While the deadline for compliance filings on FERC Order 845 remains at least three months away, PJM is making sure it’s prepared.
During an Oct. 16 conference call, PJM staffers Susan McGill and Michelle Harhai outlined 10 reforms included in the order, six for which the RTO has already drafted Tariff changes. The remaining four are in progress.
The order, expected to remove even more barriers to storage interconnection, explicitly revises the definition of a generating facility to include storage, permits interconnection customers to apply for interconnection service lower than the capacity of their generating facilities and requires transmission providers to provide interim interconnection agreements for limited operation of generating facilities prior to completion of the full interconnection process.
FERC on Oct. 3 granted an extension of the compliance filing deadline to 90 days while it considers multiple requests for rehearing of the order.
Energy storage | SDG&E
Takis Laios of American Electric Power said his company is finishing proposed revisions of PJM’s governing documents that it plans to submit for consideration.
PJM’s Pauline Foley said the revisions should be submitted “sooner rather than later” and cautioned Laios that because it’s a compliance filing, staff are trying to keep revisions “within the scope of [the order].”
“Anything beyond that would really be better handled in the stakeholder process,” she said.
Foley also noted that part of the challenge is marrying FERC’s order, which make assumptions about what’s already in grid operators’ tariffs, with what’s actually in PJM’s Tariff.
“The commission presumes that certain provisions are included in our Tariff, and a lot of the provisions when we originally made our 2003 compliance filing were not exactly as pro forma,” she said. With the expanded rules that FERC ordered, “we need to confirm that all of the provisions FERC presumes are there are actually there,” she said.
In response to a stakeholder question, Foley added that while “it’s not really practical to implement the order” before it’s fully been approved, interconnection customers can seek mutual agreements with transmission owners to utilize some of the impending rule changes.
MISO is hoping to avoid grid instability by possibly requiring inverter-based generation seeking to enter the interconnection queue to provide a specific set of calculations and documentation.
Under the plan, the owner of an inverter-based resource would be required to supply MISO its short-circuit ratio at the point of interconnection before completing an application. The RTO is also contemplating having a project owner either submit a manufacturer statement showing the inverter can operate stably or an Electromagnetic Transients Program (EMTP) study report confirming stable operation. Any project owner unable to prove stable operation will either have to add equipment to raise the short-circuit ratio or reduce the size of the project.
MISO interconnection engineer Warren Hess said the RTO will disallow use of its “momentary cessation” of active power output from inverter-based resources in order to prevent them from tripping offline unnecessarily. In that case, every generation resource would have to adhere to NERC’s PRC-024-2 standard, which requires generator owners to set their protective relays to ensure generating units remain connected during defined frequency and voltage excursions.
But stakeholders on an Oct. 16 Planning Subcommittee conference call said MISO might be requiring too much of inverter-based customers too early in the queue process. Some said the RTO should consider asking for short-circuit ratio values later in the queue process because those values will change as projects drop out of the queue. Consultant Roberto Paliza said such information should be provided at the end of the queue’s definitive planning phase, adding that MISO should make it clearer what performance standards it requires of inverter-based generation.
But Hess said that short-circuit calculations are relatively easy to provide once customers know the locations of their interconnections. He said MISO wants to avoid entering projects into the queue that ultimately cannot perform without causing harm.
“We are going to be here for guidance to help to calculate short-circuit ratios and coordinate with the applicable transmission owners. Since interconnection customers are deciding where to connect on the system, they should be responsible to work with the transmission owners to get short-circuit ratios for their inverter-based interconnection,” MISO Resource Interconnection Planning Manager Neil Shah said.
“Not doing anything is not an option,” agreed MISO Manager of Resource Interconnection Arash Ghodsian.
MISO staff also promised to work with interconnection customers and transmission owners to gather information and provide guidance on new interconnection requirements.
“This is going to be a two-way street,” Ghodosian said.
Staff said they plan to present draft Tariff language on the possible requirements at the Planning Subcommittee’s December meeting.
In two orders issued late last week affecting MISO’s generator interconnection queue, FERC rejected a maintenance fee for interconnection customers while also approving a new process for interconnecting external merchant HVDC transmission.
The commission on Oct. 12 rejected without prejudice MISO’s plan to create a new mechanism to allow transmission owners to calculate and recoup expenses related to the operation and maintenance of transmission owner interconnection facilities (TOIFs) (ER18-1731-001). TOIFs are “sole use” facilities that includes all infrastructure owned by the TO from the point of the change of ownership (on the system) to the point where an interconnection facility connects to the transmission system.
MISO proposed the “Annual O&M and Overheads Charge” because, while its current generator interconnection agreement makes interconnection customers responsible for all TOIF expenses, the RTO’s Tariff currently provides no method for TOs to recover those costs. The proposed charge would have been calculated by TOs and invoiced annually to interconnection customers, treating revenues from the charge as a revenue credit and subtracting it from a TO’s net revenue requirement.
