PJM‘s Independent Market Monitor released a report Wednesday concluding that New Jersey ratepayers would likely see costs increase if the state left the RTO’s capacity market and instituted a fixed resource requirement (FRR).
The New Jersey Board of Public Utilities opened a docket March 27 to investigate whether remaining in PJM’s capacity market under the expanded minimum offer price rule (MOPR) will impede Gov. Phil Murphy’s goals of 100% clean energy sources in the state by 2050 (Docket No. EO20030203). Comments are due May 20.
The BPU acted in response to FERC’s Dec. 19 order that expanded the MOPR to new and existing state-subsidized resources. The order granted exceptions for some existing resources: demand response, energy efficiency, self-supply and resources receiving payments under renewable portfolio standards.
The order could prevent New Jersey nuclear plants receiving zero-emission credits (ZECs) and future offshore wind generators from clearing the capacity market, leaving ratepayers paying twice for some capacity. Unless the order is overturned on appeal, New Jersey’s only alternative to the PJM capacity market is to provide its own capacity under the FRR.
Monitoring Analytics’ report concluded that a statewide FRR would increase costs by almost 30% if prices were at the PJM offer cap of $235.42/MW-day but only 2.4% if prices equaled the $186.16/MW-day weighted average price for the state in the 2021/22 Base Residual Auction held in 2018, the most recent auction.
Using similar assumptions, the Monitor found that ratepayers in an FRR for the PSEG locational deliverability area (LDA) would pay 6.4 to 27% more. Those in an FRR for the JCPL zone could save 2.1% or see prices rise by 28%. (The Monitor did not provide separate analyses for the AECO or RECO areas, which represent only 15% of the state’s load.)
PJM’s Independent Market Monitor analyzed a high- and low-price scenario for three different FRR regions in New Jersey. The high cost is based on PJM’s capacity offer cap, while the low price is set at the clearing prices in the most recent Base Residual Auction in 2018. | Monitoring Analytics
“Based on the analysis, the creation of a New Jersey FRR, a PSEG FRR or a JCPL FRR is likely to increase payments for capacity by customers in New Jersey,” the Monitor said.
The IMM’s analysis was requested by Stefanie Brand, director of the N.J. Division of Rate Counsel.
The BPU said Wednesday “it is premature to comment on the IMM’s report or anticipate what the results of the investigation may be.
“Staff has an obligation to review the comments filed in the docket and take any necessary action to continue the investigation (through further requests for comment, technical conferences, or hearings) before making recommendations for the board’s consideration,” the BPU said.
The Monitor said an FRR creates market power for the few local generation owners from whom generation must be purchased to meet reliability requirements. New Jersey has 15,005 MW of unforced capacity within its borders, 4,711 MW less than the 19,716 MW needed to meet its FRR reliability requirement.
“All participants in the New Jersey, JCPL and PSEG FRRs fail the one- and three-pivotal-supplier test, which reinforces the conclusion that there is structural market power in each case,” it said.
New Jersey zones and modeled locational deliverability areas | Monitoring Analytics
Because of the impact of market power, “even the higher estimates of the cost impact to the customers of New Jersey from the creation of an FRR are likely to be conservatively low,” the Monitor said. “If New Jersey were to subsidize any generating units, the subsidy costs would be in addition to the direct FRR costs.”
“Our basic overall point is that FRRs are not a panacea,” Monitoring Analytics President Joe Bowring said Wednesday during an RTO Insider webinar on the MOPR.
“FRR is a term that is really not very well defined, and the exact ratemaking process will be the result of negotiation. … There are, at the moment, no rules governing it; every state will do it their own way. But there is simply no reason to believe that this nonmarket approach … will provide the least-cost option for customers or provide incentives for renewables or for any form of energy you favor.”
The Monitor’s findings were similar to those of its previous analysis on the impact of Exelon’s Commonwealth Edison in Northern Illinois leaving the capacity market for an FRR and one on Maryland’s options.
Others have disputed those findings. Rob Gramlich, president of Grid Strategies, said FRRs won’t necessarily raise costs because they can use a lower reserve margin than PJM. (See PJM Monitor Defends FRR Analyses in MOPR Debate.)
ERCOT said Wednesday it still expects record demand this summer and the potential need for emergency measures, despite a drop in load from the COVID-19 pandemic’s continued effect on the Texas economy.
