MISO said Monday that it will hold its quarterly Board Week via conference call only, canceling the New Orleans event as the COVID-19 coronavirus extends its reach.
The cancellation was announced in a joint letter from CEO John Bear and Board of Directors Chair Phyllis Currie. The two said the six committee meetings and full board meeting scheduled for March 24-26 will continue as planned, but in WebEx/dial-in format.
“At this point, the board and MISO senior management have concluded that it is prudent for us to take more aggressive steps to keep our employees and stakeholders safe and do our part to limit the spread of this virus,” Bear and Currie wrote. “We did not take this decision lightly. MISO’s Board of Directors views these meetings as extremely important aspects of the stakeholder process that provide valuable opportunities for engagement with our stakeholders. As we have monitored the situation overall, paying special attention to member and state travel policies, we have concluded that this is the right decision for the region.”
MISO also announced that all other stakeholder meetings will continue to take place via conference call through May 1. The RTO’s conference call-only policy originally applied to meetings held March 9-13. (See MISO Steps Up COVID-19 Response.)
MISO has hosted its spring quarterly Board Week in New Orleans uninterrupted since 2011, two years before Entergy joined the RTO and made the city part of the footprint.
The cancellation occurred less than one week before stakeholders and MISO staff were set to converge on the Westin Hotel in downtown New Orleans. The RTO apologized for the short notice, explaining that it tried to collect “as much input and direction as possible” before its decision.
Advisory Committee Chair Audrey Penner said she fully supported MISO’s decision “to protect its staff and stakeholders while the uncertainty over the COVID-19 situation continues to play out.” She pointed out that the committee has held meetings via conference call in the past.
“While they are a little trickier to manage, I don’t anticipate any issues next week that would prevent us from having a good discussion. Having said that, holding ‘policy-type’ discussions via conference call [isn’t] ideal, so we are limiting those types of discussions next week,” Penner said in an email to RTO Insider.
Penner said she will prepare a verbal report to the board as usual, this time covering the AC’s recent recommendation that the RTO create a new “affiliate” sector for hard-to-define members. (See MISO Advisory Committee OKs 11th Sector.)
Steering Committee Chair Tia Elliott canceled the March 25 meeting of her committee and said it will next meet in an April conference call.
Elliott, who also serves as vice chair of the Advisory Committee, said she had full confidence in MISO and Penner to navigate the AC meeting by conference call.
“No doubt it can be tricky at times, but there is a chance we have a glitch during an in-person meeting too,” Elliott said. “I would encourage stakeholders to be patient, kind, and show grace during these conference calls, and to each other, especially during this unprecedented time we are all living through together.”
The AC has more than 50 members and alternates; audiences regularly exceed 100 people at Board Week.
MISO promised more updates on COVID-19’s effect on its stakeholder process and echoed Elliott’s message of unity.
“In times such as these, it is essential that we all work together to deliver electricity reliability to serve our customers,” Bear and Currie said.
Retail-choice states wanting to reduce their reliance on RTO capacity markets need to improve how their retail markets handle resource procurement, according to a new study produced for the Wind Solar Alliance.
“When competitive retail states restructured, there was insufficient focus on designing the market structure to support long-term contracting,” said the study, authored by Rob Gramlich of Grid Strategies and Frank Lacey of Electric Advisors Consulting. “Expansion of renewable energy and issues with wholesale capacity markets now require a focus on the competitive retail entities’ incentive and ability to procure power.”
The report notes that at least five states — all of which have retail competition — have begun proceedings over the last year to consider leaving FERC-regulated capacity markets.
State retail market rules were graded for their impact on competitive retail energy providers’ incentive to invest in generation resources. | Wind Solar Alliance
“If states wish to rely less on capacity markets, they will need to make sure their retail markets are designed to handle resource procurement,” the study said. Yet among the 14 states with retail competition, only Texas clearly assigns responsibility for resource procurement to customers or their load-serving entities. “No entity in those [13 states] has both the incentive and ability to procure power, given the rules and structures currently in place,” Gramlich and Lacey say.
Of the 14 states with retail electric choice, only Texas clearly assigns responsibility for resource procurement to customers or their load-serving entities. | Wind Solar Alliance
The other 13 states have “hybrid” competitive retail structures with “a monopoly default service provider offering rates that are subsidized to varying degrees and some form of a free option for customers to move in and out of competitive service. This dynamic reduces the incentive for retailers to procure supply.”
