Page 1147 – RTO Insider

July 25, 2018

NYSERDA Talks Offshore Wind Contract Terms

By Michael Kuser

At what point will an offshore wind bid in New York become firm and binding? And how will state agencies ensure a project delivers its promised benefits?

State officials discussed these and other issues with developers and stakeholders when they met in New York City Monday to explore contract terms for the planned fourth-quarter solicitation for 800 MW or more in offshore wind energy, the first part of a two-phase plan to develop 2,400 MW by 2030. (See NYPSC: Offshore Wind ‘Ready for Prime Time’.)

The New York State Energy Research and Development Authority (NYSERDA) held a July 23 technical conference to discuss the agency’s request for information (RFI) issued July 20, soon after the state’s Public Service Commission issued an order (Docket No. 18-E-0071) authorizing the solicitation.

“We know that we have a lot of work to do in a short period of time, which is why we wasted no time trying to pull together this conversation,” NYSERDA CEO Alicia Barton said.

The agency’s RFI covered the procurement schedule and quantity, interconnection and deliverability, offshore wind renewable energy certificate (OREC) pricing options, bid price evaluation, economic benefit, project viability, environmental issues and eligibility and contract provisions.

Binding Provisions

“We’re interested to know how much time you would need to develop your proposals … and secondly, we are looking for these bids to be firm and binding for a period of six months,” Doreen Harris, NYSERDA director for large-scale renewables, told prospective developers. “Is this duration reasonable?”

Anbaric Project Manager Howard Kosel said the term “firm” seemed to clearly apply to pricing but asked if “binding” referred “to all internal approvals, court approvals, all necessary such that, if awarded, would be bound to contractually execute?”

NYSERDA Deputy Counsel Peter Keane clarified the agency’s approach would be similar to that for the renewable portfolio standard (RPS).

“We consider the submission of a proposal as an offer,” Keane said, noting that a developer would include its terms in its proposed contract and that NYSERDA can form a contract by accepting. “We do, however, require that within a reasonable amount of time, about 30 days, they provide a corporate confirmation that the authority has been given to the execution parties, etc.”

NYSERDA must issue its offshore wind solicitation in consultation with the New York Power Authority (NYPA) and the Long Island Power Authority (LIPA). The agency will announce the award in the second quarter of 2019 and, if needed, issue a second solicitation next year to meet the 800-MW goal.

“Will the capacity that NYPA and/or LIPA be purchasing, if they decide to go forward, be a subset of the 800 MW or would it be additive to, and if so, would that be known as part of the RFP?” asked Clint Plummer, Deepwater Wind vice president of development.

Keane said the PSC would have to weigh in on that issue, but his “feeling” was the NYPA and LIPA capacity would be additional.

“Either of the other two power authorities could go out on their own; theoretically, there’s an option that they could join with us and just make a long-term financial commitment for whatever capacity we procure,” Keane said. “In either case, I don’t see those as being automatically subtracted from our Phase 1 goal.”

Harris agreed with Keane and read from the authorizing order: “The quantity of ORECs that is procured by NYSERDA, NYPA and/or LIPA toward the Phase 1 goal need not be limited to the proportional share of retail load to be served but instead could be based on quantities being efficient for each particular solicitation or award.”

Enforcement Mechanisms

NYSERDA plans to announce the award in the second quarter of 2019 and, if needed, issue a second solicitation next year to meet the 800-MW goal. The agency expects the Department of Interior’s Bureau of Ocean Energy Management (BOEM) to identify new lease areas for New York early in 2019.

New York Offshore Wind Study Area | *NYSERDA*

Harris did not attribute questions from those participating in the conference via the web. One asked how NYSERDA would determine or quantify a shortfall in claims — either estimated benefits or expenditures — made at the time of the bid.

“In the land-based renewables context, we do have a very similar category, albeit it was for a slightly different purpose,” Harris said. “However, on the land-based side, we do audit the spending of the awarded developers to verify, through a third-party audit, the spending records that they are claiming to have executed in their project development.”

There will be contractual ramifications for a shortfall, she said.

“What kind of enforcement mechanism should we have?” Keane asked. “We need to have something, for you win eligibility points for the economic benefits that you pledged.”

