Page 1222 – RTO Insider

December 5, 2019

West’s RC Transition Earns Plaudits

By Robert Mullin

SALT LAKE CITY — The Western Interconnection’s transition to multiple reliability coordinators ended on a high note Tuesday when SPP took over the remaining portions of Peak Reliability’s territory in the Mountain States region.

Western Electricity Coordinating Council CEO Melanie Frye took note of the happy conclusion to the 18-month process the next day with a touch of regret, even as others noted that the challenges were not all in the past. “Going into this, there was a lot of concern and a lot of angst as to how this would all turn out, but once again the industry has come together and proven what we can do,” Frye said during a WECC Board of Directors meeting Wednesday. “I’m really proud to acknowledge that — and a little saddened with Peak being dissolved. They’ve really been great for the interconnection.”

Under mounting financial pressure as more of its customers signaled their intentions to defect to CAISO’s lower-cost RC service (now called RC West), Peak announced in July 2018 that it would shut its doors by the end of this year.

The announcement — coming about a month after Frye assumed the helm at WECC — set off alarm bells for a region accustomed to being served by one major RC, initiating a scramble by WECC and NERC to ensure a smooth transfer of RC responsibility to CAISO, SPP and BC Hydro. But by September, WECC officials were assuring their board members that they and other industry participants had the situation in hand. (See No ‘Hiccups’ for West’s RC Transition.)

Frye lauded the “tremendous amount of work” done by the new RCs, Alberta Electric System Operator’s existing RC and the “engaged and focused” industry participants who ensured “all of the tools were developed.”

She also “selfishly” called out the key contribution by WECC senior engineer Tim Reynolds, team lead for each RC’s certification.

“It’s been a tremendous lift this year, [and] Tim has performed admirably. I know [he worked] lots of weekends and nights — and I’ve seen the texts and the emails, so I think we really should be proud of what has been accomplished in the interconnection,” Frye said.

She also pointed to Peak’s own role in the transition: “My hat’s off to Peak Reliability, [CEO] Marie Jordan and her entire team. They performed until the very last moment that their services were required.”

Tightening the Seams

Branden Sudduth, WECC vice president of reliability planning and performance analysis, said he had been reflecting on where the organization was a year ago, “anticipating the amount of work that was going to be needed in 2019 to make this a successful transition.”

“Between the utilities, the RC transition coordination group, WECC, NERC and other entities — the new RCs [and] Peak — it really was a herculean effort that they were able to accomplish this this year. They did run into several bumps along the way, but the industry really kind of [grabbed] the bull by the horns and they overcame,” he said.

Sudduth cautioned that WECC’s work with the RCs wasn’t done, but instead entering a new phase.

“This isn’t it. We can’t just say, ‘Alright, perfect, we’re done. The transition’s complete.’ We need to make sure that these RCs are performing effectively,” he said.

Sudduth outlined WECC’s “next steps,” which include ramping up reliability and security oversight activities — the auditing that will verify the new RCs are following NERC standards. He also emphasized WECC’s role in ensuring that the new RCs reach across newly formed boundaries to work with each other.

“We recognize the importance of ensuring that any seams issues between the RCs are addressed, and this coordination and continued communication between the RCs needs to happen,” he said.

Sudduth noted that while WECC will hold its final RC transition webinar next week, “that doesn’t mean we’re not going to receive regular updates on the new RCs. It just means that that will now continue to happen at [WECC’s] Operating Committee meetings,” held quarterly.

The ‘Fragile’ West

WECC Member Advisory Committee member Fred Heutte, of the Northwest Energy Coalition, added his praise during the board meeting’s public comment period.

“I want to thank and commend WECC for stepping up and doing what really needed to happen to make sure that things did not get sideways, did not fall behind,” Heutte said. “The really strong willingness by all of the new RC coordination organizations to make this work was not going to be enough by itself. There needed to be a cohesive approach and enough pushing to make sure that things got done, and WECC has really succeeded in my view.”

But Heutte expressed reservations about the outcome of fractured RC services in the West, questioning whether the new arrangement will stand the “test of time.”

“I wish everybody the best of luck going forward. As I’ve said before, in the future, we may want to reconsider having multiple RCs in the West. There are some distinctive differences in topology here that make the situation more … fragile, perhaps, than [in] the East, but I know that we’ll pursue this current arrangement as best we can.”