Clean Energy Transformation
The study says the transition to a decarbonized economy will require a market structure with entities able and willing to sign long-term contracts because generation developers and lenders are reluctant to finance 20- to 40-year assets based on expected future hourly prices.
This is especially the case for renewables, which are capital-intensive, with no fuel expenses and minimal ongoing costs. “Prearranged contracts provide the certainty necessary to finance those capital costs at a reasonable rate before the investment is made,” said the authors, who also noted that increasing penetration of renewables with zero production costs can depress spot energy prices. “Contracts provide upfront revenue certainty for lenders prior to committing capital.”
The failure of most restructured states to assign responsibility for ensuring resource adequacy caused a “free-rider” problem, leaving supply “under-procured and underpaid,” the authors say. “That is one reason RTOs in those areas stepped into the resource adequacy role with mandatory capacity markets.”
Recommendations
The study includes a scorecard on state retail market rules and their impact on competitive retail energy providers’ incentive to invest in generation resources. Texas gets straight “A’s,” while New Jersey, Maryland and Pennsylvania score mostly “D’s” and “F’s”.
The report identifies several reforms the authors say would improve retail market operations:
Eliminate Subsidies for Default Service: Utilities typically do not include in default service rates the costs for billing systems, accounting services, call centers or other functions required to deliver default service, resulting in a subsidy the authors estimate to be about 1 to 2 cents/kWh. In Baltimore Gas and Electric’s 2019 rate case, for example, the cost of providing default service was estimated to be about $170 million, only $12.3 million of which BGE planned to allocate to default service customers. The remainder was recovered through BGE’s distribution rates, which are paid by all customers, including those choosing competitive suppliers.
Unbiased Initial Placement: Default service is really a “provider of first resort” in many states instead of the “provider of last resort” as it is sometimes referred, the authors say, noting that only about one-third of residential customers in the 13 states have chosen competitive suppliers. Retail electric providers’ (REPs) “ability to maintain their customer base is eroded where new customers or moving customers are automatically placed on utility default service,” the authors say. “If customers were compelled to choose a supplier when enrolled for new service, they would be empowered with many options, including the option to purchase renewable energy.”
No Free Option: Consumers in hybrid restructured states are free to return to default service at any time. “The option imposes costs on default service wholesale providers (they lose load when market prices decline because the default service price decline lags the market) and onto REPs and onto other entities that provide customer services. (REPs lose load to default service when market prices increase because the default service price increase lags the market.) The free option eliminates the incentive for REPs to procure power on a long-term basis on a customer’s behalf.”
Creditworthiness: High and enforceable creditworthiness standards are needed to ensure REPs can make the long-term resource commitments needed to serve their loads.
Utility Neutrality on Default Service: Utilities profiting from providing default service are likely to steer customers away from competitive suppliers, the authors say. In its latest distribution rate proceeding, it was estimated that BGE will earn $8.3 million annually above its approved distribution revenue requirement from providing default service. By contrast, Texas has eliminated utilities’ role as default service provider.
The report says the recommendations would “enable broader wholesale market improvements.”
“One key market design element that is not widely used yet but is important to ensure retail providers have the incentive to sign long-term contracts, as well as to provide appropriate long- and short-term incentives for efficient behavior, is to accurately price energy at times of scarcity,” the authors say. “In Texas, prices can rise to $9,000/MWh at these times, as they did in the summer of 2019. This feature along with the rest of the Texas structure appears to be working to achieve supply-demand balance.”
PJM’s Paul McGlynn told the Operating Committee on Thursday that the System Operations Subcommittee (SOS) will begin holding weekly conference calls later this month to discuss how the COVID-19 coronavirus is impacting generation and transmission operators locally “and the steps that we’re all taking to deal with the situation.”
“I think it will help us to share best practices,” McGlynn said.
PJM has canceled all business travel, restricted access to its buildings and limited stakeholder meetings to Webex through at least March 27. The RTO is encouraging staff to stay home if feeling ill and planned to hold a telecommuting exercise March 13 to test its remote capabilities.
Scott Heffentrager, PJM’s chief security officer, said there have been nine presumptive cases of COVID-19 in Montgomery County, Pa., where the RTO’s two control rooms are located. PJM is conducting regular sanitizing operations of the control rooms.
The RTO will announce a decision by April 3 on the status of its Annual Meeting, scheduled for May 4-5 in Chicago.
PJM canceled the first three weeks of its Operator Seminar, scheduled to begin in Baltimore on March 10, and will decide by this Tuesday if training set for Columbus, Ohio, will be held.