Wind developers must submit their bids in terms of both fixed-price ORECs and variable — or index — ORECs, and NYSERDA has the authority to specify under what conditions an index OREC contract may revert to a fixed price.

“I don’t think NYSERDA expects to have discretion to just order that trigger on its own for whatever reason. My thought is it would be some sort of event,” Keane said.

Compliance Payments

One web participant expressed concerns about the OREC compliance obligation for load-serving entities in cases of project delays or cancellations: “If there is not an alternative compliance payment, what will happen if projects are not constructed and there are not enough ORECs available for an energy service company [ESCO] to purchase the requirement?”

Harris explained that ORECs will follow a scheme similar to that for zero-emission credit obligations, with LSEs and ESCOs only responsible for purchasing a prorated share of whatever volume of ZECs NYSERDA acquires from eligible nuclear generators.

“If there was a circumstance where a project was delayed, and it came online in July instead of May, and there were fewer ORECs to be had in a given year, it wouldn’t impact the ESCO or LSE in any way other than to just reduce the pro rata share of the ORECS that it would be obligated to purchase,” Harris said.

Transmission and More

Another meeting participant asked how the grid will accommodate large injections of power if 800 MW or more is awarded in Phase 1.

“This is expected to be a primary consideration for the transmission working group … to be formed prior to Sept. 28 this year,” said Matt Vestal, NYSERDA technical advisor.

Kosel pointed to NYISO’s “fairly rigorous” and time-consuming interconnection process, in which costs are not determined until well into the process. With 70% of the RFI’s evaluation criteria based on price, he asked how developers can be expected to plan without knowing costs for system deliverability upgrades.

Vestal said developers have been thinking about those issues for a long time and probably have significant understanding of where their interconnection costs lie.

“We’re seeking to understand and want to be able to assess the reasonableness of those interconnection costs as we evaluate those prices,” Vestal said. “We include that question specifically in the RFI, but NYSERDA, as well as the commission, certainly understands that these prices can be incrementally uncertain relative to the other costs required for offshore wind on the generation side.”

Nora Madonick of Arch Street Communications pointed out the RFI did not address “anything specific to minority, women-owned or service-disabled veteran-owned businesses, and I’m wondering if a percentage has been discussed or if you would like input on that in the RFI, and, if so, in what category.”

NYSERDA now has no plan for a set percentage, but stakeholders can address that topic under any part of the RFI they like, Keane said.

Stakeholders can submit comments on the RFI until 5 p.m., Aug. 10, to offshorewind@nyserda.ny.gov. NYSERDA will post all comments on its website.

July 24, 2018

DOE Rejects NARUC Invites on Coal, Nuke Bailout

By Rich Heidorn Jr.

SCOTTSDALE, Ariz. — State regulators were forced to scramble the programming at their summer meeting last week when Department of Energy officials belatedly rejected invitations to talk about the Trump administration’s proposed coal and nuclear bailouts.

The National Association of Regulatory Utility Commissioners invited officials from DOE’s Office of Fossil Energy and Office of Nuclear Energy to speak on a panel July 17 on Trump’s directive to subsidize at-risk nuclear and coal generators (“When the President Says You Can’t Retire: The Impacts of Section 202c on the Electricity Industry”) but neither office was represented.

doe naruc coal nuclear — DOE Assistant Secretary Bruce Walker addressed NARUC’s General Session Monday via a cellphone video. | © *RTO Insider*

In addition, Assistant Energy Secretary Bruce J. Walker, who was scheduled to speak at the Summer Policy Summit’s General Session on July 16, instead appeared at the Fairmont Scottsdale Princess hotel ballroom on a screen via a recorded cellphone video.

Walker, appointed by President Trump last year as head of the Office of Electricity, said he was unable to attend because of “weather problems in New York.” DOE said Walker was scheduled to fly from New York to Phoenix via Denver but missed his connecting flight because of delays at LaGuardia Airport and was unable to reschedule to arrive at the conference in time.

The Maryland Public Service Commission told RTO Insider that DOE’s nuclear energy representative canceled the day before the panel discussion.

“We received an email on Monday, July 16 from DOE’s Office of Nuclear Energy that they would be unable to send a representative to speak at the joint subcommittee panel on July 17 due to scheduling conflicts,” Amanda Best, an aide to Maryland Commissioner Anthony O’Donnell, who was to moderate the session, said in an email. “A representative from the DOE Office of Fossil Energy was also unable to attend.”