December 5, 2019March 6, 2026

MISO OK’d to Require Site Control in Queue

By Amanda Durish Cook

MISO received FERC approval this week to require its generation developers to secure land for projects earlier in the interconnection queue over some protests from renewable developers.

The RTO will now require interconnection customers to demonstrate 100% site control 90 days before the proposed projects enter the first phase of the three-phase definitive planning phase (DPP) of the interconnection queue for study. It also scrapped the previous practice of accepting a $100,000 cash deposit in lieu of demonstrating site control.

FERC said the stricter process was a reasonable way for MISO to better manage its brimming interconnection queue. It also accepted MISO’s transition plan to grandfather interconnection requests submitted in prior DPP cycles from the changes.

“More stringent site control requirements, as proposed by MISO, may help to reduce the number of speculative, duplicative, and non-ready projects entering DPP Phase I,” the commission said Tuesday (ER20-41).

As of last month, MISO’s queue totaled 569 projects at nearly 89 GW of generating capacity. The RTO reported that more than 730 projects totaling almost 120 GW have entered the queue in the last three DPP cycles.

“Much of this capacity will not come to fruition and is the result of certain interconnection customers submitting multiple interconnection requests into DPP Phase I to find the most advantageous point of interconnection, a strategy that has resulted in numerous withdrawals,” FERC said. “We find persuasive MISO’s argument that the ability of interconnection customers to enter the queue without financial risk contributes to the submission of speculative projects, which negatively impacts the entire queue by causing delays, skewing study results, shifting costs to other customers and inflating milestone payments when these projects are withdrawn.”

The filing FERC accepted was MISO’s second attempt at more rigorous obligations on project owners. The RTO first proposed higher milestone fees in addition to the firmer site control requirements. However, it dropped its plan to change the first, $4,000/MW milestone payment to a variable cost representing 10% of the average network upgrade cost from the last three DPP cycles. FERC said the change would have resulted in accounting uncertainty and averages applied unfairly across the entire footprint. (See MISO Zeroes in on Queue Overhaul Filing.)

MISO will now allow different fuel types and multiple generation projects to share the same site, abandoning the first proposal’s requirement that project owners show exclusive use of land. As it proposed in the first filing, the new rules add a provision that 50% of milestone fees are considered at risk of not being refunded if they’re needed to help defray network upgrade costs should a project withdraw.

A group of renewable generation developers, Invenergy and the Solar Energy Industries Association had disputed MISO’s 50% milestone forfeiture, arguing that it didn’t show that the current practice of fully refunding the first milestone fee caused delay in queue studies. They also argued that withdrawing after paying the first milestone fee is natural, as MISO delivers the estimated costs of necessary network upgrades only after the milestone payment deadline has passed. Withdrawal after the queue’s first decision point is usually a “reasonable response” to expensive upgrade estimates, they said, and not the hallmark of a speculative project.

But FERC pointed out that MISO will now require a screening study more than two weeks before the DPP begins, thereby informing customers of potential thermal and voltage constraints. The new study “should provide interconnection customers with an awareness of what network upgrades may be necessary to accommodate the interconnection of their projects,” the commission said.

FERC also denied EDF Renewables’ request that it compel MISO to annually detail in reports how the 50% milestone forfeiture has a “meaningful impact on keeping speculative projects from entering the queue.”

EDF had also sought a defined endpoint for MISO’s harm tests on withdrawing projects and a deadline for it to return milestone payments to interconnection customers if no impact is found on other projects. The commission said it wouldn’t hold the RTO to deadlines on either, noting that project withdrawals can create ripple effects that impact other projects, even as they advance to later stages of the queue.

FERC urged MISO to be more transparent with customers over how it “will calculate harms caused by withdrawing interconnection customers and how it will distribute forfeited milestone payments to offset those harms,” but it did not direct the RTO to make an additional compliance filing.

December 5, 2019

MISO Market Subcommittee Briefs: Dec. 3, 2019

CARMEL, Ind. — MISO is moving ahead with a proposal to bring solar generation into market dispatch, reusing many of the rules from its 2011 change that brought dispatchable wind generation into the markets.

At the Market Subcommittee meeting Tuesday, Executive Director of Market Operations Shawn McFarlane said MISO will file the Tariff changes later this month.