Senior Vice President of Operations Mike Bryson said companies should contact PJM’s training department if they are concerned about staffers unable to complete required training because of the cancellation.
Heffentrager said PJM has experienced an increase in “phishing attempts and other scams” related to the virus. NERC warned of the risk of virus-related phishing attempts in a Level 2 Alert it issued March 10.
The alert advised registered entities to maintain situational awareness, reinforce good personal hygiene practices, and review and update business continuity plans. It also advised of possible supply chain disruptions that could affect the availability of electronics, personal protective equipment and sanitation supplies.
Station Power Complaint Challenges FERC Jurisdiction
PJM Associate General Counsel Steve Pincus briefed members on a FERC complaint filed March 6 by Lawrenceburg, Ind., and the Indiana Municipal Power Agency against the RTO, American Electric Power Service Corp. and Lawrenceburg Power alleging that the commission does not have jurisdiction over station power and seeking to void the power self-supply monthly netting provisions of the RTO’s Tariff (EL20-30).
The city’s Lawrenceburg Municipal Utilities has an exclusive franchise for supplying electricity within city limits and says Lawrenceburg Power’s 1,096-MW combined cycle plant in the city must take station power service from the city because Indiana law does not allow it a choice of retail supplier. Lawrenceburg Power is owned by a joint venture of The Blackstone Group and ArcLight Capital Partners. The plant is interconnected with AEP transmission facilities under PJM’s operational control.
The complaint asks FERC to declare that supply station power is a retail sale over which the commission lacks jurisdiction and that PJM Tariff provisions providing a merchant seller the right to self-supply station power through monthly netting are void and unenforceable. The complainants say Lawrenceburg Power must take station power service under the retail rates and terms of state and local law.
“The reason we’re bringing this to your attention is the complaint may implicate other members,” Pincus said.
Comments and PJM’s answer are due March 30.
FERC approved the netting rules in 2001, saying station power can be supplied to a generating plant in three ways: on-site self-supply (from behind-the-meter generation); remote self-supply (from another generator owned by the same company); or third-party supply.
The city is relying on federal court rulings in 2010 and 2012 that electricity purchased from a third party for use at a generating plant is a retail sale subject to state jurisdiction.
Manual 3 Update Prompts Questions
Stakeholders voiced surprise and concern in response to a proposal to create a confidential appendix to Manual 3 (Transmission Operations), which details requirements for transmission outages and includes guidelines on thermal, voltage and stability limits.
PJM’s Lagy Mathew said the RTO plans to move section 5 of the manual — which contains operating procedures for specific areas of the system and is amended frequently to reflect topology changes — to a new Manual 3B (Transmission Operating Procedures). Because of its sensitivity, section 5 is only accessible to stakeholders with Critical Energy/Electric Infrastructure Information (CEII) clearance.
Mathew said the published version is not always current and that even members with CEII clearance don’t see changes until the semiannual update. PJM maintains a separate, internal-only version for system operators, he said.
PJM proposed that the new Manual 3B not go through the committee endorsement process when it is revised, although the RTO would review changes monthly at SOS meetings.
That would ensure that the operational procedures are current for PJM dispatchers and eliminate the need for the separate internal version, Mathew said.
Several stakeholders questioned the value of the proposed change. “Why do you need to do it?” one stakeholder asked. “You already have two versions.”
Adrien Ford of Old Dominion Electric Cooperative recalled “very contentious” discussions in the OC regarding “the whole gas contingency situation, and much of that was in the CEII version of Manual 3.”
“I’d urge PJM not to make a change until we’ve had a more fulsome discussion,” she added.
PJM’s Darlene Phillips said staff “underestimated the level of conversation and confusion that this might cause. We thought we were doing something that would simplify the process.”
She said staff will create a question-and-answer document to address stakeholders’ questions in time for the OC’s April meeting.
Generation Cold Weather Survey due April 1
PJM’s Vince Stefanowicz reminded generation operators that the RTO’s survey on minimum operating temperatures, which opened on eDART on Dec. 1, will close April 1. The survey was prompted by the joint NERC/FERC report on the MISO cold-weather event in January 2018.
MISO will allow stakeholders an additional month to file their opinions on the RTO’s draft 2021 transmission planning futures scenarios.
The three futures have undergone three sets of alterations as MISO evaluates and responds to stakeholder requests. (See MISO Outlines Electrifying Tx Planning Futures.) The RTO had hoped to finalize new scenarios in April.
