FOLSOM, Calif. — CAISO’s RC West has been shadowing Peak Reliability as the ISO prepares to take over reliability coordinator functions throughout most of the West by the end of this year.
The first phase of the two-month shadow operations — in which RC West employees have been mirroring Peak workers around the clock “in listening mode mainly” — will conclude soon, Tim Beach, RC West’s director of operations, told the organization’s Oversight Committee on Tuesday.
So far, RC West has been included on nearly every call, including an energy emergency alert (EEA) event just a few hours into the process, Beach said. “We’re very happy about that,” he said.
The next phase starts June 1, when RC West and Peak reverse roles. RC West employees will talk to balancing authorities, and Peak will step in “if they don’t like how things are going,” Beach said.
Nancy Traweek, executive director of system operations at CAISO, told the committee that the Western Electricity Coordinating Council had provisionally approved the ISO’s bid to serve as an RC and that the matter is now in NERC’s hands. NERC and WECC plan to observe RC West’s shadow operations in the coming weeks, Traweek said.
Everything is going as planned, she told the committee.
RC West has secured agreements from 39 entities in the Western Interconnection, including Arizona Public Service, PacifiCorp and Seattle City Light. Its footprint stretches from the Canadian border into northern Baja California, and from the Pacific Ocean to the Rocky Mountains.
CAISO plans to become the RC for California and Baja California on July 1. BC Hydro will become the RC for most of British Columbia on Sept. 2. CAISO will then take over for many areas outside California on Nov. 1, while SPP will take responsibility for other parts of the West on Dec. 3.
The Oversight Committee had its first in-person meeting in March, when it elected its chair, Michelle Cathcart, vice president of transmission system operations with the Bonneville Power Administration, and vice chair, Steve Cobb, director of transmission and generation operations at Arizona’s Salt River Project. (See CAISO RC Oversight Committee Elects Leaders.)
The committee plans to meet monthly throughout 2019. Its members represent the transmission owners and balancing authorities in RC West.
At Tuesday’s meeting, Cathcart led a discussion about the possibility that WECC might revive its former RC operating committee and play a role in coordinating functions between the West’s three new RCs. The proposal is in an early stage, she said.
The plan didn’t appear to generate much enthusiasm among committee members, Cathcart noted. “I’m not hearing a lot of excitement in this room,” she said.
RENSSELAER, N.Y. — NYISO’s Management Committee on Monday recommended that the Board of Directors approve a Comprehensive Reliability Plan (CRP) that identified no reliability needs over the coming decade but did point to risks that could develop over the period.
NYISO Senior Manager for Reliability Planning Kevin DePugh presented a summary of the 2019-2028 plan, which included a scenario on the reliability impacts of proposed environmental regulations on 3,300 MW of peaking units, predominantly in New York City (Zone J) and Long Island (Zone K).
The state’s Department of Environmental Conservation earlier this year proposed to lower allowable NOx emissions from simple cycle and regenerative combustion turbines (SCCTs) during the ozone season, beginning May 1, 2023. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)
| PSEG Long Island
NYISO, Consolidated Edison and PSEG Long Island said losing all the peakers without replacement resources or system reinforcements would threaten reliability in pockets in New York City, Long Island and southeast New York.
“Starting in 2023, with the first implementation phase of the rule, pockets in New York City would be deficient of supply for up to 14 hours in a given day at a peak amount of 240 MW, while pockets in Long Island would be deficient 320 MW possibly for 15 hours in a given day. With full implementation of the peaker rule assumed in 2025, the New York system as a whole would significantly exceed the probability of one loss-of-load event in 10 years due to a supply deficiency of at least 700 MW in southeast New York,” the report said.
“One thing generators will have to do by [March 2020] is put in compliance plans, and if they plan on closing a plant, they would have to submit a deactivation notice to the ISO,” DePugh said.
If NYISO can prove the loss of such a unit will create a reliability need for which it can find no alternative solution, it can get a two-year extension to keep the unit online, followed by an additional two years if necessary, DePugh said.
Working with Con Ed, the Long Island Power Authority and PSEG LI, the ISO found at least 700 MW of capacity needed in Zones J and K to meet loss-of-load expectation criterion, assuming the state’s AC Transmission projects are completed on schedule by December 2023. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)
Local transmission alone cannot fully solve the needs, and upgrading the transmission path from UPNY-SENY into Zones J and K would likely bring the New York Control Area at or only marginally below the LOLE criterion, the report said. It would not address the local transmission constraints identified in J and K.
“The solutions could be a mix and match of different things,” DePugh said, including a combination of local transmission, resource additions and load reductions.
MMU Recommendations
Pallas LeeVanSchaick of the Market Monitoring Unit reviewed the CRP, as required by the Tariff, and confirmed that transmission security and resource adequacy needs could arise if a number of plants retire.
“There are really six load pockets, three in New York City and three on Long Island, where additional resources would be needed,” LeeVanSchaick said.