MISO and the TOs contended their proposal was consistent with FERC’s cost-causation principles because the recovery mechanism ensured interconnection customers would pay their proportional share of maintenance expenses for interconnection facilities, eliminating the possibility that other customers would subsidize the facilities.
But the commission took issue with MISO allowing TOs to calculate the charge using estimated construction costs of the interconnection facilities from the GIA when they cannot determine the facilities’ actual costs. FERC said it wasn’t just or reasonable to allow use of estimates without requiring TOs to support their figures with a Section 205 filing. FERC also said MISO and the TOs did not provide evidence that the estimates would be a “reasonable proxy” for actual construction costs.
The commission additionally pointed out that MISO doesn’t file GIAs — which include the cost estimates — when they conform to its pro forma GIA template. It also pointed out the TOs don’t typically file detailed cost support for their GIA estimates of interconnection facilities. Consequently, MISO and the TOs essentially asked FERC to “accept the use of estimated values for the purpose of deriving a charge for operation, maintenance and repair of the facilities during their service lives without an opportunity to review the reasonableness of such estimates as a proxy for actual … costs,” the commission said.
FERC added that any future proposal should contemplate a partial-year charge for GIAs that expire midyear.
But FERC did accept MISO’s proposal to allow external merchant HVDC transmission projects to connect to its grid, effective July 18 (ER18-1410). The interconnection process is largely based on MISO’s existing queue rules but includes a separate pro forma “MHVDC” connection request form, a pro forma transmission connection agreement and a process for obtaining injection rights, which the project owner converts into external network resource interconnection service (E-NRIS) for its upstream generating facilities. In response to an initial deficiency letter from FERC, MISO explained that it relied on interconnection rules previously approved by FERC and an exhaustive stakeholder process to settle on the new process. (See FERC: MISO Merchant HVDC Procedures Incomplete.)
FERC said MISO’s plan was reasonable: “Because the MHVDC connection customer will go through MISO’s full interconnection process alongside internal generation customers, no issues of undue discrimination or preferential treatment arise between the external generators that may use the E-NRIS converted from injection rights and internal or other external generators that obtain NRIS or E-NRIS, respectively, through MISO’s [generator interconnection process].”
PJM has already missed its Board of Managers’ deadline for revising how it forms prices in its energy market, evoking the question: How much longer will the process drag on?
In April, the board instructed RTO staff to identify changes that could be in place for this winter and asked stakeholders “to deliberate timely” so a proposal could be sent to FERC in the third quarter. (See PJM Board Seeks Reserve Pricing Changes for Winter.) Staff emphasized at a meeting of the Energy Price Formation Senior Task Force (EPFSTF) last Friday that the deadline has passed and asked stakeholders to prepare for a vote at the task force’s next meeting on Nov. 1.
“We’ve missed that [deadline] already, so we’re trying to work as expeditiously as possible to respect their request,” PJM’s Dave Anders said.
“I really want to be able to respect the board’s wishes, and I do respect them. I’m not sure if I can in good conscience honor them. I just don’t think we’re ready to vote,” Old Dominion Electric Cooperative’s Adrien Ford said. “I want to get this right, and I don’t want a board letter to be the reason we don’t get it right.”
“I don’t want to throw in the towel and say this will take as long as it takes,” Anders said in response to the hesitation. He asked stakeholders to come prepared to work toward a vote at the next meeting.
Part of the hang-up might be that PJM has presented all its arguments for why the market should be reformed, and stakeholders aren’t convinced. PJM’s Adam Keech asked what details the RTO hasn’t provided yet.
“There are a lot of eyes on what this group accomplishes,” he said.
“For me, the main thing that’s been missing and that’s always been missing is the motivation for this,” said James Wilson of Wilson Energy Economics, who consults for several consumer advocates within the RTO’s footprint. “I don’t really think you’ve made the case that reserves beyond [the minimum reserve requirement] are worth several hundred dollars.”
The task force has been attempting to resolve concerns that the energy market doesn’t properly attract resources with the benefits, or attributes, necessary for grid reliability. In July, PJM unveiled a proposal to procure reserves on a more granular level, along with implementing nodal reserve pricing, a real-time 30-minute reserves product and flexible sub-zone modeling. At a task force meeting last month, PJM’s Independent Market Monitor proposed revising the operating reserve demand curve to compare the value of purchasing reserves now to fill potential shortages later, rather than purchasing them later during the peak hours of the day. (See PJM Price Formation Group Talks Reserves.)
The Monitor’s Catherine Tyler revisited the proposal at last week’s meeting, explaining that the point of the plan is to avoid turning on more units than necessary while also capturing in prices the cost of operator actions taken to avoid reserve shortages. The proposal prompted skepticism for an apparent disconnect in how paying for reserves now could reduce scarcity risks later in the day.