Speaking during a Planning Advisory Committee conference call Wednesday, Planning Manager Tony Hunziker said MISO will now collect stakeholders’ written feedback through March 27 and hold more discussion at the PAC’s April meeting.
Future I — formerly Announced Plans — assumes an 85% probability that companies’ renewable growth and carbon-cutting goals will materialize and full certainty that states’ clean energy plans will come to pass. It also includes a 40% reduction in carbon emissions from 2005 levels by 2040.
Future II — previously Accelerated Fleet Change — assumes MISO members meet or exceed decarbonization plans while carbon emissions drop 60% from 2005 levels. Electric vehicle adoption stimulates demand, while residential and commercial electrification reaches 39% of its technical potential, representing a 30% energy growth footprint-wide by 2040.
Future III — Advanced Electrification — also assumes members fulfill their renewable plans and consumers adopt EVs. It foresees a sharp increase in demand because of residential and commercial electrification hitting 77% of its technical potential, representing a 60% energy growth. MISO also experiences a minimum 50% renewable penetration level as carbon emissions dip 80% below 2005 levels.
From its last futures draft, MISO has eliminated the nearly 35% renewable generation minimum penetration by 2040 prediction in Future I. The RTO’s most aggressive renewable prediction in the MTEP 19 futures estimated that renewables would take a 36% share of the resource mix by 2035.
Consultant Kavita Maini said it didn’t appear MISO was preparing for the possibility of an economic slowdown and a subsequent postponement of the retirement of certain plants in an effort to keep investments and customer rates low. She said some utilities might not achieve the emissions reductions for which MISO is planning.
“I don’t think we want to plan for doomsday,” Minnesota Public Utilities Commission staff member Hwikwon Ham responded, noting that MISO plans for an average growth, not the troughs and booms of the economy.
“Regardless of your political leanings, I can guarantee there’s going to be at least one administration”, that changes party, MISO Planning Manager Tony Hunziker said.
The futures are set to guide the 2021 MISO Transmission Expansion Plan (MTEP 21). MISO will begin planning for MTEP 2022 in June.
The RTO has also scheduled an April 16 workshop to discuss resource siting for the MTEP 2021 futures.
PAC to Begin MTEP, Queue Synchronization
MISO members will soon decide whether to retire the Coordinated Planning Process Task Team (CPPTT), charged with compiling ideas for synchronizing the annual transmission expansion plan with interconnection project planning.
The CPPTT’s sole purpose was to review the MTEP and generation interconnection planning processes and identify ways the RTO could increase consistency and coordination across the two. The team forwarded its findings to the PAC and Planning Subcommittee. (See MISO Committees Tackle Queue, Tx Planning Disparities.)
MISO Senior Manager of Economic Planning Neil Shah said having created the list of issues, stakeholders could decide to retire the CPPTT if there are no additional assignments for the group.
Shah said once reliability, economic and interconnection queue planning processes are synched up, MISO could identify fewer and more cost-effective transmission projects.
“We can evaluate a single solution instead of three separate solutions using three different processes,” Shah said. “If the timing is not aligned, there isn’t much opportunity to share information and evaluate.”
Some stakeholders asked that MISO either draft a white paper or hold workshops before drafting solution ideas in the PAC.
Stakeholders will again discuss the issue at the April PAC meeting.
MISO is recommending that two substation bypass projects begin earlier than the MTEP 20 cycle allows, stakeholders heard.
The RTO received two expedited project review requests from Ameren in December to bypass the 345-kV Coffeen and Duck Creek substations in western Illinois. Ameren said the projects are necessary because Vistra Energy has retired the corresponding Coffeen and Duck Creek power plants, which used to be pseudo-tied into PJM.
MISO said the bypass projects will “eliminate the need for AC/DC station service at these stations since these services became inefficient due to the retirements.” The RTO also said it didn’t discover any reliability issues as a result of the projects.
Ameren said it will save about $1.5 million if it no longer has to provide AC/DC station service or oversee the operations and maintenance costs of the substations.
MISO said it will move both projects into Appendix A of MTEP 20 and authorized Ameren to begin construction.
SPP staff last week shared a draft congestion study with the Seams Steering Committee on the effect of MISO’s contract path to its southern footprint.
The study of the SPP day-ahead market’s external flows and solution costs analyzed whether regional directional transfers (RDTs) above the contract path capacity between MISO’s South and Midwest subregions created additional congestion or operating costs for SPP’s market. MISO is limited to 1,000 MW of contracted, firm capacity over the contract path as a result of a 2015 settlement agreement. (See SPP, MISO Reach Deal to End Transmission Dispute.)
