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.
Fresh off approval for one change to its interconnection process, MISO is still looking for more ways to advance generation projects more quickly through its queue, stakeholders learned Tuesday.
The RTO put out the renewed call for ideas during an Interconnection Process Working Group (IPWG) meeting that was converted to a conference call as MISO responds to the COVID-19 coronavirus outbreak. (See related story, MISO Steps Up COVID-19 Response.)
MISO is seeking ideas to allow it to simultaneously perform analyses under the definitive planning phase (DPP) and the annual Transmission Expansion Plan, possibly identifying projects that can meet multiple needs. (See MISO Committees Tackle Queue, Tx Planning Disparities.)
“We’re going to strive to improve the process for our customers,” MISO engineer Cody Doll said. “If we’re on the same timeline, we could have common models and joint solution development. … It won’t be a bifurcated effort. It’ll be a coordinated effort between the two functions.”
MISO queue | MISO
Doll said he would return to the IPWG in May with more discussion and early proposals. MISO doesn’t yet have a specific target date for when it would file changes to its queue.
It takes just under a year for a proposed generation project to clear the interconnection queue. MISO’s current queue contains 489 projects representing 76.5 GW. Nearly 60% of the projects are proposed solar generation.
“Keep in mind we were over 100 GW after last April’s application deadline,” MISO Manager of Resource Utilization Project Management Jesse Phillips told stakeholders. MISO’s next project application window for the interconnection queue closes June 25. The deadline was extended because of the late April rollout of a new online application tool. (See MISO to Debut Online Queue Requests.)
MISO is also drafting Business Practices Manual language for its new, firmer requirement that project sponsors prove exclusive land use for generation projects entering the queue.
The RTO in December won approval to require interconnection customers to demonstrate 100% site control 90 days before proposed projects enter the first phase of the three-phase DPP of the interconnection queue for study. It also scrapped the previous practice of accepting a $100,000 cash deposit in lieu of demonstrating site control. (See MISO OK’d to Require Site Control in Queue.)
The RTO’s site control land requirements are now 50 acres/MW for wind generation, 5 acres/MW for solar generation, 0.1 acres/MW for battery storage facilities and a standard 10 acres for conventional generating facilities.
MISO has said it will use contractors to help review site control documentation. The cost for project reviews will be charged to customer’s study deposit, similar to other queue study costs. Paul Muncy, of MISO’s transmission access planning division, said the RTO uses contractors for “numerous other project-related studies.”
Muncy said MISO “intends to review site control documentation for each project in order to ensure that no projects are able to take an unfair advantage in proving that they have met all requirements.”
After stakeholder inquiries, Muncy said MISO had more work to do to outline in the BPM what official documentation it will accept as proof of land use. Multiple stakeholders said the style of documentation varies on a county-to-county level and that the RTO’s documentation requirements could be overly burdensome by not accounting for those differences.
AUSTIN, Texas — Some utilities are taking a hard look at non-wires alternatives (NWAs) given the difficulty and expense of getting transmission projects approved, gaining regulatory sign-off, and siting and building lines.
Speaking last month at Infocast’s ERCOT Market Summit, Hudson Gilmer, founder and CEO of line-monitoring firm LineVision, said his company and others like it offer options in the likely absence of a second competitive transmission build in Texas.
The first such effort — kicked off in the mid-2000s — resulted in 3,600 miles of transmission facilities able to carry 18.5 GW of capacity. The Competitive Renewable Energy Zone buildout, which ended in 2014 and cost $6.8 billion, connected barren and windy West Texas with the state’s eastern and southern urban centers and set the stage for the massive development of renewable energy that was to follow.
Those lines are now full. ERCOT, which operates 90% of the state’s grid, had 23.9 GW of wind capacity at the end of 2019. Another 12.2 GW of wind energy could be added by the end of 2022, while solar capacity could quadruple to nearly 10 GW during that same time.
“What we heard from the wind and solar developers is that transmission is the single-largest obstacle to continue integrated new renewables on the grid,” Gilmer said. “What we’re seeing with new, large transmission projects is that they tend to be fully subscribed. It’s a chicken-or-egg thing. We believe there is an opportunity … to take a fresh look at transmission. Not in the way we’ve built it during the last 75 years, but as a way to unlock additional capacity on the grid.”
Gilmer said he recently learned that typical usage on the average ERCOT transmission line is under 20%.
