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.)
Threats from the COVID-19 coronavirus and computer viruses occupied much of the discussion at the Western Electricity Coordinating Council Board of Directors meeting Wednesday, which could be the last in-person gathering the regional entity holds while the pandemic plays out.
CEO Melanie Frye said WECC would hold only webinars and teleconferences going forward to protect staff and stakeholders, in keeping with the Level 2 Alert issued by NERC on Tuesday. The situation will be reassessed every two weeks, she said. (See NYISO, MISO Join Operators in Suspending In-person Meetings.)
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.
NERC CEO Jim Robb addresses WECC’s board March 11. | Chad Coleman/WECC
NERC CEO Jim Robb, the former CEO of WECC, returned to his former workplace in Salt Lake City and talked about ongoing efforts to guard utilities against cyberthreats from “persistent, determined adversaries” abroad. Working with federal agencies, NERC has been developing computer programs to spot “untoward internet traffic” from nations such as Iran, North Korea and the Netherlands, a hub for hackers, he said.
Robb’s comments came a day after NERC warned the electric industry to “anticipate and prepare for coronavirus-themed opportunistic social engineering attacks.”
“Spearphishing, watering hole and other disinformation tactics are commonly used to exploit public interest in significant events,” NERC wrote in its alert. “Take steps to ensure continued visibility and maintenance of cyber assets in the event of staffing disruptions.”
NERC has been working with industry to provide advice and information about the coronavirus, including publishing a document titled “Assessing and Mitigating the Novel Coronavirus (COVID-19)” on the Electricity Subsector Coordinating Council’s website.
In her presentation, Frye said WECC had decided to cancel its Reliability and Security Workshop in Portland, Ore., scheduled for March 24-26. Instead, the RE plans to offer a free one-day webinar on March 24 to discuss the most important topics from the workshop. Frye said it will issue refunds to those who have already registered and paid.
Left to right: WECC CEO Melanie Frye, board Chair Kristine Hafner and Vice Chair Ian McKay. | Chad Coleman/WECC
NERC’s Level 2 Alert requires a wide range of electric industry entities to report back to NERC by March 20 on preparedness for a pandemic.
“It’s a really good step from the ERO Enterprise perspective to just make sure we’re coordinating with industry and getting the information that we need to assure [that] in the event we have a shortage of workforce — if a large population is quarantined or ill or needing to take care of people who are ill — how would we run our business?” Frye said. “And then also thinking through the impact on supply chain — what if we’re not able to get the equipment that we need, etc.?”
WECC’s executive team has been updating the ERO’s business continuity plans and preparing “in the event that we need to take steps here at WECC, such as remote work and things of that nature,” Frye said. “One of the issues that we will face —and I think many organizations are probably finding this — telework is a great idea, but do we have the IT bandwidth and resources to support that?”
WECC managers planned to meet Thursday to discuss their options, she said. “There are some steps we’re thinking through now in anticipation of something maybe bigger,” Frye said.
For Associated Electric Cooperative Inc. (AECI), the results of a 2016 audit for compliance with reliability standard FAC-008-3 came as a shock.
The utility had assumed it was complying with the standard, which governs the determination of transmission facility ratings; instead, auditors discovered that the software it used to calculate ratings was missing a number of key pieces of information, resulting in widespread inaccuracies in its facility ratings.
“We came into it [thinking] we were living in happy-camper-ville, and came to find out we were not there,” James Vermillion, senior transmission planning engineer with AECI, told SERC Reliability’s Spring Compliance Seminar this week in Charlotte, N.C. “[We] wound up with a very concerned attitude about it [and] did develop a mitigation plan to correct the situation. So … over the course of a year, we went out … to inspect and field-verify 25% of the system each quarter.”
SERC headquarters in Charlotte, N.C. | SERC
Physically inspecting the facilities was only the beginning of AECI’s mitigation efforts; more important was the work the company spent over the next three years overhauling its rating methodology and associated computer systems. Among other things, AECI installed a new software layer to ensure that any changes in relevant data are flagged so that engineers can ensure the central database has been updated accordingly, along with updating its procedures to ensure all personnel know how to use the new system and that its reliability coordinator has full access as well.
The changes, amounting to 13 new internal controls coordinating the efforts of 11 companies and departments, paid off in 2019 when SERC re-audited AECI in 2019 and gave the company a “clean bill of health.” AECI has continued to implement changes since its second audit. Work recently began on expanding the company’s data collection to include 7,000 miles of 69-kV lines.
