FERC on Monday extended the deadline for comments in a high-stakes dispute over net metering until June 15 (EL20-42).
The New England Ratepayers Association (NERA) filed a petition for declaratory order on April 14 asking FERC to outlaw net metering for rooftop solar generation by ruling that the commission has exclusive federal jurisdiction over wholesale energy sales from generation sources located on the customer side of the retail meter.
The declaration would require such sales be priced under the Public Utility Regulatory Policies Act of 1978 or the Federal Power Act, which could require the customer to have a rate on file with FERC.
“In other words, the group seeks to end net metering as we know it,” tweeted Ari Peskoe, director of the Electricity Law Initiative at the Harvard Law School Environmental and Energy Law Program.
FERC granted the 30-day extension in response to a request by the National Association of Regulatory Utility Commissioners (NARUC), which cited the coronavirus pandemic and the potential impact of the commission’s ruling in the case.
FERC extended the deadline to June 15 for comments in a high-stakes dispute that could end net metering.
NARUC said states with full net metering programs treat the entire output of energy from an electricity consumer’s generation source that is located on the same side of the retail meter as the consumer’s load as subject to state jurisdiction.
“NARUC has not yet taken a formal position on this petition; however, many NARUC members have expressed serious concerns with the petition’s timing, scope, jurisdictional implications and implementation challenges,” the organization said in its motion.
NARUC, which had requested an extension until Aug. 12, was supported in its request by several state regulatory commissions, consumer advocates and other intervenors. NERA said it opposed any extension beyond 60 days.
NERA describes itself as a non-profit advocacy group seeking to protect “families and businesses” from excessive utility rates.
The Energy and Policy Institute, however, says its “lobbying and regulatory advocacy often align with the interests of investor-owned utilities and the fossil fuel industry” and says it has close ties to New Hampshire’s Gov. Chris Sununu.
NERA’s petition was filed by Steptoe & Johnson attorneys David B. Raskin and Richard L. Roberts and reiterates arguments that Raskin has been making for years. Raskin has represented the Edison Electric Institute in the past, but EEI has said it is not involved with the filing.
Dozens of stakeholders have filed to intervene in the FERC docket thus far, an indication of the stakes in the case.
Dominion Energy saw little load impact from the COVID-19 pandemic in the first quarter, company officials said Tuesday, but earnings were hurt by an abnormally warm winter season.
The company reported a $270 million ($0.34/share) net loss compared with a $680 million net loss ($0.86/share) in the first quarter of 2019.
CFO Jim Chapman said unfavorable weather conditions impacted utility earnings by 9 cents as Virginia recorded its third warmest first quarter on record. The first quarter marked Dominion’s 17th straight quarter of delivering results within the company’s guidance range, which was set at between $1.05 and $1.25/share.
Dominion is initiating a second quarter operating earnings guidance with a range of 75 cents to 85 cents/share, Chapman said, while affirming the annual guidance range of $4.25 to $4.60/share. The second-quarter and full-year guidance ranges reflect preliminary expectations for the impacts of the pandemic.
Dominion officials are assuming that the U.S. economy will begin to ramp up through late summer, and Chapman said electricity demand in Virginia has remained positive in relation to recent years despite the pandemic.
| Dominion Energy
“Virginia load is continuing to prove extremely resilient,” he said, attributing the resilience to several factors.
Residential usage within Dominion Energy Virginia (DEV), which typically accounts for around 45% of revenue, increased in year-over-year volume by about 3% in April as more individuals worked from home.
Despite the stay-at-home order in Virginia, Chapman said commercial load decreased by only 3% in year-over-year volume as losses from shuttered businesses were offset by the “proliferation of data centers in our service territory,” which has accounted for 30% of commercial volume since 2019.
A limited industrial exposure within Dominion’s Virginia footprint also kept load impacts from being severely impacted, he said, with only 6% of DEV’s revenue attributable to industrial usage.
| Dominion Energy
Finally, government and military electricity usage, which accounts for 16% of revenue and 15% of volume, was up almost 4% year-over-year in April.
“Based on observable data, we’re not at present forecasting major COVID-driven revenue impacts associated with reduced load at Dominion Energy Virginia during the remainder of 2020,” Chapman said. “Of course, the situation is dynamic.”
CEO Thomas Farrell said the company has taken steps to help customers struggling in the uncertain economy created by closures because of the pandemic, including voluntarily suspending nonpayment service disconnections and waiving late fees across all utility service territories.
The COVID-19 response within the company has involved utilizing frequently drilled crisis response plans, he said, as well as the activation of its remote connection infrastructure, which is enabling more than half of Dominion’s workforce to operate remotely.
Farrell said Dominion has been fortunate that, among its 19,000 employees in 20 states of operation, “very few” workers have tested positive for COVID-19. Most of the positive cases are asymptomatic or mildly symptomatic, and most of them have already returned to work.
A Renewable Future
The proliferation of renewable energy resources within Dominion also played an important part of Tuesday’s conference call. The company filed its 15-year long-term integrated resource plan for Virginia on Friday. The IRP includes plans to increase solar, wind and energy storage capacity, with some increases coming from mandates in recent clean energy legislation signed into law in April by Gov. Ralph Northam. (See Va. 1st Southern State with 100% Clean Energy Target.)
Dominion’s long-term IRP also includes:
more than 5,000 MW of offshore wind planned by 2035, including the 2,600-MW Coastal Virginia Offshore Wind project that has a targeted in-service date of late 2026;
an increase of its solar fleet, already the fourth largest among U.S. utility holding companies, to develop and procure approximately 16,000 MW in the state over the next 15 years; and
expanding energy storage capacity to about 2,700 MW through battery storage pilot programs already approved and scheduled to be online in Virginia in 2021.
Farrell said the proliferation of renewable and intermittent resources across Dominion’s system will require continued investment in transmission infrastructure, especially as solar and wind emerge around the state.
Farrell said the Virginia State Corporation Commission’s pointed March 26 decision denying certain elements of smart meter technology proposed by Dominion because of projected costs was a blow to the company.
The commission estimated that Dominion’s proposal, if approved in full, would have cost customers nearly $7 billion over 10 years. Smart meter technology was one of the most expensive elements of the plan, coming in at $752 million in total costs.
Renewables “will require an increasingly modern grid, which is why the recent [Virginia] commission decision to reject certain, although certainly not all, aspects of our most recent grid transformation filing was disappointing for our company and particularly for our customers,” Farrell said.
MISO defended its first storage-as-transmission proposal before FERC staff this week, maintaining the plan is a good interim measure while the RTO designs a more permanent approach.
The contentious proposal was the focus of a May 4 technical conference to allow FERC to weigh the merits of the plan. (See MISO SATOA Proposal Set for Technical Conference.) Many MISO stakeholders have complained that the proposed ruleset would give incumbent TOs an effective monopoly on storage assets functioning as transmission, harming competition. (See MISO SATOA Proposal Faces Opposition.)
The plan limits storage-as-transmission assets to transmission-only functions operated by MISO-defined transmission owners. As such, a new category of storage-as-transmission-only assets (SATOA) would be barred from simultaneous participation in MISO’s energy markets — for now. The RTO has contended that its plan will avoid introducing complexities around cost recovery, particularly the thorny issue of how to compensate non-TOs for providing transmission services.
But FERC in March ruled that MISO’s bid to include storage options in its annual transmission planning might be “unjust, unreasonable, unduly discriminatory or preferential,” suspending the provisions until Aug. 11 and calling for the conference (ER20-588).