In making its final resource assessment for the summer months, the grid operator used data from Moody’s Analytics to drop its peak load forecast to 75.2 GW, almost 1.5 GW less than its preliminary assessment. However, the forecast is still higher than last August’s all-time record demand of 74.8 GW.
The pandemic has reduced weekly energy usage within ERCOT’s footprint by 3 to 4%.
“There is a lot of uncertainty in today’s world, but we are confident that Texas will still be hot this summer,” CEO Bill Magness said in a statement.
ERCOT’s peak load forecast through 2025 | ERCOT
Given the expected drop in demand and capacity additions since the last seasonal adequacy resource assessment (SARA), staff adjusted the summer reserve margin to 12.6%, up from 10.6%. Seven wind, solar and storage projects, totaling 276 MW of summer peak contributions, have begun commercial operations since the March SARA.
ERCOT said that even with 82.2 GW of capacity available this summer, energy emergency alerts are still possible should there be extreme weather, low wind generation or higher-than-normal generation outages. The grid operator called two EEAs last summer, when it had a reserve margin of 8.6%. Demand did not reach record peak levels either day, but wind production was unexpectedly low and thermal generation outages were high. (See “ERCOT CEO Briefs Commission on Summer Performance,” Texas PUC Briefs: Aug. 29, 2019.)
Pete Warnken, ERCOT’s manager of resource adequacy, said the risk of an emergency is still present but less likely with a reserve margin that is almost 50% higher. “We anticipate the risk is now lower with typical grid conditions,” he said.
The grid operator also released a preliminary SARA for the fall — 6.8 GW of additional capacity will help meet a predicted peak demand of almost 61 GW — and an updated capacity, demand and reserves (CDR) report.
The CDR report, a 10-year view of the ISO’s reserve capacity, uses pre-COVID load forecasts because of staff’s uncertainty over how the pandemic will affect future years. The report forecasts reserve margins of 17.3% and 19.7% in 2021 and 2022, respectively. ERCOT has approved 2.3 GW of resources for commercial operations since the December 2019 CDR, and staff have also included 6.5 GW of planned resources.
Preliminary data provided by generation project developers indicate the grid operator will have almost 18 GW of planned capacity additions for summer 2021, much of it renewables and some small, flexible gas-fired resources, ERCOT said.
MISO is examining additional measures to shave the time its customers spend in the generation interconnection queue, this time focusing on the definitive planning phase (DPP) and negotiations on interconnection agreements.
MISO now says its goal is to cut the time it takes to clear generation interconnection agreement (GIA) negotiations and the queue’s three-part DPP, where the RTO performs interconnection studies.
Currently, the DPP process alone takes about a year. Combined with the agreement negotiations, the timeline shoots up to about 505 days. MISO aims to have both processes take a year total.
“Three hundred sixty-five days is the goal, and we want to strive for efficiencies wherever possible,” interconnection engineer Cody Doll told stakeholders during a Interconnection Process Working Group conference call Tuesday. “Basically, we need to find a way to cut out 140 days from phase one to the end of negotiations.”
| MISO
MISO’s interconnection queue contains 434 projects totaling 67.4 GW. It takes one project about three years to complete the queue.
Doll said if the process could be shortened to a year, it would help further MISO’s goal of aligning the separate planning processes for its interconnection queue and annual Transmission Expansion Plan. (See MISO Begins Bid to Merge Tx, Queue Planning.)
“This is basically a companion to that effort ongoing in other MISO forums,” Doll said.
MISO could crop about 60 days from phase one, Doll said, by getting a head start on its study models prior to the start of the DPP. He also said it could get a jump on developing mitigation plans by inputting in advance of the DPP some results from the screening analyses interconnection customers undergo before entering the queue. It could also probably devote less time to mitigation development, where the RTO recommends solutions to grid constraints, he said.
“The most projects drop out in phase one. It’s just the nature of the beast, so it might be unnecessary to have as many back-and-forths in phase one because it’s probably going to change,” Doll said. “Phase two and three are already pretty lean. I don’t think there’s really any fat to trim in phase two.”
In fact, he said, phase two has such an aggressive timeline that he recommends MISO add about 10 days to the existing 45-day timeline it gives itself to conduct system impact studies.
For phase three, Doll said MISO could begin using “engineering judgement” to begin some network upgrade facility studies immediately after the system impact study is complete and the project owner decides whether to stay in the queue. The current queue process prescribes a 40-day wait time between the owner’s decision point and the start of an upgrade study.