The CRP found the violations could be avoided through a variety of solutions, including by retaining 1,280 MW of peaking capacity in specific areas.
Chart shows the expected retirement timelines for various peaking units across New York. | NYISO
The MMU recommends NYISO adopt three significant market reforms, starting with modeling in the day-ahead and real-time markets Long Island transmission constraints — which the ISO currently manages with out-of-market actions — and developing mitigation measures to address them.
“A lot of congestion on Long Island is managed outside the market, which doesn’t provide much transparency about congestion bottlenecks or incentives for investment,” LeeVanSchaick said. “There are certain areas where it is less expensive to build generation than other areas, so price signals have to be adequate to attract investment where it is needed for reliability.”
The Monitor also recommends the ISO model local reserve requirements in New York City load pockets and consider rules for efficient pricing and settlement when operating reserve providers also provide congestion relief benefits.
NYISO-PJM JOA Revisions
The MC approved revisions to NYISO and PJM’s Joint Operating Agreement, as recommended by the Business Issues Committee. The revisions will go to the ISO’s board in June ahead of a joint FERC filing.
Under the changes, the determination of redispatch settlements would exclude several flowgates, said Cameron McPherson, the ISO’s operations analysis and services analyst.
FERC last September granted a one-year waiver of the JOA to permit the addition of the East Towanda-Hillside tie line as a market-to-market (M2M) flowgate. (See “NYISO, PJM Revising JOA for Tie Line Issues,” NYISO Business Issues Committee Briefs: March 13, 2019.)
The proposed JOA revisions were developed to address the concern raised in the waiver request and to improve other components of the M2M coordination process — in particular, the rules for performing entitlement calculations.
New External SRE Penalty
The MC also approved a new external supplemental resource evaluation (SRE) penalty regime that would boost the ISO’s ability to call on external resources that have sold capacity to New York. The changes, approved by the BIC in April, will take effect in the third quarter.
Amanda Carney, NYISO capacity market design specialist, presented the proposal and said all external capacity suppliers required to offer their energy at an external proxy must bid at the offer floor, be operating and available, and flow the scheduled transaction.
Any external capacity supplier that fails to meet the criteria will be subject to the penalty, which is equal to 1.5 times the applicable spot price multiplied by the number of megawatts of shortfall and the percentage of the SRE call hours in which a supplier fails to respond.
Howard Fromer, director of market policy for PSEG Power New York, said he hoped that NYISO would include in its FERC filing a mention of stakeholder concerns about being scrutinized for performing the bidding “gymnastics” called for under the proposed penalty scheme.
LeeVanSchaick said the Monitor is aware of those stakeholder concerns and that the ISO would mention them in the filing.
Under the new penalty provisions, the ISO will calculate deficiencies monthly, using the total number of SRE call hours in a given month that the resource could be online for and the total number of megawatts of shortfall in that month, Carney said.
Collateral Change for Foreign Market Participants
The MC on Monday approved a Tariff change restricting the posting of cash collateral to entities based in the U.S. and Canada.
The changes affect only four market participants, said Sheri Prevratil, manager of corporate credit.
Market participants that do not meet Tariff requirements for unsecured credit must post cash, letters of credit or surety bonds as collateral.
In the event of a bankruptcy, the ISO’s ability to retain a company’s cash collateral is dependent on applicable bankruptcy laws. Given the potential number of jurisdictions at issue worldwide, it is not feasible for the ISO to evaluate laws in all jurisdictions to ensure its interest in cash collateral would be adequately protected, Prevratil said.
The board will consider the measure in June ahead of a planned FERC filing.
FERC has agreed to New England’s request for a public “prefiling” meeting to discuss the region’s plans for long-term fuel security.
The staff-led session at FERC’s headquarters in D.C. on July 15 will include three, 90-minute presentations by ISO-NE, New England Power Pool stakeholders and state officials followed by questions from commissioners and staff (EL18-182, ER18-2364, et. al.).
ISO-NE, NEPOOL and the New England States Committee on Electricity (NESCOE) jointly requested the meeting in April, saying ex parte rules had prevented them from discussing with the commission their efforts to develop a long-term, market-based energy security plan, as the commission ordered last July. ISO-NE’s proposed Tariff revisions are due Oct. 15. (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)
“The solutions and alternatives under consideration are complex,” the request said. “It would be particularly helpful if the region can preview its proposals and issues with commission staff, both to assist the commission’s understanding of the issues and to receive any preliminary feedback and direction.”
Distrigas Terminal at sunset | Everett Chamber of Commerce
The commission’s July 2 show-cause order instituted a Federal Power Act Section 206 proceeding after finding that ISO-NE’s Tariff is not just and reasonable because the RTO lacks a way to address fuel security concerns that it said could result in reliability violations as soon as 2022.
ISO-NE last month issued a white paper on the challenges the region faces because of its increasing reliance on natural gas-fired generation — which may be unable to obtain fuel in the winter — and intermittent renewables. The paper said ISO-NE’s efforts to encourage gas-fired generators to invest in dual-fuel capability or LNG storage had proven inadequate because of “misaligned incentives.”