FERC Chairman Neil Chatterjee opened the commission’s first-ever virtual conference saying that he would pay special attention to the subject matter.
“I believe electric storage is a transformative technology that will be crucial to the grid of the future,” Chatterjee told listeners.
MISO Senior Manager of Competitive Transmission Administration Brian Pedersen called the proposal a “fundamental first step” in unlocking the full potential of energy storage facilities and said the plan represents a year-and-a-half of the RTO’s efforts in considering stakeholders’ opinions.
Pedersen acknowledged that some stakeholders advocated for storage to be allowed to simultaneously function as both transmission and energy market assets but said designing rules for dual-mode participation, a project selection process and a cost recovery mechanism for non-TOs would be too complex to implement right away.
“To do so would delay the issue by months, even years,” Pedersen said.
MISO officials said their approach to approving SATOA projects will factor in the length of time to get a SATOA resource operational versus traditional wires solutions, its effectiveness in resolving contingencies, availability and reaction times, what right-of-way space is necessary and the resource’s performance degradation over time. State-of-charge responsibilities will rest with the storage owner, though MISO could direct that a device be fully charged at certain times.
Pedersen said the RTO will also consider how the connection of a SATOA will impact generation awaiting interconnection in the queue.
Director of Planning Jeff Webb said MISO would not select SATOA devices in congested locations where several generation projects are vying for interconnection to avoid disrupting the generation queue. Stakeholders have voiced concern that SATOA projects would supersede planned generation projects by taking points of interconnection.
FERC staff said it wasn’t evident where the RTO’s proposal detailed such a no-harm process.
“I think it deserves some business practice manuals, but that’s the idea,” Webb said.
FERC staff also asked whether MISO expects SATOA to have the same impact on the generation interconnection queue as new traditional transmission projects.
“That’s hard to put your finger on … There’s a number of possibilities,” Webb said, adding that SATOA will be able to charge to offload lines as well.
Storage solutions that function more like energy resources will not be selected through the annual MISO Transmission Expansion Plan (MTEP) and will instead have to connect to the grid through the interconnection queue, Webb said. MISO expects that the more complicated a transmission issue is, the less likely a storage facility will be able to solve it.
Webb said the RTO envisions storage would most often resolve “N-1, steady-state issues.” A battery is less likely to “be at the right state of charge” and ready for dispatch to solve rapidly emerging second contingencies. But MISO executives also said SATOAs will solve transmission issues complex enough that MISO will need functional control of the storage facility.
“We’re at the front end of this; we haven’t seen all transmission problems that storage could solve,” Webb added.
Pedersen said that, “all things being equal,” MISO would lean toward traditional wires solutions in the event of a tie because wires are historically better at mitigating stacked contingencies and currently have longer lifespans.
The RTO’s MTEP report will include the rationale for SATOAs that are selected, Pedersen said. Stakeholders can address additional questions about SATOA selection to MISO’s subregional planning meetings throughout the year. SATOA will be subject to the same planning studies required of other transmission projects.
In response to a FERC staff question about whether SATOA energy injections would impact MISO’s market-based activity, Webb said even conventional wires have some impact on the energy market.
“Anytime you change the topology of the grid … yes, there will be some impact,” he said. “We think these situations are going to be minimal.”
“It isn’t a completely new concept for transmission to affect markets,” Webb added.
MISO will develop operational guides with SATOA owners to ensure energy market impacts are minimized. He said SATOAs, non-transmission alternatives (NTAs) and traditional transmission projects all involve assurances to the RTO that projects will be completed, either through the MISO transmission owners agreement or through individual interconnection agreements.
Not Comparable
DTE Energy’s Nick Griffin, whose company is a vocal opponent of MISO’s proposal, asked why the RTO couldn’t simply ask market-based storage facilities to keep some charge reserved for transmission issues.
Webb said that discussion is best reserved for MISO’s planned discussions on dual-mode participation in 2021.
Griffin said DTE Energy continues to believe that the RTO’s proposal creates unduly discriminatory preference for transmission owners over generation owners with comparable projects.
FERC staff at the conference said they were aware of the allegations of discriminatory treatment surrounding MISO’s proposal. They asked why the RTO’s proposal was necessary since it already has rules in place for selecting NTAs in the place of transmission projects. NTAs must first clear MISO’s roughly three-year generation interconnection queue before being placed in-service, while SATOAs need only be selected in the annual MTEP process for grid connection.
“If someone came and invoked undue preference, I’m not sure how we could address it besides give them the same deal,” FERC staffer Rahim Amerkhail said.
“What we’re trying to do here is not reclassify assets and redefine revenue streams but see how we can extract extra value from storage with these specific boundaries around what is generation and transmission,” Webb said.
Clean Grid Alliance’s Rhonda Peters said she took issue with the fact that SATOAs and NTAs will be subject to different study processes that can include diverging assumptions.
Webb responded that issues stemming from the different assumptions in generator interconnection studies and MTEP studies are not unique to SATOA projects. MISO is currently working with stakeholders to better synch the two. (See MISO Begins Bid to Merge Tx, Queue Planning.)
“I think it’s really up for debate that the studies produce comparable results,” Peters said.
Responding to another FERC staff question, Webb said MISO has not contemplated a process for transitioning a SATOA to an energy market asset when it is no longer needed as a transmission resource due to load or grid changes.
“That’s something we have not bitten off in this filing,” he said.
Public Service Enterprise Group CEO Ralph Izzo said Monday it would be “logical” for New Jersey to abandon the PJM capacity market by adopting the fixed resource requirement (FRR) option.
The New Jersey Board of Public Utilities opened a proceeding to consider the FRR option in response to FERC’s December order expanding the PJM minimum offer price rule (MOPR) to all new state-subsidized resources — including PSEG nuclear units receiving zero-emission credits (ZECs) and offshore wind.
Speaking during a first quarter earnings call, Izzo said although capacity prices could be higher under an FRR, the state could see savings because the FRR would require only a 15% or 16% reserve margin. That’s far below the margins produced by PJM’s Reliability Pricing Model, which have been 24% or more for all but one of the delivery years between 2012/13 and 2020/21, according to one recent study. (See Report Slams PJM Forecasting, CONE Estimates.)
“So, the unit cost is more [under FRR], but the number of units is fewer,” Izzo said. “The product of the two turns out to be less expensive in the state.”
Turnabout?
Izzo’s comments appear to represent a shift in his thinking. During his fourth-quarter 2019 earnings call in February, Izzo was skeptical that the state would switch to FRR, saying it would be “overkill” to pull 15,000 MW from the capacity market for 7,000 MW of offshore wind. (See PSEG’s Izzo Skeptical of FRR Option.)
A PSEG spokesperson said later Tuesday that Izzo’s “`seeming change of opinion’ is not a change at all.
“The first comment related to nature of FERC’s chosen solution – that the proposed solution, to allow an FRR-type arrangement for a single unit, was not selected by FERC, and as such, an entire FRR area would be needed, which would be `overkill’ in trying to solve the stated problem. The state’s desire to not pay twice for capacity in pursuing a clean energy agenda is perfectly logical, and because of FERC’s decision, it will simply need to do so on a broader scale.”
In his remarks Monday, Izzo cited the likelihood that the 7,500 MW of offshore wind planned by New Jersey by 2035 will be unable to clear the capacity auction under MOPR. The state awarded a contract for 1,100 MW to Ørsted in June 2019; commercial operation is projected for 2024.
