What to Do When ACE Conflicts with Interconnection Frequency?
By Rich Heidorn Jr.
The NERC Standards Committee on Wednesday postponed action on Arizona Public Service’s request to amend BAL-002-3 (Disturbance Control Standard — Contingency reserve for recovery from a balancing contingency event) after several members said they wanted to add the technical justification for its rejection to the record.
APS’ standards authorization request (SAR) proposed that compliance with BAL-002-2 requirement R1 would be reached once interconnection frequency has recovered, saying the change was needed to prevent the recovery of one event from contributing to the creation of another event.
Asked by the SC to provide a technical review, the Operating Committee in March recommended rejection of the SAR, citing advice from its the Resources Subcommittee (RS). “The recommended modification of R1.1 of this standard to include interconnection frequency assessment will modify the original intent of [the] standard, which is the demonstration of the deployment of reserves to recover from reportable balancing contingency events (RBCEs),” the OC said, adding, “The concerns raised in this SAR can be addressed by other means.”
Arizona Public Service raised questions about how balancing authorities should react when their area control error (ACE) is at odds with an interconnection’s frequency. | Arizona Public Service
Sean Bodkin, NERC compliance policy manager for Dominion Resources Services, asked for the delay, saying the technical reasons for the rejection should be added to the record. Other committee members also sought additional information on the “other means” cited by the OC.
“I’m not a BAL expert, but it looked like [APS] had a legitimate concern,” said Steve Rueckert, director of standards for the Western Electricity Coordinating Council.
Duke Energy Carolinas’ Tom Pruitt, chair of the RS, said there are simpler and more effective solutions to the situation identified by APS.
“There is an option to go through compliance guidance and develop a compliance guidance document. … There is an option for a BA [balancing authority] with the existing standard to simply execute an emergency assistance agreement with one of its neighbors for this situation. No modification of the standard at all is needed…
“The bottom line is, [under the SAR,] the BA would be exempt from balancing his BA area and that goes right to the heart of the job of a balancing authority,” Pruitt continued. “If he’s not required to balance his BA, we’re missing the boat here.”
Gary Nolan, an APS regulatory compliance adviser who wrote the SAR, told the SC there were “some differences of opinion and some misunderstandings” of his company’s concerns.
APS was not seeking to have a BA shirk its responsibilities, he said, but attempting to draw attention to a situation in which a BA’s area control error (ACE) is low while the interconnection frequency is high.
“BAL-001 R2 has a balancing authority … responding to what the interconnection needs as opposed to what the balancing authority needs. … When [interconnection] frequency is high, a balancing authority is asked not to correct their ACE and make frequency worse but rather to — if their ACE is low, it’s okay for them to remain low if [interconnection] frequency is high,” he explained.
Nolan said BAL-002 could be read to direct a BA in that situation to “increase their generation — or possibly, if it gets to a point where they’re very near to the deadline, they may need to shed load in order to recover their ACE in time. … Shedding load should be something we would be abhorrent to and not want to do. … That’s not going to help the interconnection … when frequency is high.”
“I get it, and I can see where there’s an issue,” Rueckert responded. “But we need to remember that the Standards Committee is not a technical committee; we’re kind of a process committee, and I don’t know that we should be making a decision on this SAR on technical terms. I think that is the RS and the OC.”
Bodkin agreed. “I know I am completely unqualified to make any technical justification on the BAL standards and that’s the reason I actually wanted to see the technical information from the RS in the record.”
Revised Standards Grading Tool Approved
The SC also approved a revised Standards Grading Spreadsheet for the Periodic Review Standing Review Team to use in evaluating standards’ requirements.
A working group formed last September revised ambiguous questions; eliminated duplicate questions; converted multipart questions into single questions; and added a reference section linking to source documents. It is the first update of the tool since its development in 2016.
However, the tool won’t get used immediately because of the decision to suspend the review team’s work until next year to avoid conflicts with the Standards Efficiency Review. (See “Standards Grading Process on ‘Pause,’” NERC Standards Committee Briefs: March 20, 2019.)