“That makes me pretty mad,” he said. “If we can use technology to unlock additional capacity on those lines, that makes a difference and can make a project more viable when it suddenly didn’t pencil out.”
LineVision offers continuous monitoring of transmission line conductors to confirm they are performing within their acceptable operating limits. By taking advantage of low-cost sensors, Gilmer said, his company can watch for sagging lines and push out additional capacity when the line cools.
“Not every line is monitored in ERCOT,” he said. “The transmission operator has to make very conservative assumptions about the line.”
Gilmer said topology control, which uses a software-based solution to identify grid reconfiguration opportunities on open relays and alleviate congestion, can offer a similarly less capital-intensive solution to building new high-voltage transmission lines.
Noting that close to half of all congestion in ERCOT is outage-related, he said LineVision advocates a shift in transmission construction.
“Traditionally, we build through towers and wires. Here’s an opportunity to invest in Texas using software and analytics at a fraction of the cost, making the grid much more flexible and reliable and less expensive,” Gilmer said.
Making the Case
David Townley, director of public policy for CTC Global, plugged his company’s advanced conductors. CTC’s conductors use high-strength, lightweight carbon and glass fibers that helps them withstand extreme peak-load conditions and reduce thermal sag.
“By replacing steel with carbon fiber, you’re changing the performance of [the wire’s] steel core, so it doesn’t sag that much,” Townley said. “Less sag allows you to put more current through the line.”
Townley said the conductors have resulted in about a 20 to 60% increase in operating capacity on an existing system, and “up to 100% in emergency situations.”
“Freeing up that capacity gets more out of the existing system,” he said.
“I sleep better at night when I don’t have to worry about how close a conductor is sagging to the ground,” said Jonathan Greene, senior vice president of transmission operations for Lower Colorado River Authority. “Not having to upgrade or replace wire to get 15 to 20 additional feet is a benefit.”
Greene said LCRA has installed advanced conductors in four locations, three of them in river or lake crossings, using 30-year-old existing towers. He said the cooperative has seen increased line ratings but noted that LCRA hasn’t seen that advanced conductors are cost effective for a full line upgrade.
“Advanced conductors are fantastic, but they’re still fairly expensive,” Greene said.
Gilmer, who advocates a shared-cost model, empathized with Greene.
“Regulated utilities need incentives to adopt these technologies. If you alleviate congestion with one of these technologies, you should get to share a percentage of those savings,” Gilmer said. “We’ve been very encouraged by the response we’ve gotten at the federal level and at some state commissions. We’re seeing, especially in the wake of California and the wildfires, an increased awareness of the safety risk for unmonitored lines. We feel like there’s a very compelling return on investment in deploying sensors for situational awareness and anomaly detection.”
Electric Transmission Texas President Kip Fox, whose joint venture between American Electric Power and Berkshire Hathaway Energy was involved in CREZ, posited that NWAs could actually increase returns on transmission lines.
“There’s a lot of downward [regulatory] pressure on returns,” Fox said, voicing an imaginary argument in favor of NWA upgrades. “‘Hey, I’ve made this line more valuable [through NWA]. Why can’t I have a higher return on this line?’”
PJM’s Planning Committee delayed a vote Tuesday on a new regional targeted market efficiency project (RTMEP) process to consider whether it can be approved without first considering related cost allocation rules.
The RTO said cost allocation is the responsibility of transmission owners under the Consolidated Transmission Owners Agreement (CTOA) and should not be considered until FERC approves the planning change. It cited the timeline for the recent change to the market efficiency benefit/cost ratio, which was approved by FERC in February 2019 (ER19-80) and followed by a cost allocation filing in January 2020 (ER20-776).
LS Power’s Sharon Segner acknowledged that cost allocation is the TOs’ responsibility. But she said FERC Order 1000 requires any regional planning process to be accompanied by a “cost allocation methodology.”
“We believe this is a different situation than in the past … What’s being proposed here is an entirely new type of regional planning project with … new parameters; new conditions; new modeling,” she said. “We don’t think it’s possible to separate the cost allocation from the planning protocol under Order 1000, and stakeholders deserve to understand both at the same time.”
PJM attorney Pauline Foley disagreed with Segner’s conclusion, saying FERC has historically reviewed planning processes separately from cost allocation. “We believe, based on historical practices, that should not forestall us moving forward,” she said.