“If you were to … take a look at what typical Eastern MAAC capacity prices have been and then you factor in what the capacity value of the offshore wind that might be granted by PJM, you quickly get to eight, if not nine figures in just a few years in terms of extra payments on the part of New Jersey customers for not having offshore wind be able to clear the auction,” Izzo said. “So, you have this double benefit that the state could realize if it designs the FRR in a competitive way that recognizes the carbon-free resources that it is committed to securing.”
Izzo said PJM’s MOPR compliance filing proposed an avoidable cost rate (ACR) price floor for PSEG’s nuclear units “that would preserve the full bidding flexibility to clear in the upcoming PJM capacity auction.”
“If New Jersey were to implement the FRR auction in broad terms, it would provide a choice for our nuclear units and the majority of our fossil fleet to bid into either PJM’s capacity auction or into a New Jersey FRR. An FRR could be structured to have a longer tenure, a preference for zero carbon generation and would have locational delivery requirements.”
Very Likely?
“It sounds like … it’s very likely that [New Jersey] probably will go for the FRR option. Is that the way we should be thinking?” asked Glenrock Associates analyst Paul Patterson.
“Look, they’re the final decider of that,” Izzo responded. “But I think that that is the logical thing for the state to do. Why New Jersey would want to pay twice for capacity in what is obviously an extremely ambitious carbon-free energy agenda would boggle my mind. New solar and offshore wind are not going to clear the auction at these ACRs. So, I think that the state would be greatly incented to do an FRR.”
PSEG is in discussions with Ørsted on a potential acquisition of a 25% equity interest in Ørsted’s 1,100-MW Ocean Wind project and expects to make a decision this fall. Izzo said the company’s decision will not be dependent on whether New Jersey opts for an FRR.
“The state is absolutely committed to building that project,” he said. ” … So, it’s really not a question of the FRR at all. The BPU order’s quite clear on what the commercial terms of that project will be, are and will be.”
The BPU is accepting comments on the FRR option through May 20. Izzo said he expected the BPU to make a decision on the FRR no sooner than the end of the year or the first quarter of 2021. “Remember the state really doesn’t have to worry about paying double for capacity now that the nuclear units are covered for at least for the foreseeable future until offshore wind comes online, and that’s not going to happen until 2024.”
Consumer Perspective
Stefanie Brand, director of the New Jersey Division of Rate Counsel, said whether FRR would be cheaper for consumers will depend on whether the program can adequately counter the market power of generators that could supply the state. She also said costs could be impacted by whether the FRR covers the entire state or just the Public Service Electric & Gas (PSE&G) zone.
“There aren’t going to be too many companies that are going to be in a position to set up an FRR. So, there’s going to be a market power element that’s going to have costs in it,” she said in an interview Tuesday. Izzo “doesn’t include that in his equation. And it’s money that might be going to his company, so that may have been the reason why it was included” in his comments.
Brand said her office hasn’t come to a conclusion on the wisdom of an FRR and hopes to learn more from an analysis PJM’s Independent Market Monitor is doing on a potential New Jersey FRR. The Monitor issued an analysis on the impact of Exelon’s Commonwealth Edison leaving the capacity market for an FRR in December and one on Maryland’s options April 17 that concluded ratepayers are likely to see cost increases under an (FRR). (See PJM Monitor Defends FRR Analyses in MOPRDebate.)
PSE&G has suspended non-essential fieldwork while continuing emergency work during the coronavirus pandemic. | PSE&G
“We deregulated generation with the idea that competition was going to bring positive impacts in terms of [lower] prices. And it actually did for a long time,” Brand said. “We’ve kind of all been thrown into a frenzy right now. But I wouldn’t want to return to a situation where we had just a single unregulated monopoly. I don’t think that’s going to be a good outcome.”
Brand said her two biggest concerns over MOPR are how it affects offshore wind and the state’s basic generation service (BGS) auctions held by PSE&G and the state’s three other distribution utilities to provide service to customers not served by a competitive retailer.
In its April 16 order largely rejecting rehearing of its December MOPR ruling, FERC said the BGS is a “state subsidy because it is a state-sponsored process and includes indirect payments to the resource.” (See FERC: RGGI, Voluntary RECs Exempt from MOPR.)
“I don’t have a whole lot of basis to really check his math … It may end up being cheaper” to leave PJM, Brand said. “We really need a full analysis of what we think the costs are going to be before we jump to any kind of conclusion. It could be that if [nuclear generation, solar and energy efficiency] clear then we just figure out a way to deal with the offshore wind problem [separately] and stay exactly where we are right now.”
COVID Impact
Izzo also talked about the impact of the coronavirus pandemic, saying the company’s PSE&G and PSEG Long Island units — which serve some of the areas with the highest incidence of confirmed COVID-19 cases — have suspended non-essential fieldwork while continuing emergency work.
Izzo said infection rates among PSEG’s 13,000 employees are below those for New Jersey and Long Island as a whole. About 1% of the workforce is currently self-monitoring.
The company is continuing its work on critical energy infrastructure projects although PSEG’s nuclear team reduced the scale of the current Salem Unit 2 refueling outage to protect all workers at the site, which also includes Salem Unit 1 and Hope Creek.
PSEG’s nuclear team reduced the scale of the current Salem Unit 2 refueling outage to protect all workers at the site, which also includes Salem Unit 1 and Hope Creek.| PSEG
Izzo said that the pandemic could result in “lumpy” access to mutual aid resources, noting that during a recent storm the company was able to secure only about 40% of the assistance it sought from other utilities.
“It was a combination of, candidly, utilities not willing to risk their own employees in terms of their exposure … and travel limitations put on some of the contractors,” he said. “So, if we have that experience when the trees all have leaves on them and the wind blows, then we will have to communicate extensively with customers about some of the likely delays that they will experience in being restored.”
Earnings
PSEG reported non-GAAP operating earnings of $520 million ($1.03/share) in the first quarter, a drop from $547 million ($1.08/share) in 2019. Net income under GAAP was $448 million ($0.88/share) compared to $700 million ($1.38/share) in Q1 2019.
The company said its results were aided by rate-based expansion from transmission and distribution investments at PSE&G and ZEC revenue for PSEG Power, which added $0.07/share.
Those gains were offset by a scheduled decline in capacity prices, which reduced operating earnings by $0.11/ share, and the second mildest first quarter ever recorded in New Jersey.
Photo shows damage from a storm in South Jersey in April. PSEG said it received only 40% of the mutual aid assistance it sought from other utilities because of the pandemic. | PSE&G
PSE&G said pandemic stay-at-home orders caused a weather-normalized decline of 5% to 7% in electric load from the end of March through April. It said the ranges and the mix of usage among residential, commercial and industrial customers are imprecise because New Jersey lacks advanced metering infrastructure. (Izzo said the company hopes to complete BPU proceedings allowing it to spend $600 million on advanced metering infrastructure and $400 million on electric vehicle energy storage programs by early next year.)
Chief Financial Officer Daniel J. Cregg said that although PSE&G temporarily suspended all non-safety-related service shut-offs for non-payment during the COVID-19 crisis, the company can recover bad debt expenses through the state’s “societal benefits charge.”
Beginning June 1, the average PJM capacity price will rise to $168/MW-day from $116/MW-day, Cregg said. A scheduled decline in ISO-NE capacity prices will be partially offset by its nearly year-old Bridgeport Harbor 5 plant, which has a seven-year capacity lock at $232/MW-day.