But Doll said MISO could prune the most time from the existing 150-day timeline for GIA negotiations. He said it envisions the process could take about 44 days.
“A lot of GIA negotiations can occur concurrently with the network upgrade facility study,” Doll explained.
He also said interconnection customers likely don’t need 60 days to decide to execute a drafted GIA, and transmission owners don’t need the allotted 30 days to decide the same.
Doll said that if everything goes according to plan, the new one-year process could potentially be introduced within two years. But he stressed that the plan so far is only a draft.
“We’re going to make edits on this based on comments and rehash some things,” Doll said.
During SPP’s Board of Directors web meeting last month, one stakeholder commented on the number of beards grown by fellow sheltered-at-home stakeholders.
“One thing about growing a COVID-19 beard,” said Dave Osburn, Oklahoma Municipal Power Authority’s general manager, “I hope I don’t look like Billy Gibbons before this is over.”
Osburn may yet give ZZ Top’s front man a run for his facial follicles. On Friday, SPP said it was extending its suspension of its business travel and face-to-face meetings until Aug. 1 at the earliest.
The action will convert SPP’s July quarterly governance meetings to virtual webinars, as happened in April. The stakeholder groups last met in person in January, with their next face-to-face meetings scheduled in October.
“We look forward to the day we can conduct our meetings in person again, but we won’t until we’re certain we can do so safely,” SPP CEO Barbara Sugg said in a message to stakeholders. “We’ve now proven we can facilitate our stakeholder process virtually when necessary.”
The move comes as no surprise to Rob Gramlich, president of Grid Strategies.
“I find it hard to imagine people traveling for stakeholder meetings in July,” he said. “So many people call into these meetings that it would be hard to say having them face to face is essential or worth taking any risks about.”
On Monday, ERCOT followed suit and said that its stakeholder meetings will continue to operate remotely for “the foreseeable future.” The same timeline applies to visitors at the grid operator’s facilities, where only those employees who can’t work from home are in their offices.
ERCOT said it consulted with the Technical Advisory Committee and its subcommittee leadership. Together, they determined social distancing guidelines made it untenable to hold medium-to-large stakeholder meetings at the grid operator’s facilities without endangering the health of attendees.
TAC leadership has proposed procedure changes that will allow the committee to hold votes during conference calls. The group will discuss the changes during its May 27 information session.
ERCOT follows federal, state and local health agency guidance, along with epidemiologist recommendations in making its decisions.
SPP said it extended its suspension based on feedback from its member companies regarding their own pandemic response plans.
“The health and safety of our employees and their families remains a top priority for SPP and is key to our reliable delivery of services,” Sugg said, noting staff have not recorded any confirmed cases of COVID-19.
SPP’s corporate campus will remain mostly silent in the near term. | WER Architects
SPP staff have been working at home since mid-March. When it is safe to return to the office, as Sugg says, staff will do so in a staggered approach, a fifth of the employees at a time. (See “Sugg says RTO to Open Very Carefully in Months Ahead,” SPP Joint Quarterly Stakeholder Briefing: April 27, 2020.)
The RTO’s facilities and incident command structure teams will have personal protective equipment available and a supply line to restock when staff begin their phased returns to campus, Sugg said.
SPP’s systems remains reliable, though staff are tracking small but steady reductions in load, she said. Load is down 8 to 10% across the system compared to similar days and temperatures in recent years.
Exelon’s Constellation NewEnergy retail unit will pay American Electric Power $252,701 to settle AEP’s complaint over MISO’s failure to collect transmission charges from a defunct load-serving entity more than a decade ago.
The settlement, approved by FERC on Friday, addresses charges billed to Nicor Energy (EL18-7-001, ER20-207). Constellation purchased most of Nicor’s competitive energy supply contracts for 8,000 commercial and industrial gas and electric customers in Michigan, Illinois and Indiana in 2003.
AEP sought the money through the Seams Elimination Charge/Cost Adjustments/Assignments (SECA), a non-bypassable surcharge in MISO’s Tariff intended to recover lost revenues for a 16-month transition period during the elimination of through-and-out rates in late 2004 in the MISO and PJM regions.
AEP said its withdrawal of its complaint in docket EL18-7 eliminates the need for the commission to act on pending rehearing requests by itself and MISO.