The committee ultimately approved a motion by Alex Stern of Public Service Electric and Gas to defer the vote for two months and allow LS Power to share a legal memo with the PC outlining its arguments. The issue of cost allocation had been ruled out of scope in the proceedings of the Market Efficiency Process Enhancement Task Force, which developed the three sets of packages on which the PC had been scheduled to vote.
Stern made his motion after Segner said she would raise a point of order via a legal memo on the issue at the Markets and Reliability Committee meeting if the package advanced beyond the PC before considering the cost allocation. “I’d rather discuss it in a collaborative fashion rather than a contentious one,” he said. “We worked hard to get consensus. While I don’t necessarily agree with LS Power’s legal conclusions, I would like to see them before I’m having to see them at the MRC.”
The packages address changes to the benefit calculation, the window for capacity drivers and the RTMEP process, and included proposals from PJM, the Independent Market Monitor, American Electric Power and FirstEnergy. (See “Market Efficiency Process Enhancement Packages,” PJM PC/TEAC Briefs: Feb. 4, 2020.)
Storage as Transmission
LS Power also challenged PJM during a discussion on the RTO’s efforts to develop rules for treating energy storage as a transmission asset.
PJM hopes to develop rules by the end of the year for treating storage that would be dispatched by the RTO to address thermal, voltage or stability violations or to relieve transmission constraints. Other potential drivers are operational performance (mitigating real-time violations not identified in planning studies) or public policy (grid enhancements requested by a state to further its policies). The PC is scheduled to review a draft issue charge at its April meeting.
Segner has raised questions about a proposal by AEP to use storage to correct repeated outages on its Falcon-Prestonsburg 46-kV circuit (AEP-2018-AP010). AEP said the 23-mile line, which dates to the 1940s and 1950s, is plagued by rotted wood poles and damaged guy wires and cross arms.
The company proposed a supplemental project to install a 2-MW battery at its Middle Creek substation at a cost of $9.7 million; rebuild 8.5 miles of 46-kV line between Prestonsburg and Middle Creek station ($25.5 million); and retire 14.5 miles of 46-kV line between Falcon and Middle Creek ($6.1 million).
AEP has proposed a $41.3 million project to use storage to help correct repeated outages on its Falcon-Prestonsburg 46-kV circuit, which dates to the 1940s and 1950s and is plagued by rotted wood poles and damaged guy wires and cross arms. | AEP
AEP said the total cost of $41.3 million would save almost $30 million over the $70 million cost of rebuilding the entire 23-mile line.
Segner said PJM cannot include non-transmission alternatives such as storage in the Regional Transmission Expansion Plan until it has been designated as transmission by FERC. Allowing AEP to win approval of the project under the M-3 process — which is limited to TOs — discriminates against non-TOs, she said.
PJM’s Aaron Berner said the RTO disagrees with LS Power’s position. “We don’t believe there are any issues about how the M-3 process is being followed,” he said. “The asset is being proposed in accord with that process.”
Segner said her company might seek to use the dispute resolution process under M-3.
“We would like to avert dispute resolution,” Berner said. “But if you wish to continue that … we can start discussions on how to move that forward.”
“Hopefully FERC will rule on the MISO issue sooner rather than later,” Segner said. A few hours later, FERC did rule, ordering its staff to schedule a technical conference on the issue. The commission said MISO’s Tariff changes “may be unjust, unreasonable, unduly discriminatory or otherwise unlawful” (ER20-588). (See related story, MISO SATOA Proposal Set for Technical Conference.)
FERC Chair Neil Chatterjee and Commissioner Bernard McNamee on Tuesday reversed the commission’s November 2018 order correcting a key calculation in evaluating ISO-NE’s capacity delist bids (ER18-1770-002).
At issue is how ISO-NE’s Internal Market Monitor calculates the economic life of resources that want to retire or permanently leave the capacity market. Such a resource must provide at least five years of cash flow estimates to justify their delist bids, which specify the price at or below which it would retire. The rule change was intended to correct calculations that ISO-NE said overstated the true economics of some resources and could result in improperly high delist bids.
“We find that the benefits of ISO-NE’s economic life revisions do not outweigh the disruption to market participants’ settled expectations associated with changing an FCM [Forward Capacity Market] rule regarding delist bids after the [Forward Capacity Auction] 13 qualification process for those delist bids had commenced,” the commissioners wrote. “Thus, we reject the economic life revisions in their entirety, effective Aug. 10, 2018.”