Minnesota’s Xcel Energy is aiming to be coal-free by 2030, supported by extending service of its nuclear plant and using more natural gas-fired generation, the utility announced Monday.
The company announced that it will close its two remaining coal plants a decade earlier than originally scheduled but extend operation of the Monticello Nuclear Generating Plant on the Mississippi River into 2040, 10 years after the plant’s current license expires. The nuclear extension will require both state and federal approvals.
The 511-MW Allen S. King Generating Station near the Twin Cities will close in 2028, while the 876-MW Sherco III unit of the Sherburne County (Sherco) Generating Station will close in 2030, Xcel said in a press release. The company has already said it will shutter the 680-MW Sherco I and 682-MW Sherco II in 2023 and 2026, respectively. It plans to build a new natural gas plant on the Sherco site.
Sherco Generating Station | Xcel Energy
The announcement comes as Xcel comes closer to securing the purchase of the gas-fired Mankato Energy Center from Southern Co. for about $650 million — a move originally opposed by the Sierra Club, which removed its comments in opposition after Xcel’s Monday announcement (18-702).
The company said the changes will take place while it triples its renewable portfolio, with plans to add 1,850 MW of wind by 2022 and about 3,000 MW of new solar by 2030.
Xcel said the acceleration of eliminating coal dependence “is another milestone in the company’s clean energy transition.”
The company will submit the retirement proposals, included in its 15-year resource plan, to the Minnesota Public Utilities Commission on July 1. The company has said it plans to reduce carbon emissions to 80% below 2005 levels by 2030 and go completely carbon-free in 2050.
“This is a significant step forward as we are on track to reduce carbon emissions by more than 80% by 2030 and transform the way we deliver energy to our customers,” said Chris Clark, president of Xcel Energy in Minnesota, North Dakota and South Dakota.
After the Xcel retirements, Minnesota will be left with just one coal plant, Minnesota Power’s 1,000-MW Boswell power plant in Cohasset.
Xcel’s move also comes after Minnesota Gov. Tim Walz announced in March that the state would strive to use 100% clean energy by 2050, joining Wisconsin, which has a similar goal. The company joins a spate of MISO member companies that have pledged to go coal-free or carbon-free, including MidAmerican Energy, DTE Energy, Consumers Energy and Southern Co. Other MISO companies have deep carbon-reduction goals, including American Electric Power, Alliant Energy, Ameren, NextEra Energy and WEC Energy Group.
As a result, some MISO organizations and companies have asked the RTO to better account for significant renewable goals or decarbonization commitments in its transmission planning. (See MISO Going Back to the Futures for MTEP 20.)
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.
Landowners united against a proposed transmission project straddling the Pennsylvania-Maryland border said on Monday they doubt an alternate plan using existing lines may cost an extra $94 million, as PJM suggests.
“I don’t see how that’s possible that by using existing infrastructure that it could be more expensive,” said Barron Shaw, spokesperson for Citizens to Stop Transource. “It’s hard to understand.”
Shaw’s group includes residents from Pennsylvania’s York and Franklin counties and Maryland’s Harford County, where Transource Energy plans to construct two 230-kV double-circuit lines totaling about 42 miles, known as the Independence Energy Connection (IEC) project. PJM selected the $372 million proposal — its largest market efficiency project to date — during the 2013/14 long-term planning window to address congestion in the AP South interface and has five times since reviewed its benefits to the grid, determining in each round that the IEC remains the most effective way to reduce load costs.
Once referred to as the AP South Congestion Improvement Project, Transource’s Independence Energy Connection project would consist of two lines. The western portion would run from the Ringgold substation in Maryland to the Rice substation in Pennsylvania. The eastern line would run from the Conastone station in Maryland to the Furnace Run station in Pennsylvania. | Transource
In testimony submitted to the Maryland Public Service Commission on May 8, PJM’s Tim Horger said the RTO’s most recent analysis, completed in February, determined the IEC would generate a $931 million reduction in congestion costs over the next 15 years, with a benefit-cost ratio of 2.17 — well above PJM’s 1.25 threshold required for inclusion in its Regional Transmission Expansion Plan.