The committee had asked staff to provide more information on the differences in the hourly redispatch level, with a look at the generation footprint broken out by state and legacy balancing authority. Staff’s limited study was inconclusive as to whether MISO’s above-capacity RDTs created a “pattern of financial harm.”
SSC Chair Jim Jacoby noted during the committee’s meeting Thursday that high north-to-south days would “probably” overstate the study’s results.
Staff will return to the committee for its April 2 conference call with a final version of the study. The SSC plans to endorse or accept the report at that time.
M2M Settlements Up to $72M in SPP’s Favor
SPP earned $1.81 million in market-to-market (M2M) settlements in January, the fourth straight month — and 43rd in 59 months — that the M2M process with MISO has settled in its favor.
| SPP
SPP has now incurred $72.14 million in M2M settlements from MISO since the two began the process in March 2015. The process provides a compensation mechanism when SPP or MISO have to redispatch transmission around congested flowgates.
Temporary and permanent flowgates on the RTOs’ seam were binding for 438 hours during January. Temporary flowgates accounted for 427 of the binding hours.
ISO-NE is wrapping up its Energy Security Improvements (ESI) initiative ahead of an April 15 filing deadline with FERC, stakeholders learned last week during a two-day meeting of the New England Power Pool Markets Committee (EL18-182).
The committee plans to vote on ESI at its March 24 meeting, and the NEPOOL Participants Committee plans to vote on the market design at its April 2 meeting.
The start of the second day’s proceedings was delayed by a brief discussion of teleconference protocol after ISO-NE announced that, in response to the spreading COVID-19 coronavirus, its staff will not participate in person at stakeholder meetings from March 12 to April 30.
Later on Wednesday, NEPOOL announced that “future NEPOOL meetings in March and April will be conducted via teleconference with webinar capabilities.”
Focus on Winter Benefits
Todd Schatzki of Analysis Group presented a draft impact analysis that shows that — in addition to expected reliability benefits — ESI can also improve efficiency and lower production costs under stressed market conditions when the increase in energy inventory reduces energy production from less efficient and higher-cost fuels.
The study of winter months demonstrates that changes in net revenues vary across resource types, although the direction of these impacts (i.e., whether net revenues increase or decrease) is generally the same across resource types within each case, given the nature of the stressed market conditions, Schatzki said.
Summary of change in total payments, Winter Central Case | Analysis Group
Much of the quantitative analysis focuses on impacts in winter months, partly because the ESI proposal aims to improve market efficiency by better aligning individual participant incentives with the region’s need for energy supplies during tight market conditions, according to the full draft report.
ESI would be expected to increase total payments by load to suppliers on a rising scale, with the increase being lowest during periods when stressed market conditions are uncommon or infrequent and highest when they are frequent, while the extended case shows a 2.5% decrease in such payments.
Multiple factors influence the impact, such as the frequency and duration of the stressed conditions, and the amount of incremental energy inventory incented by ESI, as the inventory can lower market prices, particularly during stressed market conditions, the presentation showed.
Stakeholder Amendments
Massachusetts Assistant Attorney General Christina Belew presented an amendment to remove replacement energy reserves (RER) from the ESI proposal. (See “ESI Methodology in Question,” NEPOOL Markets Committee Briefs: Jan. 14-15, 2020.)
“On a high level, we think that RER is both unnecessary to successfully implement FERC’s fuel security requirements, and we think it is not required to be priced for compliance with NERC or [Northeast Power Coordinating Council] standards,” said Belew’s colleague in the Massachusetts attorney general’s office, Ben Griffiths, an energy analyst for regional and federal affairs.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
The Massachusetts attorney general’s office argues that reserve deficiencies are uncommon, so the need for reserve restoration production is low. | ISO-NE
The RTO’s impact analysis has not demonstrated that RER would actually improve system reliability, he said.
RER has a much weaker link to fuel security, the reason for the market initiative, than either generation contingency reserves (GCR) or energy imbalance reserves (EIR) products, Griffiths said.
“While removing RER reduces some of the ISO’s desired incentives, it seems that removing [RER] will save $50 [million] to $142 million per year, depending on how you combine the different winter and summer seasons,” Griffiths said. “And in doing so it doesn’t disrupt the rest of the core ESI design — the GCR and EIR components, and the self-disciplining that they offer one another.”
Griffiths noted that much of the material in their presentation was not new, but that they updated data looking at the historical role of reserve deficiencies: their durations, magnitudes and season.