The proposal would require solar plants to register under the dispatchable intermittent resources category, the same category MISO requires of its wind generation. Officials said the change is driven by the rapid increase of solar installation in the RTO’s footprint. (See Anticipating Boom, MISO Extending Dispatch to Solar.)

Some stakeholders last month asked for grandfathered provisions from the change for existing solar generation, but MISO Manager of Resource Retirement Kun Zhu said no grandfather provisions were laid out in the RTO’s wind dispatch rules, nor SPP’s similar rules for solar dispatch.

Restoration Energy Design Nears Completion

MISO said its stakeholders are supportive of its plan to price energy that reactivates islanded areas of the grid following a blackout.

The RTO plans to make a Tariff a filing to incorporate the new pricing structure in either March or April.

MISO’s proposal dictates that compensation for restoration energy would rely on last-submitted offers before the blackout as a starting point for pricing, resulting in unique costs based on resource. The RTO would allow for the recovery of start-up costs, emergency purchases and resource-specific energy costs. It would also include recovery for any unusual costs incurred during operation, provided they can be verified by the Independent Market Monitor. It would also accept after-the-fact updates of offers. (See “Restoration Energy Pricing in the Works,” MISO Market Subcommittee Briefs: Oct. 10, 2019.)

Costs of restoration energy — including both resource costs and emergency energy purchases — would be allocated on an hourly load-ratio share to re-energized load in an islanded area. The restoration events would be considered finished when MISO’s day-ahead market again takes over economic dispatch.

Michael Chiasson, vice president of Potomac Economics, MISO’s Monitor, said the cost determination might not be neat and orderly, as islanded areas might shrink, grow or meld into one another as the restoration develops.

Chris Delk, MISO manager of market settlements, said the RTO would limit non-typical start-up costs, with a cap proposed at 50% of a unit’s cold start-up costs, the most expensive category. He said MISO and the Monitor were concerned about how high supplementary start-up costs could go absent a cap. The atypical costs might include the costs of renting hotel rooms for employees, travel or transportation, he said. Recovery of anything beyond the 50% cap on additional start-up costs would require a filing with FERC.

“We want it to go before FERC to get it on the record and get them defending it publicly,” Delk explained to stakeholders.

New MISO Market Protections Inevitable

MISO will seek FERC approval next month for authority to increase collateral requirements and suspend trading when a market participant exhibits undue risk to its markets.

The RTO will request an effective date before April for the changes to its credit policy.

MISO’s proposed Tariff language would allow it to act when it perceives evidence of default, manipulation or unreasonable risk to the markets. The new rules would also allow it to reject applications from new market participants and former market participants that have an uncured financial default and attempt to rejoin the RTO under a different name. Finally, MISO would ask prospective and current market participants for more specifics on its annual certification form. It would inquire about any past defaults, bankruptcies, dissolutions, mergers or acquisitions, and any investigations.

The broader market protections edits are an expansion on stepped-up requirements in MISO’s financial transmission rights market. The RTO on Nov. 22 received FERC permission to apply higher collateral requirements (ER20-73). (See MISO Looks Beyond FTRs for Market Protections.)

Customized Energy Solutions’ David Sapper asked if MISO will rely only on publicly available information to make decisions about risk to the market.

“Probably not,” said Brian Brown, principal credit analyst for the RTO. “If there’s risk to the market, we don’t want to put our head in the sand and ignore it.”

Brown also pointed out that the Tariff already requires market participants to notify the RTO of confidential investigations, so it should already be privy to certain nonpublic information.

— Amanda Durish Cook

December 5, 2019

ISO-NE Projects Adequate Resources for Winter

ISO-NE reported Wednesday that the region has sufficient power generation resources to meet the forecasted peak demand this winter but warned that during periods of extreme cold weather, “natural gas pipeline constraints can limit the availability of fuel for natural gas-fired power plants.”

Based on regular surveys on generators’ fuel supplies, the RTO estimates that more than 4,500 MW of natural gas-fired generating capacity is at risk of not being able to get fuel when needed.

Storms and extreme cold can also impact oil and LNG availability and deliveries, the RTO said.

This is the first winter season since the 2,028-MW Pilgrim nuclear plant retired in May. The plant’s capacity is being replaced by several new resources, including three dual-fuel plants, as well as solar and wind resources.