Tyler said the Monitor’s proposal is “selectively targeting the times when the market would procure additional reserves,” unlike PJM’s.
FERC on Thursday approved reliability standards for mitigating supply chain risks in industrial control system hardware, software and computing and networking services. The commission also ordered NERC to develop rules expanding the supply chain protections to include electronic access control and monitoring systems (EACMS).
The commission’s final rule, intended to build on existing critical infrastructure protection (CIP) standards, approved NERC reliability standards CIP-013-1 (Cyber Security – Supply Chain Risk Management), CIP-005-6 (Cyber Security – Electronic Security Perimeter(s)) and CIP-010-3 (Cyber Security – Configuration Change Management and Vulnerability Assessments). The final rule hews closely to the commission’s January 2018 Notice of Proposed Rulemaking (RM17-13). (See FERC Backs NERC Supply Chain Standards.)
| Pixabay
The new rules, effective 60 days after publication in the Federal Register, will be implemented over 18 months, as requested by NERC. The commission said the transition was needed because compliance will likely require technical upgrades, with implications for capital budgets and planning cycles that have longer time horizons.
Counterfeits, Malicious Software
The rules are intended to protect the bulk electric system from counterfeits or malicious software and tampering. They require affected entities to implement security controls addressing: software integrity and authenticity; vendors’ remote access; information system planning; and vendor risk management. FERC said the rules will cover 288 reliability coordinators, generator operators, generator owners, interchange coordinators or authorities, transmission operators, balancing authorities and transmission owners.
FERC acknowledged the rules did not cover the supply chain risks of EACMS such as firewalls, authentication servers, security event monitoring systems, and intrusion detection and alerting systems. The commission said NERC must propose rules to address the gap within 24 months. “Once an EACMS is compromised, an attacker could more easily enter the [electronic security perimeters] and effectively control the BES cyber system or protected cyber asset,” FERC said.
The commission also noted the standards generally don’t address physical access control systems (PACS) or protected cyber assets (PCAs). “We remain concerned that the exclusion of these components may leave a gap in the supply chain risk management reliability standards. Nevertheless, in contrast to EACMS, we believe that more study is necessary to determine the impact of PACS and PCAs,” the commission said. “Compromise of PACS and PCAs are less likely. For example, a compromise of a PACS, which would potentially grant an attacker physical access to a BES cyber system or PCA, is less likely since physical access is also required.”
Budgets OK’d
The commission also approved NERC’s 2019 business plan along with almost $166 million in spending allocated for the U.S. share of funding NERC, its regional entities and the Western Interconnection Regional Advisory Body (WIRAB) (RR18-9).
The 2019 budgets include $62.5 million for NERC; $102.8 million for its seven regional entities’ funding and almost $630,000 for WIRAB.
Including funding from other sources, NERC’s 2019 budget is $79.1 million, an 8.4% increase over 2018. Most of the increase is attributed to expanding staffing and functions at its electricity information sharing and analysis center (E-ISAC). (See New NERC Chief Not ‘Smartest Guy in the Room’.)
NERC’s budget includes 205 full-time equivalents, an increase of six from 2018.
All three of California’s big investor-owned utilities this week shut down power or warned customers they might need to because of dry, windy conditions that could lead to wildfires, prompting one consumer group to call for a probe into the practice.
It was the first time Pacific Gas and Electric has cut off power to consumers in Northern California based on fire hazards. Southern California Edison and San Diego Gas & Electric have taken such steps before when the hot Santa Ana winds picked up, as happened Monday and Tuesday.
California’s investor-owned utilities have been cutting power to residents during the state’s fall fire season. | Bureau of Land Management
With large fires becoming more the norm, and the state asking utilities to de-energize lines during severe weather conditions, California’s summer and fall fire season is becoming a time of rolling blackouts in fire-prone areas.
Some ratepayer advocates, however, criticized the utilities this week for jumping the gun. They said the power outages may have been more about avoiding liability and sending a political message than about protecting residents.
“We clearly think it’s blackout blackmail,” said Jamie Court, president of Consumer Watchdog, an advocacy group based in Los Angeles.
The IOUs and Gov. Jerry Brown had urged state lawmakers this year to do away with California’s unique system of holding utilities strictly liable for wildfire damage to private property. But the bill Brown signed in September, SB 901, left that strict-liability standard, often called inverse condemnation, unchanged.
The new law requires utilities to file wildfire mitigation plans with the state that include procedures for shutting down power in extreme weather to prevent fires. (See California Wildfire Bill Goes to Governor.)
“They didn’t get inverse condemnation [changed],” Court said. “They want to get out of liability forever for everything, and this is the way they send a signal. The biggest power a utility has is the ability to turn off power.”