“Making these discrete investments, if they meaningfully reduce the risk of electricity supply shortages (and therefore the risk of high prices), entails up-front costs to the generator — yet reduce the energy market price the generator receives,” the RTO explained.
As a result, the RTO is proposing:
Expanding the one-day-ahead market into a multiday-ahead market that optimizes energy (including stored fuel) over several days.
Creating new ancillary services in the day-ahead market to compensate generators for providing the flexibility of energy “on demand” to manage uncertainties during the operating day.
Creating a seasonal forward market to provide resources with incentives to invest in supplemental fuel supplies for the winter.
The paper said the RTO is “in the early, conceptual stages of evaluating designs” for the forward market and that its “immediate focus is to first work with regional stakeholders to develop the … multiday-ahead markets and their integrated new ancillary services.”
RTO officials discussed the multiday-ahead proposal with stakeholders at NEPOOL’s Markets Committee meeting May 7.
VALLEY FORGE, Pa. — PJM’s existing Market Efficiency Process Enhancement Task Force will tackle concerns raised by the Independent Market Monitor over its benefit-cost analyses for transmission projects.
PJM Director of Infrastructure Planning Sue Glatz told the Planning Committee on Thursday that staff agreed the issues raised in the Monitor’s problem statement last month would be best addressed in the task force’s third phase. (See “Revisit Benefit-cost Analysis, Monitor Says,” PJM PC/TEAC Briefs: April 11, 2019.) Glatz stood in for PC Chairman Ken Seiler.
The Monitor said last month that PJM’s current benefits calculation ignores increased congestion in all zones resulting from a transmission project. Specifically, the benefit-cost analysis does not account for the fact that transmission project costs are not subject to cost caps and may exceed estimated costs by a wide margin. When actual costs exceed estimated costs, the benefit-cost analysis is effectively meaningless, and low estimated costs may result in inappropriately favoring transmission projects over market generation projects or the option of no project at all, the Monitor said.
Side-by-side comparison of estimated project costs. The bars represent the possible spectrum of cost for each project, with the bottom of the bar representing the project sponsor’s cost estimate and the top point indicating an independent consultant’s estimates. | PJM
Generation Interconnection Requests Update
PJM proposed revisions to its generation interconnection requests process, as detailed in Manual 14G.
Lisa Krizenoskas, PJM senior engineer, said the first proposed change expands rules for demand response found in section 1.7. Staff propose directing on-site generators used to reduce load that participate as DR to Manuals 11 and 18 for further guidelines, while requiring the portion of any such generator that injects power past the point of interconnection to follow the existing interconnection process outlined in Manual 14G.
PJM also proposes a site control term of three years — two years for projects of 20 MW or less — commencing on the first day of the new services queue in which the customer submits its request. Extensions must be exercised by the developer at the time site control evidence is given to PJM.
New Fee Structure for Cost Containment Needed
PJM said its reconfigured cost-containment process will charge developers a lot more money, even for projects valued at less than $20 million.
Mark Sims, PJM’s manager of infrastructure coordination, said the old tiered approach, approved in 2014, doesn’t account for the increased cost of the new comparison framework that involves independent consultant review and legal and financial analyses.
“A lot of work is going to be done in parallel, which is going to increase costs,” Sims said. “A lot of projects up to $100 million will need extensive analysis. That’s just the bottom line. We aren’t sure the existing fee structure is going to work.”
Currently, PJM charges nothing for cost-containment review of projects $20 million or less. Projects up to $100 million cost $5,000 to review and larger projects incur a $30,000 fee.
Sims said the expense of paying independent consultants for each individual project proposal could reach $50,000. He said staff are working to finalize a new fee structure to present to stakeholders in the coming months.
Aaron Berner, PJM’s manager of transmission planning, said proposed revisions to the Regional Transmission Expansion Plan process remain on track for a vote at the June Markets and Reliability Committee meeting.
LS Power proposed an amendment in January to Manual 14B that was slated for stakeholder endorsement at the April 25 MRC meeting. The proposal specifies that a transmission owner’s supplemental project “will generally be removed from the RTEP” following a final order by a state siting agency rejecting the project. Supplemental projects are proposed by TOs and are not required for compliance with PJM’s reliability, operational performance or economic criteria. (See “RTEP Removal Language Vote Deferred Again,” PJM MRC/MC Briefs: April 25, 2019.)
Berner said PJM asked stakeholders to submit feedback by today so staff can present revised manual language at the May 29 meeting.
Geomagnetic Disturbance Data Needed
PJM wants TOs to submit new or updated data on facilities susceptible to geomagnetic disturbance events as part of its ongoing effort to establish procedures in sync with NERC requirements.
Affected facilities are those that include high-power transformers with a high-side, wye-grounded winding with terminal voltage greater than 200 kV.