LUS Earns Praise with Comprehensive Approach
Vermillion was one of several presenters at the SERC gathering who stressed the importance of internal controls in preventing violations of NERC reliability standards, or in detecting and eliminating ongoing infractions. A very different audit experience was recounted by Andrew Ledoux, an electrical engineer at Lafayette Utility System (LUS) in Louisiana, which joined SERC in 2018 after the dissolution of the SPP Regional Entity. (See FERC Approves Dissolution of SPP RE.)
Although LUS’ geographical footprint is relatively small, primarily covering only the city of Lafayette, the utility is registered as a balancing authority; transmission owner, operator and planner; generator owner and operator; and distribution provider. As a result, the entity is subject to enforcement of 77 NERC standards, and the compliance burden can be higher than expected, as Ledoux found out when he began to review the utility’s systems ahead of its first audit by SERC for violations of critical infrastructure protection (CIP) standards.
“About a year and a half ago, I didn’t know what an internal control was,” Ledoux said. “So it took a little bit of time to research … and what we found [is] that all this is is just a reminder that you need to do something for compliance.”
Ledoux and his team built up the utility’s expertise quickly, with a complete set of CIP internal controls in place by March of last year. The system included multiple gatekeepers — individuals responsible for monitoring open tickets and ensuring they are completed before the due date — and periodic reviews of policies and procedures to evaluate their real-world impacts. When the CIP audit team inspected the company in November 2019, auditors found no potential violations and no areas of concern.
Striking Control System Balance
One of Ledoux’s biggest struggles was with resisting the urge to go overboard with LUS’ control schemes. The company had to find the right mix of preventive measures, to ensure that violations never arose in the first place; detective controls, to find infractions once they occurred; and corrective actions, to stop ongoing issues and repair any damage that has occurred. To make the most of limited manpower and resources, the company decided to base the plan around preventative controls, complemented by a small amount of detective measures.
“Part of the problem I was having was getting too bogged down with … all these controls,” Ledoux said. “Just focus on preventative, and you can always expand later, if you want to go that route.”
Justin Kelly, senior CIP auditor at SERC, provided a different perspective. Kelly emphasized that while 100% compliance is always ideal, utilities cannot realistically expect to hit this target all the time — and do not, in fact, do so, judging by the number of infractions his team has identified. He suggested that when utilities assume that violations will occur despite their best efforts, they can pursue a more comprehensive mitigation strategy.
“I agree with Andrew, to a point, that preventative is the first way to go, because there’s a lot of things that you can catch through getting yourself a nice base of preventative,” Kelly said. “But really the next step to maturity is [through] detective [controls], because once you do the detective [work], you’re going to catch the things that you never thought would happen.”
NERC has opened a formal comment period on a draft reliability guideline covering the collection of data on distributed energy resources to run through April 24.
“As the penetration of DERs continues to grow, representing DERs in planning assessments becomes increasingly important,” the guideline says.
Under the planned guideline, TPs and PCs would be responsible for setting clear and consistent requirements for collecting aggregate DER data and sharing the information gathered with distribution providers and “any other external parties … performing DER forecasting to the TP and PC for modeling purposes.”
| FLS Solar
TPs and PCs may establish different requirements for utility- and retail-scale DERs based on their size, impact and location on the distribution system. For example, utility-scale DERs may be required to provide more detailed information on the facility, while aggregate retail-scale DER data can be collected without reference to individual facilities.
The SPIDER team has become increasingly concerned about a lack of understanding among TPs and PCs about the ways that DERs interact with the grid. This blind spot was highlighted in a white paper discussed at last week’s Planning Committee meeting, as well as in a presentation at a meeting of the SPIDER group earlier this year by Thomas Bialek of San Diego Gas & Electric. (See Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners.)
In that presentation, Bialek described a number of counterintuitive observations about behavior of DER users in his utility’s service territory — including users of both rooftop solar panels and batteries. Among SDG&E’s findings was the fact that customers seem to use even more energy after installing DERs than they normally would.
“Effectively they say, ‘I’ve put a PV system on my roof, or a battery — I’m now in charge, and I’m going to do whatever it is I want to do,” Bialek said. He dubbed this pattern of increased usage a “hidden load” that can’t be accounted for in system planning, either to tune the output of DERs or to predict how users will behave in the event of widespread service disruption.