PSEG Power has hedged more than 95% of its production at an average of $36/MWh for the remainder of 2020. It has hedged more than 55% of forecasted production at an average of $35/MWh for 2021 and more than 25% of output at $35/MWh for 2022.
In announcing first-quarter earnings that beat expectations, Vistra Energy CEO Curt Morgan said Tuesday that the company took steps early in the year to prepare its operations for the harm wrought by the COVID-19 coronavirus.
“I never thought I would be hosting an earnings call from my home with my management team dispersed across the [Dallas-Fort Worth] Metroplex,” he said during Vistra’s first-quarter earnings call with financial analysts. “Yet, that is where we find ourselves today in these challenging times.”
Vistra reported adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) of $850 million, as compared to $824 million for the first quarter of 2019. The company reaffirmed its 2020 adjusted EBITDA guidance range of $3.29-3.59 billion.
The Irving, Texas-based company uses adjusted EBITDA as its performance measure, saying this helps investors analyze the business.
In February, Vistra began suspending non-essential business travel and restricted access to corporate offices and plants. Morgan said the company was one of the first to test employees’ temperatures and use entry questionnaires at its facilities. He credited its proactive measures with completing or being on schedule with 86 maintenance outages at its Luminant plants “to ensure plant reliability for the critical summer months ahead.”
“Had we been levered like the [independent power plants] of the past, like back in 2016 when we emerged from bankruptcy, we may be having a very different discussion today,” Morgan said, a reference to its Energy Future Holdings predecessor, which eliminated $33 billion of debt before transitioning to its current form. (See Luminant, TXU Energy Emerge from Bankruptcy.)
Luminant’s Odessa-Ector gas-fired power plant | Luminant
Morgan said about 70% of its adjusted EBITDA comes from the ERCOT market, which — as in the aftermath of the 2008-09 recession — “is proving to be relatively resilient.” ERCOT tweeted on Tuesday that its recent weekend peaks “appear” to have returned to pre-COVID levels and its weekday peaks are now down only 2%.
“We believe Vistra Energy is well-positioned to deliver strong financial results in 2020, even in the face of lower demand driven by COVID-19,” Morgan said.
Vistra’s share price opened Tuesday at $20.68 following the earnings release but finished the day down at $18.72. Shares had closed Monday at $19.01.
At its quarterly meeting Tuesday, NERC’s Operating Reliability Subcommittee decided to cut back its weekly schedule of conference calls focused on the COVID-19 outbreak. Calls planned for this week and May 13 were canceled, and the team agreed to move to biweekly discussions following the next scheduled call on May 20.
ORS Chair Chris Pilong, of PJM, suggested the coronavirus meetings could be scaled back — though not eliminated entirely — because registered entities have largely settled into their pandemic response plans and there are “enough other calls going on between companies that we don’t need to hold the pandemic call” as frequently. Future calls to discuss new developments will be held every other Wednesday at 2 p.m.
GSE Communications Plan Nearing Completion
The group developing communications procedures to be used during a grid security emergency (GSE) is preparing to finalize its recommendations and hand them off to NERC for implementation.
The GSE Communications Project was created last year based on the North American Transmission Forum’s (NATF) work implementing the 2015 Federal Power Act, which enables the Energy Secretary to determine if emergency measures are necessary upon presidential declaration of a GSE. Such declarations are available in the case of physical, cyber or electromagnetic pulse attacks or in the case of geomagnetic disturbances. They are not permitted in response to natural disasters.
Efforts by the GSE communications team have focused on leveraging existing communications protocols used to share strategic and long-term goals between the Department of Energy and reliability coordinators (RCs). Their plan is to expand these pathways to share shorter-term operational communications as well, through avenues with which both participants are already familiar.
“We’re trying not to introduce new things,” said Lynna Estep of NATF. “We want to use the RC hotline as much as possible [and] we want to use the RC emergency conference call processes, but just tailor [them] for GSE … We’re not trying to change any of that, we’re just trying to add a layer [to] make sure we have what we need for the DOE to communicate to us during this very specific type of event.”
ORS members asked the development team to make sure their outline provides a realistic role for both the government and RCs. In particular, John Norden of ISO–NE reminded the team to factor in the response time of RCs and not create expectations that they will “turn around and just execute” government instructions. In response, Sam Chanoski, director of threat intelligence for the Electricity Information Sharing and Analysis Center, noted that the development team is “ahead of where the government is” and can hopefully lead the way in setting expectations.
The GSE elements of the Federal Power Act have not yet been exercised, and Estep emphasized that her team is focused on ensuring the grid is not caught unprepared the first time. She pointed to the ongoing pandemic to illustrate the benefits of ensuring preparedness.
“I was on a call earlier today, and as many calls today go, it [went] to COVID-19. And one of the comments made was [that] if we hadn’t had some pandemic plans made ahead of time, then we would have been in a really bad place,” she said. “I see this being the same way … It may not be absolutely perfect, especially because we’re working with some unknowns here, but we need to have something in place.”
ORS, SMS, Could Merge in RSTC Reorganization
The COVID-19 outbreak has complicated the introduction of NERC’s new Reliability and Security Technical Committee (RSTC), but the group still plans to take over the operations of the Planning, Operating and Critical Infrastructure Protection Committees as scheduled in June. The committee’s June 10 meeting, which was planned to take place at NERC headquarters in Atlanta, has now been changed to a webinar in accordance with the organization’s coronavirus response policy. (See “Robb Delivers COVID-19 Update,” Align Tool Set for 2021 Rollout.)
Since its first official meeting in March, the RSTC has been holding weekly conference calls to bring its members up to speed on the work of the retiring committees. (See RSTC Tackles Organization Issues in First Meeting.) Leadership felt this was necessary to ensure that important matters are not lost in the transition to a smaller structure.
“Right now we’re in the process of reviewing the existing subgroup organization and work plans … to ensure continuity from the technical committees to the RSTC,” said Stephen Crutchfield of NERC. “We have a few people on the RSTC that were not on any of the technical committees before, so this is to make sure that they’re aware of things that come up on a routine basis.”
The committee has also been ironing out details of how RSTC meetings will be structured, as well as how to take reports from the existing committees’ various subcommittees and working groups without overwhelming the agenda in routine items.
While most subcommittees are expected to continue their work as usual, reporting directly to the RSTC instead of their previous committees, leaders of the Synchronized Measurement Subcommittee (SMS), presently under the Planning Committee, are currently in talks to merge their group with the ORS. SMS Vice Chair Tim Fritch said the idea was inspired by his group’s recent work helping to analyze outage events, which leadership saw as an indication that it could be more helpful on the operational side than in a planning role.
“It seems like there’s more efficiencies and effectiveness with us being more tied in to the ORS, and we can help more with these events that we’ve seen. We know there will be more coming forward as we have more data and more devices to monitor the system,” he said.
SPP’s Board of Directors last week approved the first two revision requests stemming from the Holistic Integrated Tariff Team’s (HITT) 15-month effort to help the grid operator adapt to the evolving grid and electricity markets.
Gathering virtually for its first meeting since the COVID-19 outbreak began, the board on April 28 signed off on both measures. The changes were previously advanced by the Markets and Operations Policy Committee, Strategic Planning Committee and Regional State Committee.
SPP Chair Larry Altenbaumer opens the virtual April board meeting from his home office.
RR 391, which establishes uniform local planning criteria within each transmission pricing zone under the Tariff’s Schedule 9, received pushback, in line with the frequent tension between transmission owners and customers in SPP’s 19 zones.