PJM wants the TO-supplied data by July 18 so that further analysis can be completed in 2020.
Dominion Supplementals
Dominion Energy submitted requests for supplemental projects during Thursday’s Transmission Expansion Advisory Committee meeting.
A Dominion customer wants to add a third 84-MVA distribution transformer at the Enterprise Substation in Loudoun County, Va. The new transformer is being driven by continued data center load growth and alternate feed contract reservations, with a requested in-service date of July 15, 2020.
In the same county, Dominion wants to add a fourth 84-MVA distribution transformer at the Poland Road Substation. The need is driven by continued load growth in the area and contingency loading for the loss of one of the existing transformers, with a requested in-service date of Dec. 31, 2021.
In Prince William County, Dominion requested a new substation to support a data center campus with a total load in excess of 100 MW, with a requested in-service date of Dec. 15, 2021.
Dominion also presented nine proposed solutions for requested supplementals at a total cost of $104.25 million.
American Electric Power presented a solution to one of its proposed supplemental projects for the Tanners Creek line in Indiana on Thursday.
AEP wants to spend $5.93 million installing two new 345-kV breakers to address faults on the connecting Dearborn line. A crew will move the existing M2 breaker into a new N string, allowing for the termination of the Dearborn line. A new 345-kV breaker will complete the T string.
Alternative solutions include reterminating the 345/138-kV transformer and 345-kV Dearborn line into existing breaker spots. Because of the way the station is laid out, this would require reconfiguring multiple 345-kV lines and would cost more, AEP said.
The revisions reflect industry standard updates from the Institute of Electrical and Electronics Engineers and will apply to all new projects approved after Jan. 1, 2012.
GOLDEN, Colo. — SPP staff last week shared a proposed “modification oversight process” with its Western reliability coordination customers, much to the glee of those involved.
Given the industry’s fondness for acronyms, there’s always room for one more: The process was tagged as “MOP.”
“Mop it up!” advised SPP Operations Vice President Bruce Rew as staffer Clint Savoy prepared to explain the process during a Friday conference call with the Western Reliability Executive Committee (WREC).
“That’s what we use to clean up stuff,” Savoy said.
MOP actually borrows from SPP’s existing revision-request process to provide a means of managing document modifications (modification responses, or MRs) related to the RTO’s Western RC services. Savoy said it applies to documentation established by SPP or its working groups that might affect operations or have a compliance or financial impact on its Western RC services customers.
“MRs identify which governing document or specific section requires a review and approval, and by which groups,” Savoy explained.
The process establishes submission timelines, how to submit and respond to comments, and guidelines for public posting. MOP incorporates the impact analysis and recommendation reports familiar to SPP’s Eastern members.
SPP said in September it had signed contracts to provide RC services to balancing authorities representing about 12% of Western Interconnection load, effective Dec. 3. Peak Reliability, which has been the West’s RC since 2011, is winding down operations by the end of the year. (See CAISO RC Wins Most of the West.)
The Western Reliability Working Group (WRWG), which reports to the WREC, debated the MOP during a May 14-15 meeting in the Rocky Mountains’ foothills. As the primary — and currently only — SPP working group in the West, the WRWG will be responsible for taking one of five actions on any MR: approve, reject, table, withdraw or refer.
The WREC will be the final authority and can take the same five actions, the lone exception being remanding — rather than referring — an MR back to the working group.
The WRWG was unable to reach consensus on whether the executive committee should see every MR the working group approves or just those that aren’t unanimous. Members were also unable to agree on how the WREC would revise an approved MR.
“My concern with the process is the time consideration,” said Black Hills Energy’s Denton McGregor, the WRWG chair. “But with 40 [stakeholder] groups in the East, SPP seems to be managing [the process].”
The WREC discussed the same issues during its conference call before voting to require that all items needing approval be sent to the committee. Its members also agreed they should provide guidance when remanding MRs back to the WRWG.
“We should tell them exactly what were the concerns that led to the turndown,” Rew said.
“I believe the WREC exists for a reason,” said WREC Chair Keith Carman, of Tri-State Generation and Transmission. “We don’t need a strong hand of approval, but simply having these items come to us provides value. It gives us the ability to be aware of things that are changing.”
The MOP has yet to be approved. SPP is still gathering comments from Western entities with plans to gain the WRWG’s approval in June. Savoy is scheduled to bring a final version for approval to the WREC in July.
RC Still Needs Data-sharing Agreement
Lack of a final data-sharing agreement appears to be the lone sticking point in SPP’s plans to extend RC services into the West.
Peak currently operates under a universal data-sharing agreement (UDSA) that gives operating entities access to key data necessary for reliable system operations and meets NERC standards. CAISO has used that agreement and revised it to create a Western Interconnection Data Sharing Agreement (WIDSA) that it will use moving forward, SPP staff said.
SPP conducts its business in the East under NERC’s operating reliability data (ORD) confidentiality agreement. It has worked with CAISO to add language to the WIDSA that allows non-signatories to see some of the data but hopes to have everything resolved before shadow operations start in October.