One challenge that Bialek identified for the collection of DER data is the existence of privacy laws in some states that prevent utilities from monitoring these devices. The proposed guideline does not directly address this issue, but it does hold up the Australian Electricity Market Operator’s DER Register as a model of effective DER data collection that “[balances] information and transparency” and is “accessible and easy to use, while confidentiality and privacy are protected.”
PJM will present a problem statement and issue charge to the Markets and Reliability Committee later this month on its proposal to apply its effective load carrying capability (ELCC) calculation to include storage resources.
PJM’s Andrew Levitt told the Planning Committee that RTO officials identified ELCC, which was already under consideration for solar resources, as “an effective alternative” to the 10-hour minimum run time requirement that was rejected by FERC in October.
ELCC evaluates reliability in each hour of a simulated year and compares a resource mix with limited resources against one with unlimited resources. A resource that contributes a significant level of capacity during high-risk hours will have a higher capacity value than a resource that delivers the same capacity only during low-risk hours.
On Oct. 17, FERC partially approved PJM’s Order 841 compliance filing but set a paper hearing to determine whether its 10-hour minimum run-time requirement for storage seeking capacity obligations is unjust and unreasonable. FERC Partially OKs PJM, SPP Order 841 Filings.)
In November, PJM requested a 90-day extension on the initial brief deadline for the hearing and asked that the proceeding (EL19-100, ER20-584) be held in abeyance until Jan. 29, 2021, when it hopes to file Tariff changes applying ELCC to storage for all intermittent and limited-duration resources. It has proposed a new senior task force to discuss the issue.
FERC set a new deadline for initial briefs for April 27. Responses to PJM’s motion for abeyance are due March 11.
Order 845 Update
PJM’s Susan McGill reviewed the changes proposed by PJM in its Feb. 21 compliance filing on FERC Order 845.
In December, FERC approved six of PJM’s 10 Order 845 proposals but required changes on four issues regarding contingent facilities (unbuilt interconnection facilities and network upgrades upon which the interconnection request’s costs and timing are dependent); provisional interconnection service that allows limited operation of a generating facility prior to completion of the full interconnection process; surplus interconnection service (any unused portion of interconnection service established in a large generator interconnection agreement); and the rules governing technology changes that can be considered without affecting the interconnection customer’s queue position (ER19-1958).
PJM’s Feb. 21 filing seeks to address FERC’s concern over a lack of transparency regarding contingent facilities by clarifying the scope of the study and the criteria used. It also clarified that studies for provisional interconnection service will be conducted annually.
FERC required PJM to conduct the surplus interconnection service process outside of the interconnection queue. PJM’s revisions also require that surplus service be only from in-service generators and that use of the service cannot impact the existing system or other queue projects as determined by load flow, short circuit and stability analyses. Applicants will be required to make a study deposit of $10,000 plus $100/MW.
PJM revised its process to allow technology changes as long as they do not increase the size of the project or change a generator’s fuel type. Technology changes must be submitted before the return of a facilities study agreement without a material modification review.
The RTO asked that the changes take place 60 days following the commission’s acceptance except for surplus interconnection service, for which it requested 180 days.
Critical Infrastructure Ruling Expected
PJM’s Christina Stotesbury told the PC that the RTO expects a ruling within days on the Transmission Owners sector’s proposed confidential process to mitigate critical infrastructure on NERC’s critical infrastructure protection (CIP-014-2) list.
The PC has held three special Critical Infrastructure Stakeholder Oversight sessions, at which stakeholders separated issues into two categories: mitigation of existing CIP critical facilities, and avoiding creating new critical facilities, Stotesbury said.
A fourth meeting is set for 1-4 p.m. on April 3. Regardless of how FERC rules on the TOs’ proposal, “we are still planning to move forward working the avoidance issue and defining a more transparent process to prevent those facilities from becoming CIP-critical,” she said.
PJM to Expand PMU Deployment
PJM’s Shaun Murphy said the RTO plans to expand the use of synchrophasors and formalize their placements — currently voluntary — into the Regional Transmission Expansion Plan.
Murphy said the RTO will begin discussions in the PC to require synchrophasors — also known as phasor measurement units (PMUs) — in all new substations and major construction projects to monitor bus voltage and line flows. He said the communication equipment needed at each substation costs $50,000 to $100,000. Each substation would have two or three PMUs — provided by already installed equipment such as relays or digital fault recorders.