The settlement said the payment by Constellation is “a complete and final settlement” of Exelon’s SECA obligations to AEP but that AEP’s withdrawal of its complaint is without prejudice to its right to initiate a future proceeding seeking recovery of SECA payments from other parties.
AEP did not respond to a request for comment on whether it will pursue claims over Engage and New Power. Engage went out of business in 2004, and New Power was liquidated in bankruptcy in 2003.
Entergy on Monday reported “solid” earnings in the first quarter, saying it has taken quick action to mitigate the effects of the COVID-19 pandemic.
First-quarter earnings came in at $119 million ($0.55/share), down from a year ago when earnings were $255 million ($1.32/share). Adjusted earnings were $230 million ($1.14/share), beating Zacks Investment Research analysts’ estimate of 94 cents/share.
Entergy activated its pandemic plan in mid-January. It has implemented a $100 million spending reduction for 2020 — primarily because of mild weather in the first quarter and expected bad debt from customers unable to pay their bills — and received regulatory orders to defer pandemic-related costs.
“We were prepared, and we will remain diligent, focused and flexible to ensure we make the right decisions at the right time to mitigate the effects for all of us,” CEO Leo Denault said, noting the company’s major projects remain on track and its capital plan is unchanged. “We’re stepping forward, not back, to be leaders in our communities when they need us the most.”
The pandemic continues to pose headwinds for the company. Rod West, group president of utility operations, said Entergy is expecting industrial sales to drop about 7% and commercial sales to fall 9.5%, largely as a result of refinery reductions and delays in new customers. Residential sales are projected to grow about 2%.
Entergy’s Searcy Solar project in Arkansas was one of two 100-MW solar farms recently granted regulatory approval. | Entergy
West said the New Orleans-based company expects industrials to return as growth drivers in 2021 and 2022 “as the commercials and residential normalize to our previous COVID-19 point of view.” Entergy expects revenue to fall by as much as $140 million because of the pandemic.
“Uncertainty remains as to the depth and length of this pandemic,” Denault said in affirming the 2020 adjusted earnings guidance range of $5.45 to $5.75/share.
Entergy continues to replace older generation with cleaner and more efficient assets, Denault said. The company brought its 980-MW gas-fired Lake Charles Power Station online months ahead of schedule in March and expects to energize its 128-MW New Orleans Power Station in June. Entergy also received regulatory approvals for two 100-MW solar farms in Arkansas and Mississippi, to be completed in 2021.
Entergy’s share price, which closed at $95.01 last week, dropped to $93.75 just before the earnings call but finished the day at $96.22.
Exelon officials told investors Friday the company’s Illinois nuclear plants are “up against a clock,” with the state legislature unable to meet to consider proposals for withdrawing from PJM’s capacity market.
Illinois officials have been discussing leaving the market over the minimum offer price rule (MOPR) since 2018. (See Illinois: End PJM Capacity Market?) The legislature is considering two bills that would create a fixed resource requirement (FRR) for the Commonwealth Edison territory in Northern Illinois, replacing the PJM capacity auction with an auction run by the Illinois Power Agency (IPA).
But company officials said during a first-quarter earnings call Friday that they don’t know if the legislature, which largely suspended operations in mid-March in response to the coronavirus pandemic, will return before the term ends May 31.
Kathleen Barrón, senior vice president of government and regulatory affairs and public policy, said that although the legislative session ends in May, lawmakers could return this summer with an agreement between the House speaker and Senate president. The governor also could call a special session, she said.
Barrón said she was pleased to see the state Department of Public Health issue guidance for how the legislature could return safely to the capital. “That is good progress, but it remains to be seen whether the leaders will decide to bring folks back to Springfield this session,” she said.
CEO Chris Crane said Exelon officials have been “stressing the importance” to lawmakers of addressing the threat posed to nuclear and renewable generation by FERC’s December order expanding the MOPR to new state-subsidized resources.
PJM has said it will hold the next Base Residual Auction about six and a half months after FERC rules on its MOPR compliance filings — meaning an early 2021 auction if a ruling comes by mid-2020.
“So, we’re up against a clock. And once those auctions are run, we’re highly confident that minimal or [none] of our clean megawatts will clear in that capacity auction,” Crane said. “They’ll be replaced by fossil units, which is detrimental to the state’s goal of being 100% clean by 2030.”
Proposals
Exelon in March 2019 endorsed the Clean Energy Progress Act (CEPA) (HB 2861), which would create a ComEd FRR. The bill cleared the House Public Utilities Committee at the end of that month by a voice vote but has seen no action since. The bill currently lists 16 co-sponsors.