SPP’s Yasser Bahbaz said the WIDSA acknowledges the ORD. “We’re in a much better place than we were two months ago,” he said.
Elsewhere, SPP remains on track to meet the go-live date with progress on a several fronts:
The Congestion Management and Seams Task Force, one of three groups reporting to the WRWG, is developing a congestion management methodology that CAISO “can agree to as well,” Tri-State’s Michael Houglum said. “We’re getting close to this,” he said. “It’s already so much better than what we used to have [with Peak].”
SPP staff are testing its custom R-Comm messaging system with the Grid Messaging System (GMS) used by the Western Interconnection’s other RC providers (the Alberta Electric System Operator, BC Hydro, Gridforce and CAISO). SPP and CAISO have also created a communication protocol whereby neighboring balancing authorities and transmission owners that lie across the seam can send messages using GMS or R-Comm, depending on their RC. SPP is also setting up an application programming interface (API) that will further enable messaging with CAISO.
Staff said SPP will register as SPPW in the North American Energy Standards Board’s electric industry registry (EIR), effective Dec. 3. This will require SPP’s Western RC entities to designate the RTO as their RC before Dec. 21, when Peak plans to pull its EIR registration. Software developer OATI administers the web-based tool, which collects e-tags from registered entities that feed into the unscheduled flow mitigation plan.
SPP has completed site visits with all the Western entities, helping increase the RTO’s familiarity with the region. “It gives us an appreciation for how they do things in the West,” Bahbaz said. The RTO will welcome visitors to its Little Rock, Ark., headquarters in the fall.
An East-West system model is expected to go into production in July using a Western model based on a Peak model published earlier this year.
SPP has been holding monthly calls with training representatives in the Western footprint. Operator training begins in September. Staff are discussing with CAISO restoration training in 2020.
Three major deadlines loom: the Sept. 1 completion of on-site RC certification, the Oct. 1 commencement of shadow operations with adjacent RCs and the Dec. 3 go-live to begin providing RC services.
SPP’s Reliability Plan Confidential, but…
Bahbaz told the WRWG that SPP’s reliability plan includes both its Eastern and Western footprints and should “hopefully meet the need of anyone interested in SPP procedures.”
However, those interested in SPP procedures will have to travel to Little Rock to view the plan.
“The plan has steps specific to SPP’s system, and SPP believes those are confidential to SPP,” Bahbaz said. “We will show the procedures to anyone who comes to [our] control room.”
“We can follow directions just fine,” Houglum said. “It helps everybody’s knowledge if we understand why you’re asking us to do certain things in certain instances. Any background information we have allows us to execute those decisions better.”
Working Group Revises its Charter
The WRWG made several changes to its charter, adding clarity to term limits for the group’s leadership and its voting structure.
Members agreed to limit the chair and vice chair to two-year terms, with the initial term beginning in January 2019. Elections will be held at the end of the calendar year. Should one of the positions become vacant before the term expires, a special election will be conducted during the next regularly scheduled meeting.
The WRWG also revised the charter to include the use of a simple majority (greater than but not equal to 50%) of those present and voting to determine motion outcomes.
“SPP wants engagement,” McGregor said. “You need to be present and take part if you want your voice heard.”
Other charter revisions eliminated the need to reach a unanimous decision before requesting feedback from the WREC and added the ability to review and approve or reject revisions to applicable documents in accordance with the MOP, and to provide recommendations and escalate to the WREC items requiring financial consideration.
WRWG Members: Coordinating Communication Helpful
Working group members found the discussion beneficial, even if they did spend considerable time trying to determine whether abstentions count against a unanimous vote. “An abstention is not a vote,” said Colorado Springs Utilities’ Warren Rust, stating the group’s consensus position.
“This is all related to coordinating and communicating activities,” McGregor said. “There are a lot of moving parts and pieces to everything, not just with SPP, but here in the West. This keeps us informed.”
“Oh yes, this is helpful, just having come and hearing the discussion,” said Linda Jacobson-Quinn of Farmington Electric Utility System in New Mexico. “It’s the good old theory that if there were no communication at all, we wouldn’t be able to build the things we need in order to ensure reliability.”
Savoy, SPP’s senior interregional coordinator, said the RTO’s significant progress in offering RC services to the West is “a direct result of the engagement of stakeholder groups.”
“I think the representatives all agree that our collective success is dependent on solidifying relationships and promoting collaboration between entities,” he said. “That’s where SPP believes we provide significant value to our stakeholders.”
FERC on Thursday terminated its investigations into the tax calculations included in transmission rates after several MISO transmission owners made compliance filings to remove a two-step averaging methodology that could inflate rates by underestimating tax credits.
