pointing out that she had dissented on the order Dominion is appealing.
“As explained in that dissent, I believe the commission should have retained regional cost allocation for transmission projects that are double-circuit 345 kV and 500 kV and above,” she wrote.
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.