‘Last Resort’
PG&E spokeswoman Angela Lombardi said the decision to cut off power this week was solely about wildfire prevention.
“Power safety shutoff will only be done as a last resort,” Lombardi told RTO Insider. “It’s only in the interest of public safety.”
The company took the unprecedented step Sunday and Monday of shutting off power to about 60,000 customers and notifying 37,000 others they could lose power because of gusting winds and dry vegetation in the northern San Francisco Bay Area and the Sierra Nevada foothills near Sacramento. (See PG&E Shuts down Power to Prevent Fires.)
State fire authorities have blamed PG&E’s equipment for sparking numerous fires in Northern California during the 2017 fire season, one of the most destructive in California’s history. The utility is facing billions of dollars in damages for those blazes, which occurred during times of high winds and low humidity.
, National Weather Service
In Southern California, San Diego Gas & Electric notified 4,700 customers Sunday their power could be shut off “with the onset of Santa Ana winds and extremely low vegetation moisture forecasted for the next two days.” The company ended up cutting power to 360 customers living in the foothills near the Cleveland National Forest and had restored power to most as of Tuesday. A red-flag warning remained in effect.
SDG&E, widely considered a state leader in wildfire prevention, has de-energized lines a number of times in the past because of hazardous fire conditions.
Southern California Edison issued warnings this weekend that it might have to shut down power as hot, dry Santa Ana winds began blowing from the desert to the ocean. The winds are typically a harbinger of Southern California’s wildfire season, which tends to peak in the fall but has become more of a year-round problem in recent years with drought and climate change.
CPUC Monitoring
Court, with Consumer Watchdog, said the conditions that prompted the utilities to shut down power were not sufficient to cut off power, especially to schools and to the elderly and infirm, including those who rely on oxygen machines.
“If there are no fires or firefighters in an area, there is no reason for a utility to shut down power unless they know they have faulty equipment or problems with vegetation management,” he said.
Consumer Watchdog sent a letter to California Public Utilities Commission (CPUC) President Michael Picker on Tuesday urging him to launch an investigation of PG&E’s power shutdown and to “investigate each and every time a utility turns out the lights due to high winds.”
In an email, CPUC spokeswoman Terrie Prosper said the commission had been monitoring this week’s power shutdowns and warnings.
“We will do a post-event review, including the factors that went into PG&E’s decision to de-energize, customer outreach and notification and restoration times.”
In general, Prosper added, “the state’s investor-owned utilities have general authority to shut off electric power to protect public safety under California law, specifically California Public Utilities Code (PU Code) Sections 451 and 399.2(a).
“The utilities have recently developed programs to exercise this authority during severe wildfire threat conditions as a preventative measure of last resort,” she said.
PJM’s Board of Managers said Tuesday it will conduct an “independent review” into GreenHat Energy’s massive default in the RTO’s financial transmission rights market.
The investigation comes amid pressure from PJM members for answers regarding the June default, which — with losses expected to exceed $100 million — is likely to be the RTO’s largest ever. (See PJM Reeling from Major FTR Default.) The board said it will throw open its books in response.
GreenHat listed its address as 826 Orange Ave., Suite 565, Coronado, Calif. — a UPS store between a nail salon and a RiteAid. | Google
“Examiners will have complete access to PJM records and staff for interviews and documentation review,” according to a news release.
The default highlighted flaws in the FTR market that allowed GreenHat traders, who had already been linked to a 2013 energy-market scandal, to amass the largest-ever portfolio of positions — 890 million MWh — on $600,000 in collateral. PJM has since identified “lessons learned” following a workshop staff conducted with independent experts and addressed many of the gaps through stakeholder-endorsed rule revisions, but member questions still remain. (See Doubling Down – with Other People’s Money.)
PJM analysis shows the continuing downward trajectory of GreenHat’s FTR portfolio. | PJM
The board has formed a special committee, chaired by board member Susan Riley, that also includes members John McNeely Foster and Mark Takahashi, along with “independent third-party experts.” Among the experts are Robert Anderson, executive director of the independent nonprofit Committee of Chief Risk Officers, and Neal Wolkoff, CEO of Wolkoff Consulting Services. Wolkoff was previously chairman and CEO of the American Stock Exchange and chief operating officer of the New York Mercantile Exchange. The Philadelphia firm of Schnader Harrison Segal & Lewis LLP has been retained as counsel.
The committee promises to answer outstanding questions about the default and highlights four goals:
examine the facts and circumstances associated with GreenHat’s participation in the FTR market and its subsequent default
assess PJM’s actions in connection with GreenHat
review lessons learned and make recommendations for the future of FTR markets
address questions raised by the members concerning the circumstances of the default
PJM members pressed the board for an independent investigation at their Oct. 3 meeting of the Liaison Committee. The committee, which bans media attendance, is an opportunity for PJM members to meet directly with the board several times throughout the year.