By the Numbers

The RTO forecasts a peak demand of 20,476 MW, assuming normal winter lows (7 degrees Fahrenheit), and 21,173 MW under extreme winter weather (2 F).

Resources with a Forward Capacity Market capacity supply obligation represent 32,747 MW (94%) of the region’s total resources.

Last winter’s peak demand of 20,773 MW occurred Jan. 21, 2019, during the hour ending 6 p.m. The all-time winter peak in New England was 22,818 MW on Jan. 15, 2004.

ISO-NE is developing an Energy Security Improvements proposal, with stakeholder discussions on LNG supplies, market mitigation and a second demand curve. (See NEPOOL Markets Committee Briefs: Nov. 12-13, 2019.) The RTO has until April 15, 2020, to file a long-term fuel security mechanism under FERC’s second extension since its original order last July (EL18-182).

– Michael Kuser

December 5, 2019

Dominion Cancels RFP for New Peaker Plant

Dominion Energy called off its solicitation for a 1,500-MW peaking plant Wednesday, just days after LS Power asked Virginia officials to intervene in the process.

The request for proposals, issued last month, was meant to help close a projected 4,044-MW capacity gap identified in the company’s integrated resource plan. But LS Power argued that such generation already existed in Dominion’s footprint and questioned the competitive process described in the RFP. (See Dominion Challenged on RFP for New Peaker Plant.)

Jeremy Slayton, a Dominion spokesperson, did not give a reason for the reversal in an email sent to RTO Insider Wednesday afternoon.

“The company will continue to monitor market conditions to determine if an RFP for peaking generation will be reissued in the future,” he said.

Nathan Hanson, senior vice president at LS Power, had urged William F. Stephens, the State Corporation Commission’s director of public utility regulation, and state Attorney General Mark Herring “to suspend the solicitation as it is currently structured, review the requirements and implement changes that will make the process competitive, for the benefit of Virginia consumers.”

Hanson sent the letter on behalf an LS Power limited partnership, which began operation of two 170-MW natural gas peaking plants at the Doswell Energy Center in Hanover County, Va., in May 2018.

Marji Philips, LS Power’s vice president of wholesale market policy, said late Wednesday via email that the company “was pleased by Dominion’s recognition that the RFP was ill conceived at this time.”

— Christen Smith

December 5, 2019

PG&E Judge Weighs Insurers’ Settlement

By Rich Heidorn Jr.

Attorneys for Pacific Gas and Electric urged U.S. Bankruptcy Judge Dennis Montali on Wednesday to quickly approve the utility’s proposed $11 billion settlement with insurance companies and hedge funds, warning that claims could rise much higher if it is rejected.

Opponents countered that the settlement would require wildfire victims to sign “one-sided” releases that could leave them far from whole for their losses.

PG&E Bondholders Settlement — Stephen Karotkin | *Weil, Gotshal & Manges*

“No one can challenge the reasonableness of the settlement,” PG&E attorney Stephen Karotkin told Montali during a nearly two-hour hearing, saying it represented a 45% “discount” from more than $20 billion in claims.

Karotkin asked Montali to rule by Friday, calling it a “serious drop-dead date” for the subrogation claimants seeking reimbursement for insurance claim payouts. Swift approval of the deal is essential to the utility’s ability to meet the June 30 deadline for eligibility to participate in an insurance fund for future wildfire claims under Assembly Bill 1054, he said.

“From the debtor’s perspective, we don’t want to take the risk that this [settlement] blows up,” he said.

But Robert Julian, representing the Official Committee of Tort Claimants, said the case could be settled within days if the “one-sided” release was eliminated.

Wildfire victims facing hospital bills or damaged homes will be forced to sign the release to obtain cash “because they’re so desperate. That’s not choice,” he said.

“You’re asking me to violate the ‘bird in hand rule’ and let this $11 billion bird fly away,” Montali responded, saying that if he rejects the deal, “maybe there will be a $20 billion or $25 billion set of claims. … That’s not a good thing for anybody.”

With the proposed release, “this case is not resolving,” Julian responded. “I can’t get lawyers to agree to any plan in this case or mediation … or anything because they can’t [endorse] something they can’t recommend under the law. … You’re forcing this release down our throats.”