“We certainly agree that the only cost-effective way to reach 100% clean energy is to take advantage of the FRR,” David Kolata, executive director of the Citizens Utility Board in Chicago, said in an interview Monday.
Meanwhile, the American Wind Energy Association and the Solar Energy Industries Association are among 70 business, nonprofit and organized labor groups backing the Path to 100 Act (HB 2966/SB 1781), which would increase Illinois’ renewable portfolio standard to 40% by 2030 and add new funding for renewable generation. It does not include an FRR.
Jeff Danielson, AWEA’s central states director, said the Path to 100 is intended to address the “funding cliff” for the RPS program, which has left the IPA without any more funding for utility-scale wind and solar. “The primary issue on energy policy we need to address is to meet the RPS funding goal,” Danielson said.
Kolata said that while the Exelon-backed bill is focused on the FRR and the Path to 100 on expanding the RPS, the CEJA is more comprehensive. It would increase natural gas efficiency standards and direct the IPA to cut peak electricity demand through energy storage, efficiency and special rate plans. It would seek to eliminate 1 million gasoline and diesel vehicles by increasing development of electric vehicle charging stations, EV ridesharing and public transportation electrification. CEJA also would add 40 million solar panels and 2,500 wind turbines in the state, quadrupling the amount of new renewable energy created by the 2016 Future Energy Jobs Act, which ordered utilities to get 25% of their power from renewable resources by 2025 and approved zero-emission credits (ZECs) for Exelon’s Quad Cities and Clinton nuclear plants.
Exelon’s corporate headquarters inside Chase Tower in Chicago
In his State of the State address in January, Gov. J.B. Pritzker called for passage of legislation this term to reduce carbon pollution, promote renewable energy and accelerate electrification of transportation. “Urgent action is needed. But let me be clear, the old ways of negotiating energy legislation are over,” Pritzker said in what some saw as a reference to the FBI investigation into ties between the legislature and Exelon’s team of lobbyists. “I’m not going to sign an energy bill written by the utility companies.” (See Exelon Pledges Reforms amid Grand Jury Probe.)
Chicago radio station WBEZ quoted Pritzker as refusing to commit to any timetable on responding to Exelon’s concerns. “I’ve said we’re going to make sure that we work on an energy package for the state, and we don’t need the high-paid lobbyists to be guiding that for us,” Pritzker said Friday. “I look forward to the legislature getting together to address so many challenges that we have. But is it true there are higher priorities right now? Yes, there are, and that’s reviving our economy.”
Exelon’s ComEd also suffered a blow last month when the Illinois Commerce Commission disavowed its “NextGrid: Illinois’ Utility of the Future” study after agreeing to settle a lawsuit that alleged the former head of the ICC had given the utility veto rights over the study and its participants. (See ‘NextGrid’ Goes off the Rails.)
Nevertheless, Crane said Friday that the company has “significant support” for its efforts to create an FRR.
“We would hope that it would get done before the end of the session. That’s what we’ve stressed: to give the IPA time to be able to develop their own auction process that will allow us to break away on capacity needs for the state of Illinois from PJM. … It’s a very tight time frame. … This is a very important issue to address … along with the state budget and some other large issues. So, we know there’s a will to get to work. It’s just the way to get to work and how fast we can get this done.”
Exelon spokesman Paul Adams told RTO Insider on Monday that while the company prefers the CEPA, it also “directionally supports” the FRR envisioned in the CEJA.
Both bills promise 5% initial savings compared with what ratepayers currently pay for capacity, ZECs and renewable energy credits. Neither bill calls for an expansion of the state’s ZEC program to Exelon’s other nuclear plants in the state: Dresden, Byron and Braidwood.
In its first-quarter filing with the U.S. Securities and Exchange Commission, Exelon said its Dresden, Byron and Braidwood plants are “showing increased signs of economic distress, which could lead to an early retirement.” It said PJM’s last capacity auction in May 2018 “resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood.”
Adams said those plants would be eligible for “clean capacity” payments under the FRR as envisioned in the CEPA. Quad Cities, which is located in the PJM portion of Illinois, would continue to receive ZEC payments but would be ineligible to receive a clean capacity payment under the FRR legislation to avoid double recovery, Adams said.