East Kentucky Power Cooperative’s Chuck Dugan, the committee’s chair, detailed members’ concerns in an Oct. 10 letter to PJM CEO Andy Ott. Dugan said several questions about the default were raised at the meeting and members are “pleased” the board agreed to the investigation.
The letter outlines six questions members have about PJM’s awareness, responsiveness and transparency regarding GreenHat’s portfolio, including why staff, after apparently learning about the potential default in February 2017, failed to inform members and instead proposed modifications to the RTO’s credit policy for members’ endorsement as if they were unprovoked.
Dugan acknowledged the investigation “will require time” but requested progress reports at upcoming Members Committee meetings. A PJM spokesperson could not provide a target date for completing the investigation.
RENSSELAER, N.Y. — NYISO on Monday floated a carbon pricing proposal that would leave importers and exporters to manage the risk of predicting carbon charges for real-time imports into New York, rather than saddling consumers with that uncertainty.
NYISO staffer Nathaniel Gilbraith recommended to New York’s Integrating Public Policy Task Force (IPPTF) applying carbon charges to external transactions such that they compete with internal resources and each other as if the ISO were not applying a carbon charge to internal suppliers.
Gilbraith cautioned adopting a carbon charge without considering the pricing effects at New York’s borders would likely cause large shifts in import and export dynamics because in-state suppliers would carry an additional cost burden not shared by external suppliers.
“Total carbon emissions as a result of not addressing this seams issue are up in the air and would depend on whether or not external marginal generation is more or less efficient than internal New York Control Area marginal generation,” Gilbraith said. “However, one thing is certain, there would be large financial implications.”
Under the plan, NYISO would base the carbon impact on LBMP (LBMPc) on the real-time system dispatch to determine carbon charges and credits, as opposed to forecasting the impact. The change would be consistent with the LBMPc used to allocate residuals to loads, and the ISO would also create a new billing code for carbon charge settlements.
By basing the LBMPc on real-time system dispatch, the ISO would not be required to produce a binding forecast of the carbon impact, and energy traders would bear the risk of carbon impact uncertainty.
Several stakeholders took exception to the “big change” in the way the ISO does business, but IPPTF Chair Nicole Bouchez, the ISO’s principal economist, said energy traders would be privy to the same information as the grid operator and have the ability to manage that risk.
“Where we landed is that it really wasn’t the best place for consumers to bear that risk because they don’t have the hedges available to [traders] and because the marketers have both the ability to manage the risk and also in many ways the direct incentive to manage that risk,” Bouchez said.
With the new separate line item for a carbon charge on bills and invoices, an import will see both a payment equal to the LBMP and a charge equal to the LBMPc, Gilbraith said.
“Carbon charges and credits will only occur if the transaction flows in real-time,” Gilbraith said. “For example, if an importer receives a day-ahead schedule at a certain $50/MWh, and they buy out of that schedule prior to flowing in real-time, they will not be responsible for any real-time dispatch carbon charge because the transaction did not flow.”
NYISO is targeting the Oct. 22 or 29 task force meeting to discuss LBMPc calculation and transparency of data with stakeholders.
The study assumed lower-emission dispatch leading to a need to buy fewer renewable energy credits (RECs) to meet the Clean Energy Standard decarbonzaion goals, “so if you get this low-cost emissions abatement through the carbon price, you don’t have to do quite as much higher-cost abatement,” Newell said.
The IPPTF is attempting to ensure that consumers derive the maximum benefit from carbon pricing through reduced payouts for RECs. | Brattle Group
The effect is “not very big because it’s assessed at the REC price post-carbon charge, which is quite low, but that’s always been there and it ends up being trivially small,” he said.
The grid operator the previous week had recommended steps to prevent certain wholesale market suppliers, designated as carbon-free in the CES, from collecting double payments for carbon emissions reductions that have already been captured by REC contracts. (See NY Carbon Task Force Looks at REC, EAS Impacts.)
The ISO proposed applying a carbon charge to wholesale market suppliers with active, fixed-price REC contracts with the New York State Energy Research and Development Authority that are based on a REC solicitation that began or was completed prior to the carbon pricing rules taking effect, which the ISO estimates to be the second quarter of 2021 at the earliest.
Clawback Issues
The Brattle study accounted for pre-2020 RECs getting a so-called “clawback,” and Newell emphasized that “we’re not endorsing that at all; that’s a very tricky issue. That was our assumption because it was a proposal by New York ISO.”
Warren Myers, Department of Public Service director of market and regulatory economics, asked, “If New York doesn’t change its policy and index future contracts, do you think the clawback might have an effect on that discount, on how much of that credit is translated into these future REC contracts?
“Yes, in general it raises regulatory risk with the state on anything,” Newell said. “I think there are a number of fairly compelling arguments why not to do it.”