Based upon exogenous fuel assumptions, ESI tends to increase fuel availability, which might be helpful, “but the impact analysis does not show — when the rubber hits the road, when the system gets really tight and we start approaching reserve deficiencies — that ESI actually improves reliability,” Griffiths said.
“RER offers poor value for money,” he concluded.
Look Back, Carefully
The Massachusetts attorney general’s office and the New England States Committee on Electricity (NESCOE) are jointly sponsoring an amendment to add a look-back provision to the ESI program to enable evaluation of its efficacy.
Under the amendment, the Internal Market Monitor would assess the competitiveness of the energy call option offers and day-ahead reserve prices, determine if any uncompetitive prices are the result of market power and estimate any excess consumer payments resulting from market power.
“We are conscious of and want to respect the Market Monitor’s independence; so while we felt comfortable saying what one of the purposes of the evaluation would be, we leave it exclusively to the discretion of the IMM to determine what evaluation criteria it’s going to use,” Belew said.
The amendment proposes that the Monitor file a quarterly report of its findings with FERC, while ISO-NE will file a quarterly certification of the competitiveness of the energy call options and resulting prices.
Consumer costs scenarios under ESI | NESCOE
Jeff Bentz, NESCOE director of analysis, said his organization had open discussions of the various amendments with IMM staff, who were helpful.
“This ESI thing is in such flux, there’s only small pieces being proposed now,” Bentz said. “There’s a lot of work to do afterwards, so we thought it would not be fruitful to define the criteria here in this room between now and March 24” — the date of the MC vote.
NESCOE also put forward several ESI amendments to include a $10 strike price adder; set the RER quantity to zero for non-winter months; and remove accounting for load forecast error in RER.
“We really have worked hard starting back in July and August, and came to this committee in September, made changes and continued to work towards what we thought were amendments that would decrease consumer costs while still not harming the incentives for the objectives that ISO New England was trying to achieve,” Bentz said.
“This isn’t an attempt to just whittle down money and to be cheap,” he said. “It really comes back to what are the costs and what are the benefits. If we can get the same benefits at a lesser cost, that’s the right approach.”
The Markets Committee also voted to recommend that the Participants Committee support NESCOE-sponsored Tariff revisions relating to energy efficiency resource capacity supply obligations during scarcity conditions. (See “NESCOE Intent on EER Revisions,” NEPOOL Markets Committee Briefs: Nov. 12-13, 2019.)
MISO’s proposal to bring solar resources under its umbrella of dispatchable intermittent resources (DIRs) prompted a deficiency letter from FERC on Wednesday.
The commission directed MISO to be more specific about its defined categories of solar generation and exactly when the RTO intends for them to come under dispatch (ER20-595).
FERC said according to MISO’s transmittal letter accompanying the proposal, solar resources already in commercial operation “can, but are not required to” register under its DIR category, while solar resources with a generator interconnection agreement as of March 15, 2020, “are subject to the DIR registration requirement and will have until March 15, 2022, to register as a DIR.” Solar resources without a GIA as of March 15 “must register as a DIR in order to operate,” FERC summarized.
| Consumers Energy
However, the commission noted that MISO’s proposal didn’t similarly mention the three solar categories based on GIA date, only stating that “any generation resource fueled by solar energy not in commercial operation prior to March 15, 2020, may qualify as an intermittent resource but must register as a dispatchable intermittent resource by March 15, 2022.”
The commission asked MISO to clarify what solar resources are meant to adhere to the 2022 deadline. It also asked when solar resources must register as DIRs if they are without GIAs as of March 15, 2020, or if their commercial operation dates are later than March 15, 2022.
In preparing the plan, MISO said it was handling the dispatch expansion much like it did with wind generation in 2011. (See Anticipating Boom, MISO Extending Dispatch to Solar.) RTO staff have said they wouldn’t grandfather certain solar resources as DIRs.
PJM officials plan to hold the next Base Residual Auction about six months after they receive FERC approval of its compliance filing implementing the expanded minimum offer price rule (MOPR).
The proposed timeline will be included in the RTO’s compliance filing to expand the MOPR to new state-subsidized resources, due Wednesday.
“We have worked very hard at PJM to achieve a balance between the disparate stakeholder positions on this subject,” Stu Bresler, senior vice president of market services, told a special meeting of the Market Implementation Committee. “We need to get back on that three-year forward mechanism.”
FERC ordered PJM on Dec. 19 to expand the MOPR to new state-subsidized resources, including self-supply assets of cooperatives and vertically integrated utilities (EL16-49, EL18-178). (See FERC Extends PJM MOPR to State Subsidies.)