As written, RR 391 places the responsibility on the zone’s host TO to facilitate a “consensus-driven” criteria for reliability upgrades, rather than have individual TOs submit their local planning criteria to SPP, to ensure all customers in the zone pay equally for the same types of transmission upgrades. Schedule 9 calculates network service request charges as a ratio share of the monthly annual transmission revenue requirement.
For many transmission customers, the issue was the loss of the words “collaboration” and “consensus” in the RR’s final language.
Golden Spread Electric Cooperative’s Mike Wise said the RR failed to convey the HITT report’s intent.
“The language did fall short,” said Wise, a HITT member. “We spent a huge amount of time discussing how the host utilities in a zone should develop a collaborative process. Certainly, the language should have been a consensus-driven process within each zone. Neither of those words showed up anywhere, and I think we fell short because of that.”
“As a [transmission and distribution user], a small transmission customer being invited to a meeting is one thing. Having your opinion heard or taken into consideration is two completely different things,” Oklahoma Municipal Power Authority General Manager David Osburn said. “I’d like to see a little more teeth, to see the [TDUs] and customers have more meaningful input in the process.”
“The Tariff language … simply requires the big utility in the zone, or the [facilitating TO] to call a single meeting and, based on that, file or not file zonal planning criteria that the FTO determines to be in their best interest,” said consultant Jack Madden, who represents several Texas cooperatives. “We believe this is a far cry from what was hammered out during the HITT discussions.”
Antoine Lucas, SPP’s vice president of engineering, tried to clarify matters by pointing out that it’s up to the entities within the zone to reach agreement.
SPP’s transmission pricing zones | SPP
“Nothing in this language prohibits TOs in the zone from working together to define what consensus means to them and how they want to organize themselves,” he said. “We want to ensure everyone in the zone will have comparable criteria.”
Osburn and three others on the Members Committee voted against RR 391. Wise abstained.
The second Tariff change, RR 401, faced a smoother path to approval, with only one abstention. The measure replaces credits under Tariff Attachment Z2 for certain network upgrades with incremental long-term congestion rights (ILTCRs). It replaces a previous attempt to change the Tariff, which was rejected in January by FERC Order Keeps Z2, Aids EDF’s Sponsored Project.)
Dan Simon, outside counsel for EDF Renewables, spoke out against the measure as he has during previous stakeholder groups, saying SPP’s current ILTCR rules are “inadequate.”
“I think most people would agree. No one has selected the ILTCR option,” he said, calling for SPP to improve the ILTCRs “so they’re more in line with other RTOs.”
SPP staff wasted no time in filing the change at FERC, doing so the day after the board meeting and asking for an effective date of July 1.
The HITT concluded its work last year, handing off its 21 recommendations to various stakeholder groups. The recommendations encompassed four categories: reliability, marketplace, transmission planning and cost allocation.
Directors Suspend Competitive Upgrade
The board sided with recommendations from SPP and the Oversight Committee to suspend a previously approved competitive interregional upgrade, pending negotiations with the seams partner and FERC approval.
The 345-kV Wolf Creek-Blackberry project in Kansas and Missouri was approved by the board last year and included in the 2020 SPP Transmission Expansion Plan, which the board passed in January. Part of the 105-mile project, projected to cost $152 million, would be on the Associated Electric Cooperative Inc. (AECI) transmission system and constructed by AECI.
Because AECI is not a TO under SPP’s Tariff, staff must reach an agreement with it to outline the project’s scope and define cost allocation for its work. The entities have agreed to a joint study schedule to conclude in May, after which they would finalize an agreement that must be approved by FERC before SPP can allocate funds to AECI for the latter’s portion. (See “SPP, AECI Agree to Joint Study,” SPP Seams Steering Committee: April 2, 2020.)
The OC said were SPP to commence its competitive process and issue a request for proposals without reaching an agreement with AECI, “there is significant risk that millions of dollars would be spent on a [competitive selection process] that results in nothing.”
SPP COO Lanny Nickell said were the project not suspended, staff would have to meet a Tariff deadline and begin the RFP process by July without a negotiated agreement and FERC approval in hand.
“There are risks associated with not suspending the project and beginning the RFP process,” Nickell said. “It could impose costs on members if AECI does not ultimately agree to what they have to do on their end.”
For the time being, AECI is projected to spend up to $2 million on a substation. “But if other upgrades are needed to accommodate this request, that opens up a whole series of discussions with AECI and our members, because that would create additional costs,” Nickell said.
Wise said he thought the OC made the correct decision.
“This falls in line with what I’ve been advocating, which is achieving a higher degree of quality in transmission buildouts,” he said. “These are 40-year assets that have to be paid by all consumers in the footprint. We need to ensure AECI pays its fair share.”
“The idea to initiate a process where the clock would be running, and those members wanting to participate would have to start spending time and money to develop a bid, doesn’t seem prudent,” said Brett Leopold, with independent transmission utility ITC Great Plains.
“This project can still be suspended or canceled at a later date if it’s not deemed to be right,” Evergy’s Kevin Noblet said. “Sending an RFP out on the street when the only thing at risk is a few hundred thousand dollars, if that, seems like a risk worth taking.”
Evergy was one of four member companies to oppose the recommendation. Two other members abstained.
COVID-19 Alters Sugg’s Transition Plan
Delivering her inaugural CEO report to the board and committee, Barbara Sugg had to admit her transition into the position held for 16 years by the retired Nick Brown was “not exactly turning out like I had expected.”
Sugg, who was selected to replace Brown in January, had intended to spend much of her first 90 days in the role traveling across the footprint and visiting with SPP’s many stakeholders. (See Sugg Prepares to Take ‘Dream Job’ at SPP.)
Those plans were waylaid by the COVID-19 pandemic after she had met with a dozen different companies.
“The roadshow stopped just as soon as it started. I’m really disappointed I had to cancel many of those meetings,” she said. “COVID-19 may have sidelined me right now, but I look forward to getting back on the road.”
Sugg has continued to conduct virtual meetings and has made individual calls with each of the regulatory commissioners in SPP’s footprint. “It’s good for those commissioners to hear from me so we can start building trust and respect that is mutual.”
Saying it’s “inevitable” that an employee will eventually test positive for COVID-19, Sugg said, “We continue to hope for the best and prepare for the worst.”
There is a silver lining to the pandemic. With the reduction in travel and meeting expenses, SPP has over-recovered about $2.5 million in administrative fee revenues through March. Sugg said that with “lots of meetings planned to be virtual for many months to come,” that number will grow.
However, the pandemic has also resulted in lower demand, “putting pressure on 2020 rates,” she said. SPP has also incurred about $340,000 in net savings by increasing and using the engineering staff, rather than consultants, to manage the interconnection queue.
Sugg said resolving seams issues with SPP’s neighbors remains one of the grid operator’s key goals. “We remain committed to win-win solutions on the seams,” she said.
Lowest Prices Ever for Integrated Marketplace
Keith Collins, executive director of the SPP Market Monitoring Unit, shared with directors and members a draft of the 2019 State of the Market report that found the footprint’s energy prices were the lowest since the Integrated Marketplace went live in 2014.
Day-ahead prices averaged about $22/MWh and real-time prices averaged about $21/MWh, down from $25/MWh in 2018, Collins said. With gas prices below $2/MMBtu, also among the lowest since 2014, natural gas-fired resources frequently set market prices.
Collins also said the region’s frequently constrained areas have all been removed, partly because of transmission additions that have shifted congestion and leveled the footprint’s market prices. He said the MMU believes Central Oklahoma and the Tulsa area could potentially become frequently constrained areas in the future.