The perception of a double payment is not quite accurate and a clawback carries a lot of potential unintended consequences, Newell said.
Newell said including pre-2020 RECs poses questions: Was the REC payment generators were receiving unambiguously just for carbon or for something else? To what extent did the suppliers already offer a lower price because of the potential upside from getting carbon pricing?
“There also may be some hedging instruments that would have the effect, if you gave them a lower price at their generation node, of impoverishing the generation owners,” Newell said. “They’d actually be losing money if you clawed back the carbon component of the LBMP.”
Rule changes create regulatory risk in general and not just for the next REC payments, he said.
“Even if you believe that these REC prices were based on a view of the world that would never have carbon pricing and was fully just compensating them for their non-emitting attributes, the carbon component of the LBMP would be too much to claw back because there are dynamic effects that have already lowered the energy and capacity prices,” Newell said.
Looking Ahead
Michael DeSocio, the ISO’s senior manager for market design, listed the stakeholder requests so far for additional analysis, such as considering assumptions of a higher social cost of carbon or different RGGI values for 2030. The ISO will prioritize the requests and recommend what analyses the task force undertake, he said.
The task force next meets at NYISO headquarters Oct. 22 to follow up on the treatment of resources with existing REC contracts and to hear a Calpine presentation on how a carbon charge might affect hedges on transmission congestion contracts.
In a victory for transmission owners, FERC on Tuesday signaled a major change in how it sets TOs’ return on equity rates, saying it will no longer rely solely on the discounted cash flow (DCF) model it has used since the 1980s.
Instead, the commission said it will give equal weight to results from the DCF and three other techniques: the capital asset pricing model (CAPM), expected earnings model and risk premium model.
The commission’s new policy came in its long-awaited response to the D.C. Circuit Court of Appeals’ April 2017 ruling vacating Opinion 531, FERC’s 2014 order on the New England Transmission Owners’ (NETOs) ROE rates. (See Court Rejects FERC ROE Order for New England.)
Tuesday’s order proposes a methodology for addressing the issues remanded to the commission in Emera Maine v. FERC and pending in three other proceedings involving NETOs’ ROEs, setting a paper hearing on how the methodology should apply.
“In relying on a broader range of record evidence to estimate NETOs’ cost of equity, we ensure that our chosen ROE is based on substantial evidence and bring our methodology into closer alignment with how investors inform their investment decisions,” the commission wrote (EL11-66-001, et al.).
Higher Hurdle for ROE Complaints
FERC said it would use the methodology to determine initially whether an existing ROE remains just and reasonable. It said it will use three of the models — the DCF, CAPM and expected earnings — to establish a composite zone of reasonableness, which will be “an evidentiary tool to identify a range of presumptively just and reasonable ROEs.” (The risk premium model results in a single number and cannot produce a range of reasonable rates, the commission said.)
Zone of reasonableness quartiles | FERC
“Under this approach, we intend to dismiss an ROE complaint if the targeted utility’s existing ROE falls within the range of presumptively just and reasonable ROEs for a utility of its risk profile — unless that presumption is sufficiently rebutted,” the commission said.
This new threshold, and FERC’s indication that it will act more quickly on complaints, appears to address complaints by TOs and the Edison Electric Institute over “pancaked” ROE complaints being filed while prior cases remained pending. (See EEI White Paper Calls for End to ‘Pancaked’ Rate Cases.)
When the existing ROE has been shown to be unjust and unreasonable, the commission said, it will use all four models to produce four individual cost of equity estimates; the just and reasonable ROE will be the average of the results.
“For each of the DCF, CAPM and expected earnings models, we propose to use the central tendency of the respective zones of reasonableness as the cost of equity estimate for average risk utilities. We would then average those three midpoint/median figures with the sole numerical figure produced by the risk premium model to determine the ROE of average risk utilities. We would use the midpoint/medians of the resulting lower and upper halves of the zone of reasonableness to determine ROEs for below or above average risk utilities, respectively. Because our current policy is to cap a utility’s total ROE, i.e., its base ROE plus incentive ROE adders, at the top of the zone of reasonableness, we propose to use the composite zone of reasonableness produced by the DCF, CAPM and expected earnings to establish the cap on a utility’s total ROE.”
Based on evidence from the first NETO complaint, the new approach resulted in a range of presumptively just and reasonable ROEs of 9.6 to 10.99%. Based on this analysis, the commission said the just and reasonable base ROE would be 10.41% and the cap on NETOs’ total ROE, including incentives, would be 13.08%.
“However, these findings are merely preliminary,” it added, saying the paper hearing would incorporate feedback on its proposed framework.
The commission’s 2014 ruling — prompted by a 2011 complaint by New England state officials and others alleging that the NETOs’ 11.14% base ROE was excessive — reduced the base ROE to 10.57%. (See FERC Splits over ROE.) But the D.C. Circuit said FERC failed to meet its burden of proof in declaring the existing 11.14% rate unjust and unreasonable.