The Organization of PJM States Inc. (OPSI) voted last month to ask for at least 12 months between the FERC compliance order and the BRA, with a cap limiting the delay to no later than May 31, 2021. Regulators from Ohio and Pennsylvania abstained. Other market participants have urged PJM to conduct the next auction before the end of 2020.
Starting the Clock
Bresler said the RTO will need six months to plan the auction after the ruling, calling the expanded MOPR the biggest change to the capacity market since the beginning of Capacity Performance rules, which took effect with the 2015 BRA. “We can’t start that clock the day the compliance order comes out,” he said, adding the RTO will need about two weeks to review the ruling before beginning pre-auction activity.
Bresler said PJM officials will propose compressing the pre-auction activity timeline to six months from the normal nine months for the 2022/23 auction, which has been delayed since last year because of uncertainty over the rules.
PJM will ask FERC for flexibility to delay the 2022/23 auction until as late as mid-March 2021 if a member state passes legislation responding to the expanded MOPR before June 1 and the state requests the additional time.
PJM would seek to eliminate the first and second Incremental Auctions for delivery year 2022/23 if the Base Residual Auction is not held until December 2020. | PJM
Bresler said PJM didn’t want a blanket delay if no state legislation is passed but also didn’t want to lack the flexibility to respond to the states, which could seek to leave the capacity market by having their utilities adopt the fixed resource requirement. (See PJM’s MOPR Quandary: Should States Stay or Should they Go?)
Pre-auction activities would be compressed further to 4.5 months after the 2022/23 BRA. PJM said it would conduct BRAs for 2023/24 through 2025/26 at six-month intervals, with a six-week span between the posting of auction results and the beginning of pre-auction activities.
Incremental Auctions
PJM typically holds three Incremental Auctions for each delivery year, with the first 16 months after the BRA, the second 10 months later and the third in the February before the delivery year begins.
But officials said they may cancel the first or second IAs if required by the schedule. An IA will be canceled if: its normally scheduled date has already passed; if it would fall within the same calendar year as the BRA for that delivery year; or if it falls within 10 months from the BRA for that delivery year.
Asset Life Ban
PJM officials also outlined their proposals for implementing the asset-life ban provisions of the Dec. 19 order along with their definition of “asset life” and the treatment of generation-backed demand response.
FERC said a resource would be barred from the capacity market if it clears the market under the competitive exemption by initially forswearing state subsidies but “subsequently” accepts a subsidy.
Under PJM’s proposal, a resource would be barred from the capacity market if it clears the market under the competitive exemption by initially forswearing state subsidies but later accepts a subsidy for the delivery year in which it wins a capacity obligation. | PJM
PJM’s Pat Bruno said there is disagreement about what FERC meant by “subsequently,” with some stakeholders saying the ban is triggered if the resource ever accepts a subsidy after winning a capacity obligation.
But Bruno said PJM will propose that the ban apply only if a subsidy is accepted for the delivery year in which the resource was treated as new entry and won a capacity obligation.
Asset Life
FERC’s order said default cost of new entry (CONE) calculations should assume a 20-year asset life for all generation resources. But PJM said it will propose to allow asset lives of up to 35 years for resources seeking a unit-specific MOPR floor price.
“We want it to be reasonably close to commercial reality,” explained Adam Keech, vice president of market services.
Keech said PJM settled on the 35-year maximum based on Footnote 301 of the order, in which the commission responded to a proposal by the American Wind Energy Association, the Solar RTO Coalition and the Solar Energy Industries Association, which filed comments as “Clean Energy Industries.”
“Rapid changes in market conditions and generation technology could make resources uneconomic in less than Clean Energy Industries’ proposed 35 years,” FERC said.
PJM said it and the Independent Market Monitor will review claims of longer asset lives based on evidence including audited financial statements; project financing documents; independent project engineer opinions; manufacturer’s performance guarantees; and federal filings such as FERC Form No. 1 or SEC Form 10-K.
Generator-backed Demand Response
PJM also plans to propose generator-backed DR providers be allowed to provide evidence showing that the cost of a backup generator is not reflective of their cost to implement planned DR or their avoidable costs. DR providers have said that many backup generators are installed for resilience, not for provision of DR.
The RTO also will propose that DR providers be permitted to provide evidence showing reduced demand charges to offset the costs of a backup generator if the generator’s cost is included in the CONE or avoided-cost rate (ACR) for the DR.