PJM is looking to expand the use of synchrophasors, in part, to help diagnose future oscillation events, like the one in January 2019, when a malfunctioning steam unit in Florida sent the Eastern Interconnection rocking like an unbalanced washing machine for 18 minutes. | PJM
PJM also plans to install 14 additional PMUs and retrofit four PMUs to support interconnection reliability operating limit (IROL) monitoring.
In addition to current roles in post-event analysis and oscillation detection, PJM plans to expand PMUs’ use to include detection of system islanding and other events and as backup monitors for area control error (ACE).
2020 RTEP Proposal Window Eyed
PJM posted the summer peak case for the 2020 RTEP on Feb. 28 and is asking transmission providers to begin their Form 715 analyses. The RTO plans to post preliminary violations between April 15 and May 1. It will open a competitive proposal window on potential solutions June 1.
Landfill Retirements Cleared
PJM’s reliability analyses found no reliability violations from the retirement of three landfill gas generators: Sussex County landfill (2 MW) in the JCPL zone and the Salem County landfill (1.7 MW) in the AEC zone, both retiring April 26, 2020; and the BC landfill (6 MW) in the PSEG zone, retiring May 31, 2023.
Analyses are underway on the retirement of the coal-fired Chesterfield Units 5 and 6 (1,015 MW) in the Dominion zone, retiring May 31, 2023, and Keystone NUG (4.9 MW) in the PPL zone, retiring May 31, 2020.
Questions on PPL Supplemental Project
TOs presented summaries of $173 million in supplemental projects, led by American Electric Power ($105.9 million) and PPL ($63 million).
Baltimore Gas and Electric presented two projects totaling $3.2 million, and Dominion Energy presented two projects totaling $1.25 million.
AEP’s biggest project is in response to the termination of the Department of Energy’s plan to retire its X 530 substation, which is connected to the Ohio Valley Electric Corp. (OVEC), and its request for a new delivery point at AEP’s Don Marquis substation. The total cost to AEP is estimated at $30.4 million, with OVEC spending an additional $4.4 million.
OVEC was created in 1952 to service a DOE uranium enrichment plant near Piketon, Ohio, that ceased operations in 2001. DOE ended the 2,000-MW contract in 2003 but maintains a load estimated to peak at 38 MW. (See FERC OKs OVEC Move to PJM.)
PPL said scope changes have reduced the cost of a supplemental project in northern Pennsylvania from $95 million to $63 million (S1106).
A representative of the PJM Industrial Customer Coalition questioned why a $63 million supplemental project is being built by PPL as a stability project rather than being considered within the Regional Transmission Expansion Plan. | PPL
The project was originally presented before the M-3 process in January 2016 and called for building a new 230/500-kV substation and tapping the Sunbury-Susquehanna 500-kV and 230-kV lines and the Columbia-Frackville 230-kV line to address a stability issue in the Montour area. PPL said a three-phase fault with normal clearing on the double circuit Montour-Susquehanna 230-kV line will cause generator instability and tripping of several power plants totaling 2,400 MW.
PPL’s Shadab Ali said the new design involves 22 miles of second circuits on existing 230-kV lines between the Montour, Milton and Sunbury substations and rebuilding 12 miles of the Montour-Milton 230-kV line to double circuit. The project would also change the operating voltage of about 10 miles of 69-kV line between the Milton and Sunbury 230-kV substations and line terminal work at the Montour, Milton and Sunbury substations. The project is expected to be online by the summer of 2023.
David Mabry of the PJM Industrial Customer Coalition said he recognized the region as a “generation pocket” for PPL but questioned why stability issue concerns weren’t identified in the RTEP process or through the generation interconnection studies rather than being a supplemental project.
“It seems like we might be transferring cost allocation onto PPL’s end-use customers [for what is] a network-type upgrade,” Mabry said.
Ali said the project was originally proposed based on an actual event that identified it as a weak area in the system. With as much as 45% of PPL’s generation coming from that region, Ali said the utility wanted to address the issue even though it did not violate PJM or PPL criteria.
“It’s a little bit more than what is required in terms of criteria,” Ali said. “That’s why it’s not part of the RTEP process.”
Mabry asked if paying for the risk was being misallocated and said new generating facilities that affect stability should have some responsibility for the upgrade costs.
“Obviously new generation is going to make the situation worse, but there’s no way that new generation coming online making the situation worse has any cost responsibility in fixing the problem,” Mabry said.
Ali said Mabry’s feedback would be considered in potential changes to PPL planning criteria.
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.