The 2-1 vote granted a rehearing request by the New England Power Generators Association (NEPGA), which asked that the commission make the economic life revisions effective, “if at all, beginning in FCA 14.” That auction was held last month. (See ISO-NE Capacity Prices Hit Record Low.)
In the 2018 ruling approving the calculation changes, Commissioner Richard Glick joined with then-Commissioner Cheryl LaFleur in the majority. Chatterjee filed a dissent saying that making the change effective for FCA 13 violated the commission’s rule against retroactive ratemaking because market participants had made commercial decisions based on Tariff rules in place before the ruling. (See Split FERC OKs New ‘Economic Life’ Rules for ISO-NE.)
This time around it was Glick dissenting, insisting that the original ruling “correctly balanced the harms and benefits of ISO New England’s proposal.”
“I note that nothing in today’s order precludes ISO New England from refiling substantially the same provisions tomorrow,” he added. “Today’s order, as I understand it, is concerned only with the timing of ISO New England’s previous filing and not its merits.”
ISO-NE spokesman Matt Kakley said Wednesday the RTO will determine its next steps after reviewing the order.
Chatterjee and McNamee agreed with NEPGA’s contention that a market participant that chose not to submit a retirement delist bid in FCA 13 based on the then-existing economic life calculation might have submitted such a bid under the revisions based on expectations of future FCA clearing prices.
But they declined to order FCAs 13 and 14 be rerun without the economic life revisions, saying that would create more harm than benefit.
“We acknowledge the harm to market participant confidence resulting from changing the economic life calculation for delist bids midway through the FCA 13 process,” they said. “However, we find that, because rerunning FCA 13 and FCA 14 would further decrease market participant confidence, such action is ill-suited to providing market participants relief in these circumstances.”
Deadline Waiver Granted
The commission also granted a waiver allowing market participants to adjust or withdraw their retirement or permanent delist bids for FCA 15 based on potential changes to ISO-NE’s Energy Security Improvements proposal (ER20-759).
ISO-NE is expected to file the ESI proposal on April 15, following a vote by the New England Power Pool Participants Committee on April 2 — after the FCA 15 delist deadline of March 13.
The RTO requested the waiver, saying that market participants’ retirement bid decisions may be affected by revenues they will earn or costs they incur under the ESI proposal.
The commission said it will extend the March 13 deadline through seven calendar days after the PC vote. If ISO-NE makes “a non-clerical change” to the ESI proposal after March 13, market participants will have seven calendar days following the vote to either withdraw their bid or update their retirement bids to reflect the changes.
MISO and SPP staff are both recommending that the RTOs take another stab this year at a coordinated system plan (CSP) in their elusive pursuit of an interregional project.
Staff have identified 10 congestion areas that merit further evaluation and shared them with stakeholders Tuesday during the Interregional Planning Stakeholder Advisory Committee’s annual issues review. The areas were selected based on their level of congestion and shadow prices, which both RTOs use to identify economic congestion issues.
MISO and SPP have conducted three joint studies since 2014 but have yet to come up with a project to which both could agree. The RTOs modified project criteria last year to improve their chances of reaching an agreement, although differences still remain. The changes included a mandated frequency of CSP studies, elimination of the $5 million cost threshold for the projects, addition of avoided costs and adjusted production cost benefits to project evaluation, and removal of the joint modeling requirement in favor of individual RTO regional analyses. (See MISO, SPP to Ease Interregional Project Criteria.)
| SPP, MISO
The recommendation to undertake a CSP must still be approved by the Joint Planning Committee, which is composed of a representative from each RTO and meets later this month. Assuming its approval, the CSP process would begin shortly thereafter with the scope’s development. Initial portfolios would be filed by each grid operator in August.
The Advanced Power Alliance (APA), American Wind Energy Association and Clean Grid Alliance (CGA) filed a joint letter with the IPSAC supporting the need for interregional planning. They said it is a need that “continues to increase as the use of the grid evolves” with renewable energy’s replacement of fossil fuel generation.
“It should now be clear that forward-looking regional transmission planning is indispensable to ensure both reliability and cost-effective results for customers,” the organizations wrote.
APA’s Steve Gaw highlighted the need to address current restrictions on moving power between MISO North and South. Ben Stearney, MISO’s interregional planning adviser, said the RTO has been evaluating the issue since last year but has found placing the solutions in the CSP to be a “gray area.” (See Interregional Projects May Become Reality for SPP, MISO).