SPP’s energy prices are the lowest since the Integrated Marketplace went live in 2014. | SPP Market Monitoring Unit
According to the report, the reliability unit commitment process’ make-whole payments rose 55% to nearly $70 million last year. Collins attributed the increase to more resources being brought on from the RUC processes, including manual commitment for capacity needs.
The MMU also said wind generation continues to catch up with coal. Wind resources accounted for 27% of all generation in 2019, up slightly from 23.5% the year before. Coal generation, meanwhile, fell from 42% in 2018 to 35% last year.
The report outlined recommendations for SPP’s market, including improving price formation during emergency and scarcity conditions, improving outage coordination, increasing flexibility and enhancing the ability to assess a range of transmission planning outcomes.
Collins said the MMU has noticed several concerning trends, including a 70% increase in scarcity intervals, increased negative pricing during the overnight hours, and increased generator outages and emergency conditions.
“Scarcity intervals highlight an increase in the volatility that occurs in the real-time market,” Collins said. “It’s driven by short-term, ramping-related scarcity events that happen on the system. That’s why we’ve been supportive of ramping products.”
The MMU’s market-enhancing recommendations include improving price formation during emergency conditions and scarcity events, incentivizing capacity performance, and updating and improving outage-coordination methodology.
“It’s important to set proper prices during these types of events,” Collins said. “Scarcity events are actually reflecting events that are happening on the system. You want the power flowing in the right direction, particularly when scarcity events occur.”
SPP has already formed the Generator Outage Task Force to improve outage coordination.
Staff Strengthening TCR Credit Practices
Director Graham Edwards, chair of the Finance Committee, said the Credit Practices Working Group (CPWG) has spent the last 18 months trying to strengthen the use of credit in SPP’s transmission congestion rights (TCR) market. The work follows the 2018 GreenHat Energy default in the PJM market, which left members liable for more than $100 million. (See FERC Orders PJM to Unwind GreenHat Settlements.)
The group is recommending increasing the minimum capitalization for participants in the TCR market to either at least $20 million in assets or $10 million in net worth, or by increasing alternative collateral requirements. The CPWG is also recommending a strengthened credit application and minimum collateral on all TCR portfolios.
The Finance Committee has approved the recommendation and sent it through the stakeholder process for Tariff language development.
The board approved the committee’s recommendation that it accept accounting firm BKD’s 2019 audit report and findings. BKD said it did not find any issues or concerns in its review of SPP’s accounting practices.
Digital Release for 2019 Annual Report
The virtual meeting marked another break in tradition for SPP. The RTO’s annual report was posted digitally instead of being placed in each director and member’s chair.
Entitled “Integration,” the report includes former CEO Brown’s final introductory message and focuses on the five major initiatives facing SPP: seams issues, transmission, Western expansion, the HITT recommendations and providing member value.
Consent Agenda Includes Exit Fee Changes
The board’s consent agenda, unanimously endorsed by the committee, included revisions to SPP’s bylaws and membership agreement that define the exit fees for transmission-owning and non-transmission-owning members upon their withdrawal.
FERC in December scuttled SPP’s alternative proposal of a $100,000 exit fee and rejected a rehearing request. It also directed the RTO to make a compliance filing that ensures non-TO members pay a lower fee should they leave (EL19-11). (See FERC Denies Rehearing of SPP Exit Fee Decision.)
Other items on the consent agenda included:
An amendment to the membership agreement that allows Roughrider Electric Cooperative, embedded in the Integrated System as a Basin Electric Power Cooperative member, to join SPP as a TO. Roughrider, a non-transmission-owning member of SPP as of April 30, will transfer functional control of its transmission facilities to the RTO, pending FERC approval. The IS joined SPP in 2015. (See Integrated System to Join SPP Market Oct. 1.)
The nomination of Kansas Electric Power Cooperative CEO Suzanne Lane to the Human Resources Committee.
Revising the Corporate Governance Committee’s scope to use independent executive search firms to replace a director or fill a vacancy on the board.
Baseline resets for five previously approved transmission projects. (See “Members Approve 1 RAS, Retirement of Another,” SPP MOPC Briefs: April 14, 2020.)
The PJM Markets and Reliability Committee deferred a vote on a proposed issue charge to consider rule changes for hybrid resources after members questioned the RTO’s plan to assign it to a new senior task force.
PJM has more than 10,000 MW of co-located generation and energy storage hybrid resources in the interconnection queue. RTO staff intend to focus the effort primarily on solar-battery hybrids, which represent more than 95% of the total, with the remainder wind-battery and gas-battery.
Since introducing the issue charge at the March MRC meeting, PJM added to the education topics the interconnection queue process for hybrids, including how existing material modification rules apply. It also pushed the start date from May 1 to July in response to concerns over the MRC’s workload. (See PJM MRC Moves Forward on Storage, Hybrids.)
PJM’s Scott Baker said staff recommended creating a senior task force because of the varied issues raised by hybrid configurations. “There’s enough cross-functional [issues] here between planning, markets and operations to warrant this being a separate group,” he said.
Under Manual 34, a senior task force reports to a senior standing committee (the MRC or Members Committee) and is created for “consideration of specific issues that have the potential for large dollar or major policy impacts.”
Dayton Power & Light’s John Horstmann said that while he supported the initiative, it should be a task force under one of the standing committees — the Market Implementation Committee, Operating Committee or Planning Committee — rather than a senior task force.
“To the extent it crosses MIC, OC or PC interests, there is no reason the other committees can’t be invited” to the meetings, he said.
PJM’s Dave Anders acknowledged that the RTO has had “a bit of a struggle” with assigning new projects because of conflicts between concept and practice.
“In theory, we could invite others to a task force under the MIC, but in practice that doesn’t always happen,” he said. “The senior task force seems to get more attention and … participation.”
Horstmann said he was “frustrated” because he and others in the Stakeholder Forum “met for quite a few months to develop clearer” rules for such assignments in Manual 34.
“We think we’ve fixed this problem, but it hasn’t been presented to members for endorsement,” he said.
After discussion, MRC Chair Stu Bresler decided to defer action on the issue charge so staff could reconsider the assignment.
Horstmann explained after the meeting that the members created a table for inclusion in Manual 34 listing “the different types of stakeholder groups with a description of their function and use, including the expected length of time that they would meet.”
Emerging Technologies Subcommittee Proposed
Stakeholders also expressed concerns about the reporting structure for a new Emerging Technologies Advisory Subcommittee (ETAS) that PJM proposed to support its Advanced Technology Pilot Program (ATPP). The ATPP provides a testing ground for studying the viability of integrating new technologies that could enhance system reliability, operational and market efficiency, and resilience.
Eric Hsia of PJM reviewed the subcommittee’s charter, which the MRC will vote on May 28. Hsia said PJM was acting on the issue based on stakeholder feedback and the RTO’s recognition that it currently doesn’t have a forum to discuss emerging technologies and pilot programs.
The subcommittee would identify operational, planning and markets-related issues and make recommendations, Hsia said. In addition to hosting technical education sessions on emerging technologies, it would create and review ATPP procedure documentation to incorporate stakeholder feedback into the process and provide additional transparency. PJM would continue to maintain authority over the ATPP, and the subcommittee would not make decisions on selecting specific pilot projects. The group also would identify benefits of new technologies and obstacles to implementing them.
Gary Greiner, director of market policy for Public Service Enterprise Group, said he supports the idea but that the subcommittee should not report to the MRC, as proposed.