Rebecca J. Winthrop, attorney for Adventist Health, whose Feather River Hospital was among 18,700 structures damaged or destroyed by the Camp Fire in November 2018, agreed that the release “is not symmetrical.”

“So, if I want to go against those tree trimmers or against my insurers, I can’t. … That is well beyond what is necessary to protect the insurance carriers,” she said.

Nancy Mitchell, representing Gov. Gavin Newsom, said the governor is concerned that the settlement will leave the utility without enough cash to meet the requirements of AB 1054. She echoed claims the governor’s office made in court filings last month that holders of subrogation claims, some of which also hold equity in PG&E, are using the settlement to improve their holdings. (See Fight Escalates over PG&E Settlement with Insurers.)

“This settlement is about leverage. It is not about a debtor who … is trying to do the right thing,” she said. “This plan is making it impossible for us to evaluate other plans because the debtor is only pursuing one plan.”

Gregory Bray, representing the official Committee of Unsecured Creditors, said the $11 billion settlement is “in the ballpark” but that it should apply also to competing reorganization plans.

In his closing remarks, Karotkin denied that the company was acting in bad faith or taking advantage of wildfire victims, insisting the release provisions challenged by the opponents “are customary and typical.”

“The debtors are not hell-bent on an equity-sponsored plan. What they are hell-bent on is having the best plan, a financeable plan, that is fair to all of the debtors’ economic stakeholders and will get these debtors out of Chapter 11 in a timely basis so they can participate in the wildfire fund.”

Montali ended the hearing with a pledge to make a ruling, “not to defer a ruling,” as some in the case had urged.

“I can’t promise you how soon it will be,” he said. “I’m trying to keep the decisions coming out. I’ll do my best.”

Bloomberg reported Wednesday that PG&E is close to finalizing a $13.5 billion settlement to wildfire victims, half in cash and the rest in stock in the reorganized company. PG&E stock rose 7% on news of the potential deal, closing at $9.47/share after trading as high as $10.75.

December 5, 2019

FERC OKs SCE Rate Settlements

By Rich Heidorn Jr.

FERC on Tuesday approved a settlement reducing Southern California Edison’s 2018 base transmission revenue requirement (TRR) and return on equity, and a partial settlement on the utility’s 2019 request for an ROE increase to reflect wildfire risks.

The commission approved an uncontested settlement in a dispute over SCE’s 2018 base TRR and revisions to its formula rate methodology (ER18-169-002). It set the case for hearing and settlement procedures in late 2017, saying that although SCE proposed a reduction in its TRR, “a further decrease may be warranted.” (See FERC Sets Hearing on SCE Tx Rates; Glick Dissents.)

The commission approved the deal after its endorsement by FERC trial staff, which said the settlement “provides numerous benefits to customers,” including increased transparency of the utility’s cost inputs and “near-immediate rate relief.”

SCE Rate Settlement — Investigators found that Southern California Edison power lines sparked the Thomas Fire, which killed two people in December 2017 and led to mud flows that killed 21 more. | *U.S. Forest Service*

SCE had proposed a base ROE of 10.3%. The settlement reduces that to 9.92%, exclusive of the 50-basis-point CAISO adder and project-specific adders equivalent to 0.78%.

The true-up TRR for 2018 was set at $1.079 billion. SCE had sought a TRR of $1.169 billion, down from $1.189 billion in 2017.

The settlement also adjusts how SCE calculates its capital structure, limits its recovery of incentive compensation and allows more time for stakeholders to discuss draft annual updates with the company.

The utility also agreed to pay up to $350,000 for the California Public Utilities Commission’s consultant to participate in the CAISO transmission planning process, the transmission maintenance and compliance review, and the 2019 formula rate annual update and settlement negotiations. SCE and the CPUC also agreed to continue discussions on potential rate design modifications.

SCE’s proposed two-year limitation on correction of errors was eliminated.

FERC had required SCE to file a replacement transmission rate recovery mechanism as part of a settlement over its original formula rate, which took effect in 2012. SCE had recovered its TRR through stated rates after unbundling its retail transmission rates and transferring operational control of its transmission network to CAISO in 1997.

SCE Wins 12.47% ROE in Temporary Deal

The commission on Tuesday also approved a partial settlement reducing SCE’s ROE from 17.62% to 12.47% as settlement proceedings continue over the company’s 2019 TRR (ER19-1553-001).