Protesters argue, however, that the need for the eastern segment of the project could be met by the existing Furnace Run-Conastone and Furnace Run-Graceton 230-kV double-circuit transmission tower lines, which each have only one 230-kV circuit and could carry a second. Maryland’s Power Plant Research Program (PPRP) urged the PSC to suspend the project while PJM studied the market efficiency of this alternative and three others — a request that was granted in January. (See More Info Needed on Tx Line Options, MD PSC Says and Cancel Transource Line, Md. Panel Says.)
As requested, PJM analyzed PPRP’s four conceptual alternatives and determined all but its third option — adding lines to the Furnace Run-Conastone towers — created thermal violations too costly to even consider for its RTEP. Even still, to help the remaining plan survive its market efficiency process, PJM and Transource expanded the scope to add a third transformer at the Furnace Run station that would alleviate possible reliability violations. This modified plan was called 3A in PJM’s testimony.
Steve Herling, PJM’s vice president of transmission planning, said in testimony that the additional transformer caused the Peach Bottom-to-Furnace Run 500-kV lines to reach 98.5% of its thermal conductor limit following a single contingency. Conversely, the IEC takes significant power load off that line, Herling said, calling into question the viability of the proposed configuration in 3A.
PJM’s analysis showed 3A would cost between $54 million and $94 million more than IEC and produce $267 million less in congestion benefits to the region. Its benefit-cost ratio ranges from 1.39 to 1.52, still well above PJM’s 1.25 threshold but lagging far behind the IEC’s rating.
Herling said none of the conceptual alternatives proved “demonstrably superior” or even equal to the IEC plan. Jeff Shields, PJM spokesman, said Monday that staff stand by their testimony.
PSC hearings on the project begin in Maryland on June 3. Meanwhile, an administrative law judge in Pennsylvania will consider the IEC’s reliability benefits after the state Public Utility Commission overturned a prior dismissal of PJM testimony regarding the issue.
PPRP has described PJM’s attempt to justify the project on reliability grounds as a “bait and switch.” Although the project was not needed to address reliability violations when it was approved, the RTO said “that the project would inherently enhance system reliability by introducing additional transmission network paths.”
“Reliability means generator-deliverability reliability,” Shaw said. “It’s not about keeping people’s lights on.”
ISO-NE on Thursday proposed a “hybrid” filing Section 205 of the Federal Power Act to allow some generators to recover the costs of NERC critical infrastructure protection (CIP) requirements, but Eversource Energy suggested alternatives, saying it doesn’t want the costs collected as part of its transmission rates.
The RTO’s Jonathan Lowell made the proposal at a meeting of the New England Power Pool’s Transmission Committee on Thursday. It would allow cost recovery for generators designated by the RTO as “critical” to the determination of interconnection reliability operating limits (IROLs), which have higher CIP standards than other generators.
Violations of IROLs can lead to instability, uncontrolled separation and outages cascading into neighboring regions. Generators are designated as IROL-critical because of their characteristics and locations relative to other control areas, the RTO said.
ISO-NE says it has about as many IROLs as all other ISOs and RTOs together. “Because New England is at the eastern end of the Eastern Interconnection, a contingency in New England can have significant reliability impacts on systems to the west,” explained ISO-NE spokeswoman Marcia Blomberg. “Many interconnection reliability operating limits have been identified in New England to avoid creating those impacts, and many facilities have been determined to be critical to the determination of those limits.”
Eversource Energy told the NEPOOL Transmission Committee that the costs of generators’ compliance with NERC CIP requirements should not be recovered in transmission rates. | Eversource Energy
The RTO is proposing to make a Section 205 filing with FERC to add a new OATT Schedule 17 for the billing and collection of FERC-approved IROL-CIP costs, with the RTO serving as billing agent. It would be based on a formula rate template listing recurring and nonrecurring costs.