“I think most of what you’re going to see would be operations-based. I’m wondering why it wouldn’t be down at the standing committee level,” he said. “I really think there’s value in having those issues pass through that lower-level layer to be fully vetted.”
Hsia said staff did discuss having the ETAS report to a standing committee but decided on the MRC as its parent because of “the nature of pilot programs and the cross-functional nature of the discussions.” Many issues that come before the new group would involve planning as well as operations, he said.
Paul Sotkiewicz of E-Cubed Policy Associates asked if there was a way to combine the solar hybrid resources issue previously discussed with the ETAS as a way to pare down the number of stakeholder groups.
“It’s just becoming unwieldly to follow all of the committees at this point,” Sotkiewicz said.
Bresler, PJM’s senior vice president of market services, said the location of the committee is “one thing we’ll examine prior to bringing this back for a vote.”
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the ETAS will help stakeholders understand the functionality and benefits of emerging technologies.
Poulos noted that Thursday’s MRC agenda included several emerging technologies, including hybrid storage and HVDC converters.
“I’m glad that PJM is getting ahead of this,” Poulos said.
‘Credit’ Subcommittee Proposed to Change to ‘Risk Management’
PJM gave a first read to a proposal to rename the Credit Subcommittee as the Risk Management Subcommittee and amend its charter to broaden its authority to include market risk.
Under the revised charter, the renamed subcommittee also would be elevated, reporting to the MRC rather than the Market Implementation Committee. Chief Risk Officer Nigeria Poole Bloczynski said the change would acknowledge that the broader consideration of risks “may incorporate aspects outside of the sole purview” of the MIC.
Anders said the restructured group would be a venue for considering risk management as a wholistic topic. He previously said the subcommittee — which hasn’t met since December 2018, as members have focused their efforts on the Financial Risk Mitigation Senior Task Force in the wake of the GreenHat Energy default — was the best venue for considering a planned problem statement over a credit risk issue the RTO identified in February. (See “Scope, Name Change for Credit Subcommittee?” PJM MIC Briefs: March 11, 2020.)
Bloczynski noted the committee’s charter has not been revised since 2010.
“Risk management seems to be an afterthought. No one thinks about it until there’s a problem,” she said. The MRC will be asked to endorse the revised charter at its next meeting.
The revised mission statement says the committee will “discuss and recommend” ways to address market and credit risk issues. It will not “manage, govern or otherwise set policy for PJM.”
Sharon Midgley of Exelon said she thought the charter change should be considered in tandem with how it will potentially impact the scope of the MIC.
“Anything that we’d talk about credit or markets related at this committee, we’re going to want to make sure that the participants in the MIC are aware of it because that impacts them as well,” Midgley said.
Greiner said he views “market risk” as a term that can be defined differently depending on who is being asked. He said he would like to see PJM put a clear definition of the term in the charter.
“If you have a definition for market risk, it’s going to help inform the scope of what we’re doing here,” Greiner said. “I think it’s probably best to embed it in the charter itself so we can get a sense of what’s in and what’s out.”
Sotkiewicz encouraged PJM to include market design risks in the scope of the charter. He said having a core group of PJM staff and possibly stakeholders working together to look at market designs and finding problems that are there before they turn into a major issue that results in a FERC filing or a financial hit to membership would be of great benefit.
“Those risks are always going to be out there, and if we can get ahead of the game, we in the membership would be much better off,” Sotkiewicz said.
Surety Bonds
The MRC heard a first read of a proposal to allow market participants to use surety bonds as collateral.
Bonds can be less expensive than letters of credit but are dependent on the credit and risk profile of the market participant, PJM said.
The MIC endorsed two proposals in October 2018, with 61% supporting use of surety bonds as collateral for all market purposes except financial transmission rights, with a $10 million cap per issuer for each member and a $50 million aggregate cap per issuer.
A second proposal allowing surety bonds as collateral for all market purposes including FTRs won 58% support. It would set a $20 million cap per issuer for each member and a $100 million aggregate cap per issuer. PJM said it supports the first proposal, citing limited experience in the use of surety bonds in FTR markets and the large size of past FTR defaults.
In December 2018, the MRC agreed to defer action on the proposals until completion of the independent consultants’ report on the GreenHat default. It was deferred again in April 2019 pending appointment of a chief risk officer and appointment of a new CFO.
If the Tariff change is approved, PJM said it will require use of bond companies on U.S. Treasury Department’s certified list and a minimum credit rating of A with S&P Global Ratings; A with Fitch Ratings; A2 with Moody’s Investors Service; or A with AM Best. PJM also will require acceptance of one-day payment demand terms.
The MRC will consider endorsement on May 28, with the MC taking it up in June.
Governing Documents Cleanup
In its only voting action aside from approving the minutes for the MRC’s March meeting, the committee approved administrative revisions to the PJM Tariff, Operating Agreement and Reliability Assurance Agreement, as recommended by the Governing Document Enhancement & Clarification Subcommittee.
PJM stakeholders debated for nearly two hours Thursday over transmission owners’ spending on end-of-life (EOL) projects, suggesting there is little chance for compromise on an issue that has been disputed for years within the RTO.
Three EOL proposals were given first reads at Thursday’s Market and Reliability Committee meeting, setting up votes at the next MRC meeting on May 28. The proposals — which would require TOs to share how they make EOL determinations and potentially open at least some replacement projects to competition under the Regional Transmission Expansion Plan (RTEP) — are the result of deliberations over six special MRC meetings since December.
Three Proposals
A proposal by a group of PJM stakeholders, including American Municipal Power and Old Dominion Electric Cooperative, would require TOs to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date so that the project could be included in five-year planning models and opened to competitive bidding. It would also modify the supplemental project definition to exclude EOL projects, which would be made a new category of regionally planned projects. It was endorsed by the PJM Industrial Customer Coalition, the Public Power Association of New Jersey, Consumer Advocates of the PJM States (CAPS) and the D.C. Office of the People’s Counsel.
LS Power supports the stakeholder package but would require six years’ notice for lower-voltage facilities and at least eight years’ notice for facilities of 230-kV and above.
PJM also offered a package requiring TOs to identify EOL projects five years in advance. Projects that “overlap” with RTEP violations would be included in a competitive window seeking regional solutions. Like the stakeholder and LS Power plans, PJM’s proposal would require each TO to have a formal program for EOL determinations. The RTO said it would prevent TOs that don’t already have a EOL determination process from using a “run to failure” asset management approach.
Under current rules, said Mark Ringhausen, vice president of engineering for ODEC, some TOs don’t identify EOL projects, choosing instead to replace “pieces and parts.”
“Some have told me that they never make EOL determinations,” Ringhausen said.
Divergence of Plans
But PJM disagreed with the stakeholder proposal on the RTO’s jurisdiction over EOL facilities, saying the Consolidated Transmission Owners Agreement (CTOA) transferred to PJM only the responsibility to prepare an RTEP “for the enhancement and expansion” of the transmission system to meet demands for firm transmission service. Section 5.2 of the CTOA says, “PJM shall not challenge any … sale, disposition, retirement, merger or other action.”
Dave Souder, PJM senior director of system planning, said the proposal honors the TOs’ responsibility over asset management decisions while allowing the RTO to determine when an RTEP project is more cost-effective than a TO’s proposed replacement. “We believe the PJM package takes a reasonable approach,” he said.