PJM acknowledged that the demand charge savings could be difficult to quantify and will require subjectivity in resource-specific reviews. But the RTO said ignoring the savings would artificially inflate the net cost of providing DR.
Filing due Wednesday
MIC Chair Lisa Morelli ended Thursday’s meeting by saying it was unlikely PJM staff will have time to share a draft of the compliance filing prior to Wednesday’s deadline. “I don’t have huge expectations that we will have time to do so,” she said.
The U.S. Senate on Thursday voted 52-40 to confirm FERC General Counsel James Danly as a commissioner.
Three Democrats joined the Republican majority: Doug Jones (Ala.), Kyrsten Sinema (Ariz.) and Joe Manchin (W.Va.). Majority Leader Mitch McConnell (R-Ky.) on Wednesday filed a motion to invoke cloture on Danly’s nomination, which the Senate approved 54-40 Thursday morning.
Danly fills a seat left open by the death of Commissioner Kevin McIntyre in January 2019; his term will conclude June 30, 2023. His confirmation has been a matter of when, not if, since the Energy and Natural Resources Committee advanced his nomination, along with that of Dan Brouillette as energy secretary, to the floor in November. The Senate quickly confirmed Brouillette but did not get to Danly before it adjourned for the year. The ENR Committee re-advanced Danly on March 3. (See Danly Re-advances, but not Without Drama.)
FERC Chairman Neil Chatterjee photographed General Counsel James Danly (right) as he watched the Senate confirm him to be a commissioner March 12. | FERC Chairman Neil Chatterjee
Manchin, the ranking member of the committee, said prior to the confirmation vote that he was supporting Danly “because I believe he is well qualified for the job” and “he understands the complex legal issues that come before the commission.” But he lambasted President Trump for not nominating the Democrats’ choice — Allison Clements, clean energy markets program director for the Energy Foundation — to fill the seat left open by the departure of Cheryl LaFleur in August. Danly’s confirmation gives Republicans a 3-1 majority on the commission.
“The politics involved in this town is outrageous, truly outrageous, that even proper decorum, simple civility, just a little bit of procedure is not even considered any more,” Manchin said, adding that the administration was undermining “the bipartisan structure of the commission.”
He repeated a promise he made March 3 to oppose any Republican nominee to replace Commissioner Bernard McNamee, who has said he would not seek another term, unless they are paired with Clements. “I will not support another nominee unless we get both. This has got to stop. … Let’s make sure that we have a complete, working commission, and not just a partial commission that’s over-weighted.”
Senate Minority Leader Chuck Schumer (D-N.Y.) said on the floor that the White House has “given no reason or explanation why” Clements has not been nominated.
After the vote, FERC Chairman Neil Chatterjee said, “This is great news for FERC and for the country. I have appreciated getting to know and work with James as my general counsel, where he’s already proven to be an invaluable asset to the commission. James has an exceptional ability to carefully and thoughtfully consider the legal and regulatory questions raised by matters before us, and I look forward to working alongside him as a fellow commissioner.”
American Council on Renewable Energy CEO Gregory Wetstone also congratulated Danly but asked “the president to nominate, and the Senate to confirm, two more commissioners on a bipartisan basis to fill the remaining commission vacancies.”
McNamee’s term ends June 30, but he has said that if no replacement has been confirmed, he will stay on past that date until he is replaced or the end of the year, whichever comes first.
SPP on Thursday stiffened its response to the COVID-19 coronavirus with the strictest measures yet undertaken by an RTO or ISO.
The RTO said it is canceling all in-person stakeholder meetings through April and replacing them with virtual meetings. It is also prohibiting staff business travel and nonessential visitors from its facilities.
“Circumstances surrounding the spread of the COVID-19 coronavirus continue to evolve rapidly,” the RTO said. “The continued spread of the COVID-19 virus has prompted us to take several steps to safeguard the health and safety of all SPP stakeholders and the people with whom we work.”
The SPP Corporate Center | WER Architects
SPP’s actions mean the regular quarterly stakeholder meetings, originally scheduled for April at its Corporate Center in Little Rock, Ark., will now be conducted by webinar. Those meetings include:
Markets and Operations Policy Committee, April 14-15;
Strategic Planning Committee, April 15-16;
Regional State Committee, April 27; and
Board of Directors/Members Committee, April 28.
The grid operator promised to keep its stakeholders updated in the weeks ahead.
“Our incident coordination team continues to work closely with local, state and federal agencies and is meeting daily to assess whether additional safeguards are appropriate,” SPP said.