The commission accepted compliance filings in part for MISO TOs ALLETE, Montana-Dakota Utilities, Northern Indiana Public Service Co., Otter Tail Power and Southern Indiana Gas & Electric (EL18-138), as well as American Transmission Co. (EL18-157) and International Transmission Co. (EL18-159). It also fully approved filings submitted by CAISO TOs GridLiance West (EL18-158) and Southern California Edison (EL18-164).
All the TOs proposed to end the use of a double averaging formula to calculate accumulated deferred income taxes (ADIT).
Some MISO TOs were using a two-step averaging methodology in their projected test year calculations of ADIT balances, but FERC said the practice makes deferred income tax credits appear lower than they should be, possibly raising rates because averaging the prorated ADIT value for the year with the beginning-of-year ADIT balance “produces a result that is disproportionately skewed towards the beginning-of-year balance.” (See FERC Broadens Challenge to TOs’ Tax Calculations.)
FERC got a bit more than it bargained for when the MISO TOs submitted compliance filings that also revised their annual ADIT true-up calculations.
The commission rejected the MISO TOs’ proposed revisions to apply the IRS’ proration methodology to their annual true-up calculations, saying the effort was beyond the scope of compliance.
“The filing parties’ proposal to prorate certain MISO TOs’ annual true-up calculations is not necessary to comply with the remedy … and is thus outside the scope of this compliance proceeding,” FERC said.
It directed the TOs to make further compliance filings that include the revised ADIT calculations, this time leaving out “any other modifications or revisions.”
The commission said if the TOs still want to revise their transmission formula rates to apply the proration methodology in their true-up calculations, they could make separate filings for FERC review.
METC Filing Rejected
In a proceeding separate from the other MISO TOs, Michigan Electric Transmission Co. (METC) failed to earn FERC’s stamp of approval over its attempt to address the ADIT issue (EL19-16). In that order, the commission said that while METC’s proposed removal of two-step averaging complied with FERC’s directive, the company’s request to include the IRS’ proration methodology in its true-up calculations for all of 2019 amounted to retroactive ratemaking because the company had submitted its filing on Jan. 22.
“Although we are rejecting METC’s filing, we note that it may refile its proposal to apply the IRS’ proration methodology to its true-up calculations, provided that its proposed revisions apply prospectively, in a separate [Federal Power Act Section] 205 filing. The commission will evaluate the proposal at that time,” FERC said.
VALLEY FORGE, Pa. — PJM asked for stakeholder feedback last week about how to reshape its gas pipeline contingency plan, three months after FERC turned it down for lacking specificity and clarity.
“We talked with FERC staff to get a read on what they want to see in a new proposal,” Thomas DeVita, PJM senior counsel, told the Market Implementation Committee on Wednesday. “We got an insight to their thinking. … The key point is the commission wants to see a meeting of the minds between generators and pipelines.”
On Feb. 19, FERC rejected the stakeholder-approved mechanism that would have implemented a process for market sellers seeking cost recovery for certain gas contingencies associated with the RTO’s instruction to temporarily switch to an alternative fuel or alternative fuel source because of pipeline breaks or the loss of compressor stations (ER19-664). The proposal included nine cost categories of switching costs, including park-and-loan service charges and overrun charges.
The commission said PJM’s definition of penalty was “unreasonably narrow and unsupported” because pipeline tariffs delineate between penalties and fuel-switching costs in different ways, meaning what appears to be an appropriate cost for one pipeline could be considered a penalty for another. FERC also faulted PJM for not including events that might trigger fuel-switching directives in its Tariff and for lacking procedures for dealing with such contingencies through the Capacity Performance market design. (See FERC Rejects PJM’s Gas Contingency Pipeline Proposal.)
DeVita said commission staff discouraged PJM from submitting an itemized list of switching costs, as it did in the first filing, and instead focus on procedures surrounding “explicit authorization” to switch between pipelines and any new limitations on the amount of gas burned after the switch occurs. Rich Brown, manager of PJM’s system operator training, said FERC’s focus on authorization and fuel burned reflects the commission’s insistence on ensuring reliability is maintained during any switch.
David “Scarp” Scarpignato of Calpine said that approach would not protect his company’s interests.
“I’m not comfortable that we just leave it open and send it to FERC with no guidance on what’s a coverable cost and what’s not,” he said. “Just getting over the hurdle of notice is not enough to give us confidence that our costs will be recovered.”
In a January filing with FERC, Duke Energy and East Kentucky Power Cooperative said they generally supported the idea of compensating generators for switching fuels, but they worried that PJM’s enumerated categories didn’t capture all the possible costs. Without an exhaustive list, they said, generators lacked financial incentive to make the switch or the ability to recoup expenses after-the-fact.
Marji Philips, Direct Energy’s director of RTO and federal services, told the MIC that if generators know PJM will order the switch — instead of generators making the call themselves — the cost of fuel switching is transferred to customers instead. The filing isn’t clear as to whether generators who can’t perform will incur CP penalties, either, she said.
“This is so fundamentally flawed,” Philips said. “It is not pipelines that do the switching. It’s whoever owns the capacity on the pipeline. We need to rethink this and reframe how we think about this.”