CGA’s Natalie McIntire raised concerns about MISO’s 2019 futures, which are also being used in its 2020 Transmission Expansion Plan models, saying they are “not very representative of what the future is likely to be like.”
Stearney said his staff are working “diligently” on its 2021 futures. However, the futures are not likely to be ready for the 2020 study.
“Part of the advantage of the new process is that it allows us to refresh on an annual basis,” Stearney said.
Regulators’ Seams Committee Wants More Info
Meanwhile, the Organization of MISO States (OMS) and the SPP Regional State Committee’s (RSC) Seams Liaison Committee (SLC) is seeking more information from the RTOs before it scopes its own interregional issues analysis.
The committee decided this week it wants an updated analysis on historical congestion across flowgates and more information on the process behind evaluating interregional reliability projects.
Adam McKinnie, chief economist with the Missouri Public Service Commission, said the SLC is seeking transparency into how individual transmission owners collaborate to propose potential reliability projects across the seams to the RTOs.
| SPP, MISO
“We’re looking for how that evaluation takes place,” McKinnie said during a conference call Monday.
The committee said it has identified “a potential disconnect and general lack of coordination in the [CSP] interregional planning process.”
“Although reliability projects can be proposed through the interregional planning process, this does not occur, and planning for reliability continues to happen predominately separately, or on an ad hoc basis through individual transmission owner collaboration,” the SLC wrote.
To date, MISO and SPP have not approved a seams reliability project, instead favoring regional projects. MISO officials have attributed that to low load growth in recent years, saying the RTOs haven’t had the need for reliability projects along their seams. Staff from the RTOs have also maintained that their reliability planning processes are fundamentally different.
“I don’t have the belief that the seams are so different that we couldn’t benefit from a coordinated reliability process,” McKinnie said.
The SLC will also ask MISO and SPP for a presentation on historical market-to-market congestion using 2018 and 2019 data that could be used in an upcoming CSP. Finally, the SLC is also asking that MISO and SPP detail how it plans to address flowgate congestion now that it has an improved CSP process in place.
The committee won’t select a direction or draft a scope for their seams analysis until they have more information on the two topics.
The OMS and RSC in January laid out the option to either re-examine the RTOs’ past analyses of proposed interregional projects or embark on a series of smaller studies on congested flowgates that could produce entirely new project proposals. (See MISO, PJM Weighing New Interregional Study.)
MISO on Monday introduced temporary measures to contain the COVID-19 outbreak, converting all in-person meetings to conference calls and barring visitors from its three offices until further notice.
The prohibition on visitors covers RTO offices in Carmel, Ind.; Eagan, Minn.; and Little Rock, Ark. Indiana and Minnesota both recently recorded their first cases of COVID-19, while Arkansas so far has no confirmed cases.
MISO has tightened access to its control room and put a hold on all control room tours. It has also suspended all non-essential business travel for its employees.
MISO Little Rock headquarters | Google Maps
The conference call policy applies to this week’s March 10 Interconnection Process Working Group meeting and March 11 Planning Advisory Committee meeting and Integrated Roadmap workshop. MISO doesn’t have any in-person meetings scheduled March 16-20. It said decisions about future meetings will be “communicated as they are made.”
“The plan is to continue the conference-call only policy for the foreseeable future,” MISO spokesperson Allison Bermudez told RTO Insider.
The RTO is conducting a reassessment of attendance at its Board Week in New Orleans March 24-26, asking all registered attendees to change their registration status by March 12 if they no longer plan on traveling to the meetings.
Bermudez said MISO leadership is still evaluating the board meetings in New Orleans and will communicate their decision with attendees.
MISO said its “top priorities are the health and well-being of our employees and stakeholders and the reliability of the bulk electric system.”
In a March 9 message to stakeholders, CEO John Bear said, “MISO’s Incident Management Team continues to track the situation closely and is consulting with experts on appropriate safety steps that help protect employees and ensure grid reliability.” The RTO has initiated more cleaning practices, and employees and contractors are similarly limiting large, in-person gatherings. He also said MISO is prepared to have employees work from remote locations.
“All areas within MISO have business continuity plans that enable work to continue from alternative locations if necessary. We will continue to monitor developments and implement additional protocols as necessary to minimize risk to the MISO community,” MISO said, adding that new developments will be posted on its Twitter page and misoenergy.org.