In addition to being aligned with the state’s carbon-free goals, CUB’s Kolata said the CEJA will save consumers in large part by reducing ComEd’s reserve margin to 16% under the FRR versus the nearly 30% under PJM’s Reliability Pricing Model (RPM).
Kolata said the IPA would first procure carbon-free capacity — which would receive compensation for their environmental attributes — and then procure fossil fuel resources for any residual needs. Kolata said he expects 16 GW of fossil capacity to compete for 5 GW of residual need in Northern Illinois.
Not everyone is convinced the FRR will be cheaper, however. In December, PJM’s Independent Market Monitor issued an analysis that concluded net load charges would increase 23.6% if ComEd procured all of its capacity obligations outside of RPM at the offer cap — $254.40/MW-day — rather than the $195.55/MW-day clearing price in the 2021/22 BRA.
In a second scenario, the Monitor calculated that ComEd’s load charges would decrease 5% if the price negotiated for its capacity were equal to the locational deliverability area’s clearing price. The report contended the first scenario was more plausible, “given Exelon’s assertions that the current total revenue from energy, ancillary and capacity markets is not adequate for its nuclear plants.”
Earnings
Exelon’s first-quarter earnings beat the Zacks Investment Research analyst consensus by 2 cents/share, but the company reduced its earning guidance for the full year because of decreased demand during the pandemic.
CFO Joseph Nigro said the company earned $582 million ($0.60/share) on a GAAP basis compared to $907 million ($0.93/share) in the first quarter of 2019. Nigro said non-GAAP operating earnings were flat from last year at 87 cents/share, slightly below the midpoint of the company’s guidance range.
Nigro said Exelon was “particularly pleased” with the results considering the warm winter weather throughout the region.
“Temperatures in the Mid-Atlantic were 5 to 7 degrees higher than average in January through March, costing us 14 cents/share between Exelon Generation and our non-decoupled utilities,” Nigro said.
COVID-19 Impacts
Besides the warm winter weather, Nigro said the effects of the pandemic’s stay-at-home orders had the most dramatic effect on energy demand. He said because of the pandemic, the unfavorable weather and lower allowed electric distribution returns on equity at ComEd because of a decrease in U.S. Treasury bill rates, Exelon was revising its 2020 full-year guidance range from $3 to $3.30/share to $2.80 to $3.10/share.
“While typically we would not change guidance so early in the year, we want to provide a complete picture of where we stand at this point in the year and include our best estimates of the COVID-19 impacts,” Nigro said.
Exelon officials expect commercial and industrial load to decrease by 9 to 15% and residential load to increase by 4 to 7%, depending on the region, during the second quarter. Nigro said the company recognizes the situation surrounding the pandemic changes rapidly, so they’ve taken a “cautious view of the world” when revising the numbers.
“The full impacts, including the duration and structural changes to the economy, continue to evolve,” Nigro said. “In developing our revised guidance range, we looked at the load and economic data we were seeing in April, talked to our customers about their expectations for the year and considered different economic outlooks.”
Acquisition Opportunities?
Guggenheim Securities analyst Shar Pourreza asked company officials whether the economic distress resulting from the pandemic could present strategic opportunities for Exelon’s Constellation retail business.
Constellation CEO James McHugh said the company would kick the tires of any retail operations that became available.
“Our strategy before will stay the same, which is we would be looking to buy … books of business that we could easily fit into our platform,” he said. “We’ve developed, I think, a world-class platform over the years that we can integrate easily, and we’ve shown that before when we bought books of business.”
While Exelon and Public Service Enterprise Group last week expressed support for pulling out of PJM’s capacity auction over the expanded minimum offer price rule (MOPR), Dominion Energy says it is undecided.
But Dominion told the Virginia State Corporation Commission in its proposed integrated resource plan May 1 that it is still evaluating the FRR alternative in response to FERC’s December order expanding the MOPR to new state-subsidized resources and “has made no decision at this time.”
“If the company were to elect FRR, it would have to do so in advance of the next RPM [Reliability Pricing Model] base auction,” Dominion said. “Typically, this election would need to happen about six months prior to that auction; however, due to the pending MOPR-related filings with FERC, the schedules may be compressed. The schedule depends on if, and when, FERC accepts PJM’s recent compliance filing.”
PJM currently estimates the next Base Residual Auction to occur in late 2020 or early 2021, about six and a half months after FERC rules on the RTO’s compliance filings.