The Independent Market Monitor and the PJM Industrial Customer Coalition further alleged that the RTO’s gas-electric coordination remains an information-sharing process, therefore PJM can’t give operational instructions to pipelines. Moving customers with firm contracts off some pipelines — while others with lower levels of service remain unaffected — may discourage the former group of market sellers from taking proper steps to obtain reliable back-up fuel sources, they said.
The D.C. Office of the People’s Counsel crafted the Operating Agreement and Tariff changes detailed in the rejected filing after earning a majority of stakeholder support at the December meeting of the Markets and Reliability Committee.
The supermajority vote was a victory for load interests who opposed a Calpine-authored plan endorsed at the MIC in November. That proposal would have developed a formula for cost recovery to be filed with FERC that did not include pipeline penalties.
Although ongoing services generally include cost recovery formulas, DeVita said FERC may interpret the “rare” event of generators seeking fuel-switching reimbursement as incomparable.
“We are very concerned about cost to load,” said Adrien Ford of Old Dominion Electric Cooperative. “We are also very concerned about generators mitigating their own risk. We are in no man’s land now.”
WASHINGTON — FERC on Thursday officially rescinded its controversial policy of allowing its Office of Enforcement to publicly disclose its investigations of possible misconduct and their subjects’ identities, ending a practice in place since 2011 (PL10-2-003).
The commission in 2009 authorized Enforcement to issue a Notice of Alleged Violations (NAV) after the subject of an investigation had the opportunity to respond to the office’s preliminary findings. Enforcement issued its first five NAVs on Jan. 25, 2011, four of which dealt with alleged market manipulation in ISO-NE’s Day-Ahead Load Response Program.
NAVs, however, were not like indictments: They were issued before Enforcement staff had finished their investigations and reached their conclusions in the case. Prior to 2011, the commission only disclosed the existence of an investigation and its subjects’ identities when it approved the issuance of an Order to Show Cause (OSC). NAVs also did not need to be approved by the commission itself; instead, they were issued after approval from the director of enforcement.
FERC said it had “acknowledged the potential risk of reputational harm that might result from the issuance of a NAV but sought to strike a balance between protecting the confidentiality of investigations and promoting the public interest of heightened transparency.”
But the commission found that issuing NAVs generated little information for Enforcement’s investigations. And since the policy’s adoption, the commission found that other sources, such as data provided by RTOs under Order 760, have been more useful.
“Accordingly, the commission finds that the potential adverse consequences that NAVs pose for investigative subjects are no longer justified in light of the limited transparency NAVs have generated and the more effective, alternative means of adding transparency that the commission has developed since the NAV order.” These means include providing guidance through orders on settlement agreements, OSCs and orders assessing civil penalties.
At FERC’s open meeting Thursday, Commissioner Richard Glick said the policy had been unofficially ended for some time. Indeed, the last time Enforcement issued a NAV was in April 2018, the only one that year. (See FERC Investigation Shows PSEG Violated PJM Bidding Rules.) Prior to that, the office on average issued seven to eight per year.
While Glick acknowledged that NAVs had provided limited value, and joined in the unanimous vote to end the practice, he said that “the Office of Enforcement must act aggressively when there is evidence of market manipulation or other malfeasance that could adversely impact our jurisdictional markets, and I intend to review any future proposals affecting Enforcement’s role with that in mind.”
Asked by reporters after the meeting whether the commission was considering any other changes to Enforcement policies, Chairman Neil Chatterjee declined to comment.
WASHINGTON — FERC voted 3-1 on Thursday to approve the construction of a fourth liquefaction unit at the Freeport LNG export terminal in Brazoria County, Texas (CP17-470).
The unit, called a “train” in the LNG industry, will allow for the export of an additional 5.1 million metric tons per annum (mtpa), equivalent to about 0.74 Bcfd. Currently, the facility has a capacity of 15.49 mtpa (2.14 Bcfd), according to FERC.
The approval of the so-called Train 4 Project marks FERC’s fourth approval of an LNG project this year, following last month’s approval of the Driftwood and Port Arthur projects, and February’s approval of the Venture Global Calcasieu Pass project. And as has become common, the order elicited celebration from Chairman Neil Chatterjee, a reluctant concurrence from Commissioner Cheryl LaFleur and a dissent from Commissioner Richard Glick over the commission’s reticence to assess the project’s impacts on global climate change.
“I’m proud of the efforts by the commission and its staff to process today’s and our previous LNG orders,” Chatterjee said in a statement. “Exporting LNG from the United States can help increase the availability of inexpensive, clean-burning fuel to our global allies who are looking for an efficient, affordable and environmentally friendly source of generation.”
Freeport LNG export terminal | Freeport LNG Development
FERC disclosed in its order that its environmental assessment (EA) of Train 4 estimated that operation of the project may result in emissions of up to 491,500 metric tons per year of carbon dioxide equivalent, increasing national emissions by about 0.01%. “Currently, there are no national targets to use as benchmarks for comparison,” the commission said.