SCE requested the 17.62% ROE in April, citing “dramatic material changes to SCE’s regulatory and financial conditions that have occurred” since the utility’s prior rate took effect in October 2017 — a reference to the potential for multibillion-dollar costs based on California’s strict liability standard for utility-sparked wildfires. In June, FERC tentatively accepted the increase but postponed any change for the maximum five months and set it for an evidentiary hearing. (See FERC Leery of SCE’s ROE Request for Wildfires.)

The partial settlement, which was unopposed, “does not definitively resolve any issues set for hearing but reduces SoCal Edison’s ROE on an interim basis,” the commission wrote. It noted trial staff’s comments that the commission “has not found the 12.47% ROE to be fair, reasonable or in the public interest, and that it is leaving a final determination on that issue to the existing hearing and settlement judge procedures.”

December 4, 2019January 18, 2024

Westward Ho: SPP Now a Western RC Provider

By Tom Kleckner

SPP launched its Western reliability coordination service Tuesday afternoon, becoming the first regional transmission organization to handle RC services in both the Eastern and Western Interconnections.

The RTO said the transition from Peak Reliability, the Western Electricity Coordinating Council’s RC provider since it was separated from WECC in 2014, was seamless and took place at noon, Mountain Time.

SPP is now responsible for ensuring the bulk electric system’s reliability for 16 entities, representing about 12% of Peak’s legacy load: Arizona Electric Power Cooperative (AEPCO); Black Hills Energy utilities Black Hills Power, Cheyenne Light, Fuel and Power Co. and Black Hills Colorado Electric; City of Farmington (N.M.); Colorado Springs Utilities; El Paso Electric Co.; Intermountain Rural Electric Association; Platte River Power Authority; Public Service Company of Colorado (Xcel Energy); Tri-State Generation and Transmission Association; Tucson Electric Power; Western Area Power Administration (WAPA) Colorado River Storage Project Management Center; WAPA Desert Southwest Region; WAPA Rocky Mountain Region; WAPA Upper Great Plains-West.

The grid operator spent more than a year working with the companies to develop its Western RC services and manage their implementation. SPP established data connections to new customers, built out systems and processes and ensured everyone was ready for the transition.

“AEPCO commends the staff at SPP for the dedication and diligence required to successfully pull off a daunting task,” Arizona Electric’s executive director of system operations, Shane Sanders, said in a state m ent. “AEPCO appreciates the level of detail required to bring in the project on time and on budget without any unexpected surprises or hurdles. Hats off to a job well done.”

CAI S O has been providing RC services for the vast majority of WECC since July. Like SPP, CAISO jumped at the opportunity to expand its services when Peak announced last year it would wind down operations at the end of 2019. (See CAISO RC Wins Most of the W est.)

Canadian entities BC Hydro and the Alberta Electric System Operator are serving as RCs for their footprints, accounting for another 14% of the WECC’s load.

WECC CEO Melanie Frye called the transition a “major reliability milestone” and lauded Peak’s leadership and staff for providing “high-quality RC services” up until the last moment of Peak’s existence.

“The transition to multiple RCs represents a significant accomplishment for all new RCs, their customers, Peak Reliability, and the overall reliability and security of the bulk power system in the Western Interconnection,” she said.

“We greatly appreciate the work of Peak, CAISO and SPP to make the transition as smooth and seamless as possible,” said WAPA COO Kevin Howard.

SPP framed its Western RC services as “laying the foundation” for additional offerings as part of its Western Energy Services portfolio. The RTO already administers the Western Interconnection’s unscheduled flow mitigation plan for six utilities, and it will launch an energy imbalance service in 2021. (See WAPA, Basin, Tri-State S i gn up with SPP EIS.)

NERC certified SPP’s RC services last month. (See NERC Certifies SPP as RC Provider in West.)

The RTO has been a NERC-certified RC in the Eastern Interconnection since 1997, managing about 40 GW of load. Its RC service territory now extends from the Canadian border to the Texas Panhandle.

December 3, 2019

FERC Rejects Pepco, Delmarva Tx Rate Challenges

By Christen Smith

FERC rejected transmission rate challenges on Monday against Potomac Electric Power Company (Pepco) and Delmarva Power & Light that challenged the accounting of each utility’s prepaid pension assets in its annual update.