‘Administrative Burden’
Although FERC acknowledged that using multiple models increases the “administrative burden” in ROE cases, the commission said it decided to broaden its approach after concluding that the DCF methodology no longer captures how investors make decisions.
“We believe that, since we adopted the DCF methodology as our sole method for determining utility ROEs in the 1980s, investors have increasingly used a diverse set of data sources and models to inform their investment decisions. Investors appear to base their decisions on numerous data points and models, including the DCF, CAPM, risk premium and expected earnings methodologies.”
FERC said the discounted cash flow methodology produced lower ROEs than the three other models for the four test periods at issue in the New England Transmission Owners’ proceeding. | FERC
The commission said the DCF methodology produced lower ROEs than the three other models for the four test periods at issue in the NETO proceeding. It noted that the models’ results sometimes “move in opposite directions.”
Models Explained
The commission’s order includes an appendix explaining the four approaches. The two-step DCF methodology incorporates both short-term and long-term growth projections. CAPM is used by investors to measure the cost of equity relative to risk.
The risk premium methodology considers interest rates as a direct input to compare returns on stock investments to that on less risky bonds.
The expected earnings analysis is based on the book value of individual stocks and can be either backward-looking using historical earnings, or forward-looking using analysts’ earnings forecasts.
Analyst: Higher Rates Likely
ClearView Energy Partners analyst Christine Tezak said the commission’s new approach will likely result in higher top values to the zone of reasonableness than seen since Opinion 531’s adoption. “This potential re-expansion of the zone of reasonableness would make it more likely that transmission owners will realize higher base ROEs than the DCF model alone indicated without a subsequent subjective upward adjustment. A broader range of reasonableness returns also looks likely to restore the full value of incentive adders awarded to transmission owners in prior proceedings.”
Information on how FERC may apply the new methodology to other TOs may come at Thursday’s open commission meeting, the agenda for which includes the NETO docket.
“We will be looking for an indication at the open meeting as to whether the industry should begin integrating these new principles into pending, recently filed and upcoming rate cases and pending complaints now, or wait” for the conclusion of the paper hearing, Tezak wrote.
The commission set a 60-day deadline for filing initial briefs (Dec. 17), with reply briefs due 30 days after that (Jan. 17, 2019).
The New England TOs are Emera Maine (formerly Bangor Hydro Electric); Avangrid’s Central Maine Power; National Grid; New Hampshire Transmission; The United Illuminating Co.; Unitil Energy Systems; Fitchburg Gas and Electric Light; Vermont Transco; and Eversource Energy (formerly Northeast Utilities, Connecticut Light and Power, NSTAR Electric, Western Massachusetts Electric Co. and Public Service Company of New Hampshire).
Commissioner Richard Glick, who formerly worked at Avangrid, did not take part in the ruling.
Commissioner Neil Chatterjee on Wednesday acknowledged concerns that uncertainty over how FERC would respond to the D.C. Circuit’s remand had chilled transmission investments. “So, our action should help ensure [there is] more clarity going forward,” he said during remarks at the Department of Energy’s Electricity Advisory Committee meeting.
At the commission’s open meeting Thursday, Chatterjee said “the commission will need to make important decisions about how the policy we’ve proposed in Emera Maine applies” in other ROE dockets.
Commissioner Cheryl LaFleur, who was chair when the commission issued Order 531, said that ruling was a compromise that set a tighter zone of reasonableness, with the ROE higher within the zone. “Here we’re allowing a much wider band and the ROE is in the middle of the band.”
VALLEY FORGE, Pa. — Stakeholders at last week’s Planning Committee meeting endorsed PJM’s annual reserve requirement study and recommendations for a 15.7% IRM and a 1.0887 forecast pool requirement (FPR) for next year’s Base Residual Auction, both slight reductions from last year. (See “IRM, FPR Reduced,” PJM PC/TEAC Briefs: Sept. 13, 2018.)
The study found a reduction in the standard deviation for the RTO-wide forced outages from the 2017 study to the 2018 study, which indicates the outliers “are slightly less extreme than they were last year,” PJM’s Andrew Gledhill said.
Staff traced the change back to a “slightly smaller” average unit size this year of 121 MW compared to 129 MW in 2017.
Ride Through
PJM’s Emanuel Bernabeu detailed the results of the RTO’s two-day workshop on distributed energy resources ride-through held on Oct. 1 and Oct. 2.
“We made tons and tons of progress,” he said, adding that staff plan to seek an endorsement vote at the Nov. 11 PC meeting on a problem statement and issue charge to address questions surrounding implementation of a new Institute of Electrical and Electronics Engineers standard on how DERs should react to system voltage fluctuations.