This was enough to secure LaFleur’s vote, though she warned that the order, as with previous LNG approvals, are vulnerable to judicial scrutiny. She also noted that an additional risk existed for Train 4 because the commission issued an EA instead of an environmental impact statement (EIS). Under the National Environmental Policy Act, federal agencies issue an EIS when they find that an action will have a significant impact on the environment.
“This tension between the finding of no significant impact, and the commission’s failure to assess significance of climate change impacts, heightens the risk that a court could vacate and remand this project, simply on the basis of which environmental document was prepared,” LaFleur said in her concurrence.
At Thursday’s meeting, Glick noted that Chatterjee has said that the Natural Gas Act doesn’t give the commission authority to analyze the impact of natural gas infrastructure on climate change. He then turned and appealed directly to Chatterjee, suggesting that they “work together to send some draft legislation to Congress to fix the problem and clarify that FERC does have such authority.”
Asked by reporters about Glick’s remarks after the meeting, Chatterjee dismissed the idea, saying “there is a 0% chance that such legislation could get through the United States Senate. We have so many things to focus on, that to me is not a worthwhile thing to spend time on.”
Commissioner Bernard McNamee said the approval was “another great achievement.” He emphasized “that we have considered all the environmental effects, including greenhouse gases. I know there’s a disagreement about … how those should be measured. … But a disagreement about that does not mean they were not considered.”
Refunds appear imminent in a three-year dispute over MISO and PJM’s past practice of double-charging pseudo-tied generation for congestion fees after FERC last week ordered settlement proceedings to determine how much the RTOs must remit to address the redundant costs incurred from 2016 onward (EL16-108).
The issue stretches back three years to when Tilton Energy lodged a complaint against the RTOs for assessing overlapping congestion charges on pseudo-tied resources. American Municipal Power, Northern Illinois Municipal Power Agency, Dynegy and Illinois Power Marketing soon filed similar complaints. FERC consolidated the proceedings.
The RTOs introduced a temporary rebate program in 2017, then began including pseudo-ties in the day-ahead scheduling process in 2018 to end redundant congestion costs. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.) In March, MISO got FERC approval for a second piece of the solution, where participants with pseudo-tied resources can use the day-ahead market to hedge against real-time congestion.
In its order, FERC noted that it has already accepted two filings apiece from MISO and PJM to address overlapping charges and has since discovered that those proposals have eliminated the congestion overlap. But those corrections come too late for the transmission customers already assessed those charges, FERC said.
“We find that the potential for overlapping or duplicative charges for congestion existed prior to the effective dates of the revisions,” the commission said.
As such, FERC established settlement procedures to determine the appropriate refunds owed to owners of pseudo-tied generation. The commission said if the involved parties don’t settle, a settlement judge will decide the case by May 18, 2020. FERC set a refund effective date of Aug. 25, 2016.
FERC: MISO Congestion and Admin Charges Appropriate
However, the refunds will not include the costs of MISO’s non-duplicative congestion and administrative charges that Tilton also challenged.
Tilton claimed MISO violated its Tariff by erroneously using financial schedules to assess charges on pseudo-tied generation, arguing the schedules are meant to represent contracts between two market participants and that the RTO is not a counterparty to the pseudo-tie transactions.
The company said MISO circumvented a Tariff provision and implemented Business Practices Manual language when it used its financial schedules to record transmission transactions for pseudo-tied generation “despite the nonexistence of a bilateral transaction that is a prerequisite for the use of a financial schedule.”
Tilton also argued that MISO’s assessment of real-time congestion costs against generation pseudo-tied from MISO to PJM is improper because the charges cannot be hedged and are “inconsistent with market fundamentals.” The company asked FERC to put a stop to MISO’s assessment of congestion and administrative charges.
In response, MISO argued that Tilton failed to show the RTO was acting counter to its Tariff and said the complaint should be thrown out. It also said Tilton failed to initiate dispute resolution procedures prior to filing the complaint, a break with commission precedent.
“Although Tilton has purchased long-term firm transmission service from MISO to PJM, paying for transmission service does not exempt Tilton from paying for congestion and losses,” the RTO explained.
The commission sided with MISO, ruling that Tilton must pay to use the RTO’s system.
“We conclude that MISO’s assessment of congestion costs and administrative charges on Tilton does not violate the MISO Tariff. Specifically … we find that the MISO Tariff authorizes MISO to assess congestion costs and administrative charges on pseudo-tie transactions. We also find that it was not a violation of the MISO Tariff for MISO to use financial schedules as a vehicle for imposing congestion and administration charges on Tilton,” FERC said.
The commission pointed out Tilton is a MISO transmission customer taking transmission service “to facilitate its pseudo-tie transactions” and is thus required to pay applicable charges.
Pseudo-tie transactions that use the the RTO’s system nevertheless contribute to its real-time congestion, FERC added.