Several parties, including AMP and ODEC, insisted the FERC rulings do not preclude their proposal. They said the PJM proposal lacks transparency and would not require TOs to have EOL criteria or to share the list of EOL projects with stakeholders. Souder said PJM hasn’t decided whether the retirement list would be public.
Ed Tatum, AMP’s vice president for transmission, said PJM data from 2019 show $4.8 billion in TO supplemental projects, about 75% of which are for EOL assets that could benefit from longer-range planning. Robert Taylor of Exelon said he disagreed with the $4.8 billion statistic, saying the dollar amount appeared to combine supplemental and baseline projects, inflating the number by as much as $1.5 billion.
Tatum conceded that the retirement of a transmission asset should be determined by the TO that owns it. But he said PJM should take over planning once a retirement decision is made.
“Asset management includes operational maintenance activities, as well as the decision as to when an asset has reached the end of its life,” Tatum said. “But asset management ends at that point, and planning begins. … We need to have the assurance that this is being planned by an independent organization that is not bound by its stockholders to put together a construction project.”
“We’re supposed to be working together and not going straight to legal arguments,” Poulos said. “The stakeholder process does not work if we’re just going to go to FERC with things.”
Alex Stern of Public Service Electric and Gas said TOs worked hard for a compromise problem statement and issue charge when EOL was brought up at Planning Committee meetings last year but that an agreement could not be reached. (See PJM Members Debate Dueling Tx Replacement Plans.)
Stern said he still had hope that a compromise could be reached during the special stakeholder process in the MRC over the last five months. But he said the packages that emerged are an attempt “to leverage the stakeholder process” to force PJM to make a filing at FERC that individual stakeholders should be making themselves.
“If stakeholders want to challenge the FERC-approved paradigm governing the authority of TOs to make determinations regarding the end of the useful life of their asset … there’s absolutely nothing stopping them from doing so,” Stern said.
John Horstmann of Dayton Power & Light agreed, calling the EOL stakeholder meetings a “scorched-earth process” to force PJM into a Federal Power Act Section 205 filing. Horstmann said the issue should have been brought to FERC as a Section 206 filing rather than going through the stakeholder process.
Stakeholders filing under Section 206 must first prove the RTO’s existing rules are unjust and unreasonable to win FERC approval of changes. A PJM filing under Section 205 would not need to make that showing, needing only to convince the commission that its new rules are just and reasonable.
The Members Committee has Section 205 filing authority over the Operating Agreement (OA); the PJM Board of Managers has Section 205 authority over the Reliability Assurance Agreement and the Open Access Transmission Tariff (excluding provisions under the exclusive control of the TOs).
The stakeholder and LS Power proposals would require changes to the OA.
PJM said its proposal would only require manual changes. LS Power’s Sharon Segner disagreed, saying FERC Order 1000 requires such planning process rules be included in the OA. She also said the PJM proposal fails to eliminate “redundancy between the supplemental and regional planning process” that would require an OA fix.
Stern said the focus on EOL by some of the stakeholders seems to be less on planning criteria and appropriate decision-making to ensure local and regional grid reliability, and more on the dollar amount being invested. He said transmission decisions are supposed to be made on ensuring the reliability of the grid and not the cost.
“PJM certainly has a role to play in planning, but it is not to decide how a transmission owner goes about addressing the impact of the end of useful life of an asset,” Stern said.
Tatum said he agreed with Stern’s assertion that planning shouldn’t be based solely on costs. But he said he would have more confidence that projects were being done in the most cost-effective way if PJM was conducting the planning.
Tatum said the TOs “unfairly discount” the importance of the PJM stakeholder process and the rights of the rest of the stakeholders. He said that since the inception of PJM as an RTO, the TOs demanded many of the provisions in the OA so they could have control over the new entity that was being developed.
“It’s not just [TOs that are] concerned about reliability and keeping the lights on,” Tatum said. “We all have a vested interest in that. But we see a majority of planning being driven outside of [the RTEP] process. Independent planning is essential in order to have successful markets, and we’re moving away from that.”
Susan Bruce, representing the PJM ICC, said industrial customers have seen their transmission bills increase “exponentially” over the past two years, largely because of EOL costs. Aligning the EOL asset management process with RTEP would ensure the transmission investments being made are cost effective and well planned, she said.
“Industrial customers want to see a reliable and robust grid, but they also want to make sure that their investment in transmission is optimized,” Bruce said.
Costs
Citing PJM statistics, Horstmann said that only 30% of the RTO’s transmission system is less than 40 years old, causing a glut of assets nearing their EOL that must be replaced. He said a high price tag is inevitable no matter who oversees the planning.
“You’re looking at a lot of money over the next period of years to basically maintain what we have, let alone improvements,” Horstmann said. “To me, that’s the elephant in the room here. This [dispute] just sort of dances around the edge of that problem.”
Tom Hyzinski of GT Power Group asked how much would be saved by identifying EOL projects six years in advance and making it subject to competitive bidding.
PJM’s Jim Gluck said the MRC will schedule one more special session (May 11 or May 15) to discuss the packages and seek opportunities for consensus before the three proposals are brought to sector-weighted votes May 28. The package with the most stakeholder support and meeting the two-thirds threshold will be brought back to special meetings to draft governing document language. The package receiving the greatest support will become the main motion for a vote of the MC.
PJM could support the loss of up to 40% of installed generation capacity on a summer day and up to 60% on a spring day in a worst-case scenario situation in which units were knocked offline from a COVID-19 outbreak among plant workers, the RTO said last week.
Ray Lee, senior engineer in generation, and Jason Sexauer, senior engineer for outage analysis technologies, presented the generator availability analysis to stakeholders during PJM’s weekly coronavirus call Friday.
Lee said the analysis was intended to determine the maximum generation loss PJM could handle without curtailing power to the hardest hit areas. The analysis began by considering the impact of an outbreak at one plant spreading and disabling a generating company’s entire fleet, he said.
Sexauer said the 40% and 60% outage levels in the scenario are about twice as many outages as typically occur during summer and spring. “These scenarios are worst case, far and above what we normally screen for from an operational perspective,” Lee said.
An overlay map of generators located within the PJM footprint compared with cases of outbreaks of COVID-19 | PJM
PJM has not seen any generator outages from the pandemic thus far, they said.
Analysts used overlay maps to compare the highest levels of COVID-19 infection within the PJM footprint with generator locations, Lee said, focusing specifically on New Jersey, the Interstate 95 corridor from New Jersey to D.C., and Chicago and its suburbs.
Lee said coal-fired and combined cycle plants were judged most likely to be impacted by an outbreak because they require higher numbers of on-site personnel to operate.
The final step in the planning process was to define the appropriate time frames for outbreaks at the sites, Lee said.
Because of uncertainty over how long the pandemic will last, PJM decided to perform the studies for the spring and summer peak loads. The findings “could then be used to potentially consider proactive actions, such as limiting future outages if we’re seeing a trend towards these worst-case scenarios,” he said.
Sexauer said four steps were used in the process for calculating the outages, including: selecting the hypothetical generation units that would go offline; building an “all-in case” for May 4 and July 7 using normal load on those dates; creating an “all-out case” where all scheduled transmission and hypothetical generation outages from COVID-19 were applied; and running a DC/AC contingency analysis on the hypothetical cases to look for thermal overloads and “non-converged contingencies,” in which no solution is found.
He said that while running the analysis, PJM found that thermal issues with the grid were more prevalent in the spring and voltage collapse issues were more prevalent in the summer. About 5,200 cases were analyzed, requiring two days of computer runs.