Delaware Municipal Electric Corp. and the Southern Maryland Electric Cooperative in January questioned the prudency of the utilities’ combined $522.5 million in retirement contributions, suggesting the costs were voluntary and inappropriately included in their 2018 transmission base rates.

Both Pepco and Delmarva participate in a consolidated retirement fund with Atlantic City Electric Co. and Baltimore Gas & Electric. Parent company Exelon manages the account and determines annual contribution requirements for each utility, based on federal law and an internal policy that mandates at least a $300 million contribution until fully funded. Pepco and Delmarva raised transmission rate bases last year by $34.5 million and $12.4 million, respectively, to account for the prepaid pension assets.

SMECO said Exelon’s policy lacks transparency and its funding strategy remains unclear, noting the contributions go above and beyond federal mandates — arguments FERC rejected in its order Tuesday (ER09-1 1 59). DEMEC’s complaints against Delmarva were likewise dismissed, just as they were in a near-identical challenge to the company’s 2016 annual update (ER0 9 -1158).

“The commission did not say [in 2016] that an expenditure is imprudent if it exceeds the minimum funding requirements established by federal pension laws, or that there is a serious doubt about the prudence of an expenditure just because it is not required by federal pension laws,” FERC wrote. “SMECO’s argument runs contrary to the commission’s prudence standard because it suggests that Pepco was limited to a single correct act — making cash contributions that matched minimum funding obligations under federal law — rather than having discretion in its decision-making.”

DEMEC’s attempts to solicit refunds from Delmarva for accumulated deferred income tax (ADIT) associated with two retired transmission facilities also failed, since the utility paid the ADIT balance to the appropriate government authorities per IRS procedure.

FERC also said Delmarva acted appropriately when it used historical formula rate methodology to true-up rates between Jan. 1, 2018, and May 31, 2018, despite the fact the federal income tax rate had dropped from 35% to 21% that year.

Questions about the utility’s accounting of software-related expenses as miscellaneous intangible plant costs, which raised the rate base by $10,000, were also dismissed as unproblematic because the category accounts for licensing, an “intangible” element of software.

December 3, 2019

FERC OKs PJM-MISO JOA Changes

FERC on Monday accepted revisions to PJM and MISO’s joint operating agreement (JOA) but declined a broader review of how interregional planning coordination could be improved with SPP (ER20-34, ER 2 0-36).

MISO and PJM filed identical sets of JOA revisions in October that clarified the coordinated system plan (CSP) process, corrected errors and addressed inconsistencies in earlier versions. The revised JOA:

Clarifies that a CSP study including a more complex, longer duration study provides for, but does not require, the development of a joint model;
Clarifies that construction of interregional transmission projects is subject to the regional tariff in which the facilities will be constructed;
Removes the interregional market efficiency project criterion that at least one dispatchable generator in the adjacent market has a generation-to-load distribution factor of 5% or greater;
Removes references to use of a joint model from the determination of benefits; and
Removes a legacy provision that allows testing of any project against interregional cost allocation criteria outside a CSP study.

The RTOs said the revisions reflect their stakeholder processes and “are intended to improve and add greater clarity to the development of the CSP process.”

Units of International Transmission Co. told FERC the revisions were an improvement but said more changes were needed to address planning coordination with SPP.

The companies also said the JOA between MISO and PJM disfavors interregional transmission projects with more broadly-applicable benefits and FERC should consider “elevating interregional transmission planning processes to a more equal footing with their respective regional counterparts.”

FERC rejected ITC’s arguments as out of scope.

PJM MISO — PJM and MISO footprints | *MISO, PJM*

Interconnection Changes Approved

On Tuesday, the commission also approved changes tightening MISO’s site control requirements in the definitive planning phase (DPP), the final step of its interconnection studies (ER20 –41).

Under the new rules, effective Dec. 4, MISO will require a demonstration of 100% site control 90 days before the DPP begins. It will also eliminate its $100,000 cash deposit in lieu of demonstrating site control.

MISO also is making the M2 milestone payment 50% at-risk unless an interconnection request is withdrawn before the start of DPP phase I. The commission agreed with the RTO that the change would discourage interconnection customers from submitting speculative projects and reduce the harm caused by project withdrawals.

— Christen Smith and Rich Heidorn Jr.