The initial filing will “facilitate a smooth and efficient FERC review of the Section 205 formula rate filing by having resolved most controversies in advance,” the RTO said in a presentation.
Critical generators and similarly situated transmission facilities would then make their own Section 205 filings itemizing their costs for FERC review and approval.
ISO-NE said the two-step filing is necessary because the RTO cannot be responsible for supporting the costs of individual facilities.
‘Inappropriate’
But Cal Bowie, representing Eversource, told the committee in a presentation that it is “inappropriate” for generators to recover expenses through regional network load transmission charges. “Transmission charges should primarily reflect the costs of building, operating, maintaining and ensuring the reliability of the transmission system,” Eversource said.
The company said the RTO should instead consider collecting the costs under its capacity load obligation (used to recover the “missing money” not recovered by generators in the energy market) or real-time non-coincident peak load obligations (Schedule 3 reliability administration service costs). Eversource also said the RTO should create a separate billing item for CIP costs to make them transparent.
According to the New England States Committee on Electricity, transmission costs are between 11 and 18% of total electric bills for residential customers in the region. Total transmission charges have risen from about $869 million in 2008 to $2.25 billion in 2018, NESCOE says.
Asked whether ISO-NE could accommodate Eversource’s proposal, Blomberg said the RTO believes its cost-allocation plan “is the most appropriate solution to ensure compensation” for the NERC compliance requirement.
“The ISO is continuing to listen and discuss this issue with stakeholders,” she added.
In a presentation to the Transmission Committee on March 27, ISO-NE had proposed a cost-of-service reimbursement method, saying a 2017 effort to create a formula rate failed because the RTO was unable to identify a methodology to determine an IROL-critical “proxy” generator or estimate reasonable costs for compliance with the NERC standard.
ISO-NE says the lack of “clear and precise CIP requirements” in standard CIP-002-5.1a Attachment 1 may lead generators to differing interpretations on what steps they need to take. The RTO said costs disclosed by the operators of seven IROL-critical generating stations showed both one-time capital costs and recurring O&M expenses. There was no obvious correlation between costs and generator size, type or vintage, ISO-NE said.
Blomberg said a formula rate is not the same as a proxy rate approach. “Under a formula rate approach, the facility submits its specific costs for approval. A proxy rate is an estimate of the costs of a generic, but similar, facility without consideration of the actual costs. IROL-CIP facilities all have different characteristics, which make proxy rate approach extremely challenging.”
ISO-NE said IROL-CIP costs should be allocated to regional network service and through or out service because accurate IROLs allow the RTO to maximize use of the transmission system.
Lowell told the committee at the March meeting that the ISO-NE would consider alternatives to the cost-of-service proposal if it had broad support within NEPOOL and had a cost estimation methodology the RTO could defend as just and reasonable.
NERC spokesman Martin Coyne declined to comment on the RTO’s characterization of the CIP requirements.
“[We] can’t comment on a presentation that’s not ours or for security purposes discuss details on critical facilities,” he said.
He added: “It is common for entities to seek information from NERC on how specific requirements in our stakeholder consensus-based standards apply to them.”
Business Procedure Change Approved
In other matters, the committee approved ISO-NE’s proposal to make administrative changes to Ancillary Service Schedule 2 of Section II of the Tariff and the VAR Business Procedure, along with revisions to accommodate electric storage reactive resources. The changes move requirements from the Business Procedure into the Tariff and incorporate electric storage facility language into the Schedule 2 capacity cost compensation program.
The RTO said the changes were related to FERC’s Feb. 25 approval of revisions to Section II that created multiple constructs for storage devices to participate in the RTO’s day-ahead and real-time energy markets (ER19-84). (See FERC Accepts ISO-NE Storage Tariff Revisions.)
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.