FERC had previously exempted from MOPR self-supply resources owned by public power entities (cooperative or municipal utilities), vertically integrated utilities subject to traditional bundled rate regulation like Dominion and load-serving entities that serve retail customers.
But in the Dec. 19 order, FERC said new self-supply resources would no longer be exempt, ruling that they suppress capacity prices under PJM’s RPM. The commission said the self-supply exemption would be limited to resources that had either cleared the RPM or were in development and in PJM’s interconnection queue before the December order.
Dominion capacity position 2021 to 2035 | Dominion Energy
But in its April 16 rehearing order, the commission rejected Dominion’s request. “Integrated resource plans do not replace the PJM interconnection process; granting rehearing in this manner would expand the number of resources eligible for the exemption beyond those that reflect established investment decisions, to include resources that may not even be sufficiently developed to be in the PJM interconnection process at all,” FERC said. “We find that the demarcation clarified above is sufficient to recognize those resources that are sufficiently along in the interconnection process to warrant exemption under the commission’s stated goals.” (See FERC: RGGI, Voluntary RECs Exempt from MOPR.)
Dominion Energy Virginia, which owns 27,100 MW of generation, is planning to build 2.6 GW of wind generation off the coast of Virginia and is about halfway through a plan to add 3,000 MW of solar generation. Its proposed IRP for 2021-2045 would quadruple the amount of solar and wind generation in its previous 15-year plan, a response to Gov. Ralph Northam’s executive order on climate change and the Virginia Clean Economy Act, signed last month. (See Va. 1st Southern State with 100% Clean Energy Target.)
In its discussion of the FRR option, Dominion noted that American Electric Power, parent of Appalachian Power in Virginia and West Virginia, is “the only significant utility in PJM” to have adopted FRR.
“Because of its five-year minimum commitment requirement, risks to FRR election should be carefully weighed against the benefits,” Dominion told the SCC. “Risks include future environmental changes, regulatory changes, zonal constraints, and capacity and energy market changes. The potential benefits of FRR election include [a] lower required reserve margin and the absence of MOPR risk to new generation used to meet the load obligation.”
Under the expanded MOPR, Dominion said, “virtually all new generation resources will need to offer at net [cost of new entry] or an otherwise calculated market seller offer cap — which could be above the RPM market clearing price — resulting in $0 revenue for these uncleared resources.” (See MOPR Ruling Threatens to Upend Self-supply Model.)
Dominion said the reliability requirement for the FRR service area would be the forward load forecast plus the target reserve margin. “This is one of the primary differences between RPM and FRR, as the PJM coincident peak target reserve margin for FRR is forecasted to be approximately 15% — over 5% less than where the RPM market has been clearing recently. From a long-term planning perspective, this reserve margin requirement difference could be significant. If the company’s forecasted load was 20,000 MW, for each percent difference between [the] cleared reserve margin and target reserve margin, electing FRR would result in about a 200-MW reduction in [the] purchase requirement.”
But the company cautioned that “both the clearing price and the clearing reserve margin of the upcoming RPM forward capacity market remain highly uncertain.”
And it noted that capacity resources committed under an FRR plan will continue to be subject to the same Capacity Performance requirements as those committed through the RPM. “To the extent an LSE has capacity in excess of its load requirement, those excess capacity resources may not generate the same revenue as if offered into the RPM market,” it said.
Stakeholders are asking if MISO’s new long-term generation outage policy played a role in driving up Michigan capacity prices in this year’s Planning Resource Auction.
While nearly all MISO local zones cleared under $7/MW-day in last month’s 2020/21 PRA, Lower Michigan’s Zone 7 cleared at the $257.53/MW-day cost of new entry price — 10 times the capacity price paid in the last planning year. (See Michigan Prices Soar in 8th MISO Capacity Auction.)
During a Resource Adequacy Subcommittee teleconference Wednesday, MISO Manager of Capacity Market Administration Eric Thoms told stakeholders that Zone 7 came up short of capacity to meet its local clearing requirement and had to import capacity, activating the CONE price.
Stakeholders asked if the Independent Market Monitor examined whether MISO’s new long-term outage rules might have been used as a façade by some Zone 7 resources to physically withhold capacity and drive up prices. The new rule stipulates that planning resources cannot offer into the auction if they plan to be on outage for longer than 90 days of the first 120 days of the planning year. MISO deems the first four, warm months of the planning year as the time when capacity availability is most critical. The RTO’s 2020/21 planning year begins June 1.