The PC will then vote on endorsing required settings for resources wishing to participate in PJM’s markets, but it will not vote on guidance developed by staff for state regulations on locally regulated resources. The issue raised stakeholder concerns at last month’s meeting. (See “Workshop Set on DER Ride-through Standard,” PJM PC/TEAC Briefs: Sept. 13, 2018.)
Bernabeu confirmed that several revisions have been made to the problem statement and issue charge since then, including not making the standards retroactive for existing resources and creating rules for both inverter-based and synchronous resources.
“They behave quite differently. … We are trying to tackle the entire DER space and not just focus on inverters,” he said. “We are trying to achieve both.”
Alex Stern of Public Service Electric and Gas and Tonja Wicks of Duquesne Light expressed appreciation for PJM’s willingness to address stakeholder concerns.
“We just have to be sure at the RTO level that, as we incorporate greater levels of distributed energy resources, … we’re doing it safely and reliably,” Stern said.
“That’s why we want to solve this now as opposed to California,” Bernabeu said in reference to solar generators disconnecting from the grid during wildfires. “I don’t want to be like California.” (See NERC Chief: Inverter, Fuel Assurance Standards Needed.)
Offshore Wind Interconnection
The growing wave of interest in offshore wind is finally hitting PJM. Staff announced plans to review the Tariff for revisions necessary to address the “new and creative ways” offshore wind developers are proposing to interconnect facilities, which include offshore transmission networks with multiple interconnections.
“We haven’t anticipated this,” PJM’s Susan McGill said of the developers’ proposals. “There’s some ideas out there that this [current] construct doesn’t fit perfectly.”
Ken Foladare of Tangibl requested that PJM also look into other long-term firm transmission projects that sometimes cause delays with generation interconnection queue requests and asked that staff investigate ways to eliminate these delays.
“For generation project developers, these delays often cost them a considerable amount of time and money,” he said.
Impacts of the Energy Transition on Transmission
PJM’s Yuri Smolanitsky detailed plans for two new 500-kV lines and substations that highlight the changes resulting from shale gas and solar development in the RTO.
The Flint Run 500/138-kV substation west of Clarksburg, W.Va., will tap the Belmont-Harrison 500-kV line to provide extra-high voltage for Marcellus shale load growth in the area. The $40.1 million project in the Allegheny Power Systems zone — b2996 in PJM’s Regional Transmission Expansion Plan — will run 138-kV lines of approximately 3 miles each to 138-kV buses at Waldo Run and Sherwood. It’s expected to be in service by December 2019.
In addition, a $5.7 million project in Dominion’s zone will upgrade the Spotsylvania substation and construct approximately half a mile of 500-kV line to connect with the 500-MW Spotsylvania Energy Center solar farm. Smolanitsky said it will be the largest solar farm in the RTO when it goes into service, which is expected next fall. It was developed by Sustainable Power Group (sPower), which was acquired by AES and AIMCo in February 2017, according to the project’s website.
TMEP Congestion Analysis
Two recently approved targeted market efficiency projects (TMEPs) would have resolved $55 million (approximately 11%) of the total $523.2 million in congestion costs over 2016 and 2017 from the 61 facilities that MISO and PJM identified as part of study begun in the spring, PJM’s Alex Worcester announced. (See MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)
Other planned system changes would have resolved $213 million (approximately 41%). Outages drove $201 million (approximately 38%), and $6 million (1.1%) were caused by situations where the congestion isn’t persistent. The remaining $48.2 million (9.3%) includes potential TMEPs, as well as ones where the effectiveness is uncertain, the upgrade is unknown or the proposal didn’t meet the necessary benefit-to-cost ratio.
RTEP Recommendations
PJM’s Board of Managers approved another $214.9 million in RTEP baseline reliability projects at its Oct. 2 meeting. The recommendations come after the board approved $629.23 million in recommended baseline projects at its July 31 meeting.
The majority of the cost comes from a $155 million plan to construct two new 69/13-kV substations in the Doremus area of the PSE&G zone.
Dominion Supplementals
Dominion’s Ronnie Bailey presented three new need assessments and two planned solutions as part of the transmission owners’ new FERC-ordered process for developing supplemental projects. Dominion has presented 19 needs assessments since the process was implemented in September. (See “First M-3 Experience,” PJM PC/TEAC Briefs: Sept. 13, 2018.)
The planned solutions address the first and second needs identified by Dominion last month. The solution for the first need, which would serve a new data center campus in Loudoun County, Va., with total load in excess of 100 MW, is estimated to cost $27.8 million.
The second solution, which would accommodate a request by Old Dominion Electric Cooperative to serve residential, commercial and industrial growth south of Fredericksburg, Va., that is expected by 2023, is estimated to cost $1.4 million. The summer load in the area is around 35 MW, Bailey said, and the winter load is expected to be around 41 MW.