IMM staffer Michael Chiasson said the Monitor scrutinized long-term outages to make sure they were justified.
“We don’t want people to have outages in there that give them an excuse to not participate,” Chiasson said. “It’s kind of like a road with two ditches: Don’t participate if you shouldn’t, and participate if you should.”
Chiasson also said that some Zone 7 resources didn’t offer all the capacity they had, but the unoffered supply was below the Monitor’s conduct threshold of 50 MW per affiliated companies per zone. MISO’s 2017 rule applies a 50-MW physical withholding threshold to affiliated market participants collectively, rather than individually to each affiliated company.
Last year, the Monitor had to enforce market mitigation for economic withholding in Zone 7, resulting in a 1 cent/MW-day reduction in the Lower Peninsula. Zone 7 also cleared higher than all other zones last year, at $24.30/MW-day compared to $2.99/MW-day everywhere else.
Thoms said MISO will discuss how it approached its loss-of-load sensitivity analysis for Zone 7 at the June 10 RASC meeting. He said MISO would also investigate whether Zone 7 would have come up short in the last planning year had the long-term outage rule been in place at the time.
MISO’s 2020 Transmission Expansion Plan contains a special study into the increasingly tight capacity import and export limits (CILs/CELs) in Zone 7. The Michigan Public Service Commission requested the study, which will help the state “better understand the effects” of increasing either the CIL or CEL for Zone 7, according to MISO. (See Northern Focus for MTEP 20.)
Meanwhile, MISO says it wants to be more transparent in how it develops its loss-of-load expectation study.
“This is something we’re struggling with. … We’re trying to figure out how to get more stakeholder engagement earlier and up front. We want to make sure this process is meaningful,” RASC Chair Chris Plante said.
Customized Energy Solutions’ Ted Kuhn said the problem is that MISO makes a “fluffy,” introductory presentation one month, then comes back with LOLE study results in the next month.
“We never saw how this was being developed in the first place. … So something needs to change in how they’re developing their work products,” Kuhn said.
MISO is ready to begin testing some of the capabilities of its new market platform as the effort to develop the system enters its fourth year, stakeholders learned last week.
“It’s really an exciting time for the program because we’re pivoting from foundational work to delivery,” MISO Senior IT Director Curtis Reister told stakeholders on a Market Subcommittee conference call Thursday.
Reister said members’ IT departments will soon begin testing MISO’s new market user interface software in a customer test environment.
MISO expects it will begin transitioning to the new interface by the third quarter of 2021, running the system in parallel to the old platform for several months to allow members to phase in the change before the old interface is officially retired in early 2022, Reister said.
The RTO reports that 291 companies currently use its market user interface.
“It’s not like every member has to transition on the same day. This allows members to attempt to transition … and go back and forth as many times as needed,” Reister said.
Because of vendor delays, MISO now says it’s unsure if it can meet a self-imposed June deadline to demonstrate the operation of its private cloud using non-Critical Infrastructure Protection data. The new private cloud will house the modular platform, replacing the current server-based platform.
The RTO plans to migrate data to its new private cloud for testing and import modeling information to its one-shop model manager this year. (See “Private Cloud Prepped for New Market Platform,” MISO Board of Directors Briefs: Dec. 12, 2019.)
By the end of the year, MISO will have uploaded its operations data in the model manager, which is scheduled to go live next year, Reister said.
“Modeling is interwoven in a lot of MISO processes,” Reister said of the importance of a singular repository for the RTO’s many planning models. MISO currently relies on several different means to collect and validate grid information for modeling.
MISO said the contract and delivery date of work on its new day-ahead market clearing engine is currently under negotiations. Its goal is to have the existing platform and a version of the new platform running in parallel for testing purposes in 2021, paving the way for the eventual retirement of the old platform. The RTO hopes to have the new clearing engine in production in the third quarter of 2022.
MISO executives have said that the monolithic nature of the current market platform is a major limiting factor in adapting its market to accommodate new products that seek to incentivize availability of the RTO’s shifting resource mix.
“2020 is the fourth year of the program, and it represents a turn in focus of the work,” Vice President of Market System Enhancements Todd Ramey said during MISO Board Week in March. “Whereas the first three years of the program were primarily focused on extending the life of the legacy platform … this year we’re really making the switch to completing major projects and bringing some of this online.”