DOE’s absence led some NARUC attendees to speculate that the department wanted to avoid questioning by regulators and reporters about its plans for implementing Trump’s directive.

DOE spokeswoman Shaylyn Hynes didn’t deny it.

“There is an interagency policy review process underway regarding grid resilience and examining multiple policy options,” she said in a statement. “It would have been premature for DOE representatives to discuss the specifics of that process while it remains ongoing.”

Walker angered members of the House Committee on Science, Space, and Technology’s Subcommittee on Energy last month when he testified that his agency had no estimates on the cost of the bailouts, which Trump had ordered a week earlier. Walker responded to Democratic members’ questions tersely and without elaboration. (See Dems Hit Coal, Nuke Bailout at House Hearing.)

doe naruc nuclear coal — The House Committee on Science, Space, and Technology’s Subcommittee on Energy hears DOE Assistant Secretary Bruce Walker testify in June. | © *RTO Insider*

Walker’s name has been among those floated as a potential replacement for FERC Commissioner Robert Powelson, an outspoken opponent of the bailouts, who is resigning in mid-August to become CEO of the National Association of Water Companies. (See related story, FERC Says Farewell to Powelson.)

At the conference, however, NARUC members passed a resolution asking that Trump appoint a replacement with state regulatory experience. “No one understands better than state commissioners the real-world, often unintended, effects of federal policy at the ground level on consumers, and how such policies complement, interfere or interact with related state programs or local/regional market conditions/demographics,” the regulators said.

Powelson, former chairman of the Pennsylvania Public Utility Commission, is the only former state regulator on FERC.

Quicker Recovery for Cyber Investments

Walker spoke for less than four minutes on the video, reading from notes while sitting in what looked like an airport corridor.

“What I wanted to speak about directly was the need for all of us within the regulatory framework to acknowledge the changes that are necessary in the general rate case filings so that they better adapt to and address the problems we see today,” he said. “Specifically, in the cybersecurity world, the investments that are being made today become obsolete within six months. Our regulatory models today don’t necessarily recognize that, and one of the things we collectively need to do is — using a risk-based approach process — properly align the rate case mechanisms and the recovery aspects for the utilities that we work with so that they can properly recover their investments.”

NARUC passed a resolution at the summer meeting encouraging regulators to “explore and examine alternative rate recovery mechanisms to accelerate the modernization, replacement and enhancement of the nation’s electric system.”

Carl Pechman, director of the National Regulatory Research Institute, NARUC’s research arm, said Walker’s “concerns about the rate treatment of cyber activities is real.”

“In light of these issues, the NRRI is planning to undertake a survey and deep dive on the ratemaking of assets that have short and difficult-to-predict asset lives,” Pechman said in an email. “We look forward to working with our nation’s public utility commissions and the U.S. DOE to help assure that cost recovery and rate mechanisms support national priorities of cybersecurity.”

“Regulators should and mostly do have discretion with regard to the treatment of capital and operating costs, including consideration of risk and obsolescence, and the alignment of cost recovery to useful life,” Janice Beecher, director of Michigan State University’s Institute of Public Utilities, said in an email. “Potential obsolescence within one year raises several issues. The regulatory policy community would benefit from research and information-sharing in this area, given its criticality.”

States’ Role in National Security

Walker said that although national security is generally considered a federal function, states have an important role because they regulate the utilities that power the 16 critical infrastructure sectors.

“We will continue to work through our Electric Sector Coordinating Council and the Oil and Natural Gas [Subsector] Coordinating Council to work with the asset owners to develop short-term executable strategies for cyber, physical and [electromagnetic pulses],” he said.

“The investments we are looking to drive are designed to reduce risk. Thus, as you become aware of investor requests designed to address these three specific areas, I would implore you all to take the threat very seriously and find a way to support the investment.”

July 24, 2018

SPP Stakeholders to Study Admin Fee Changes

By Tom Kleckner

OMAHA, Neb. — SPP’s Markets and Operations Policy Committee last week agreed to create a task force to evaluate a proposal that would change the recovery mechanism for the RTO’s administrative fee.

Saying the RTO’s Finance Committee “is at a point where maybe we change the recovery methods,” SPP CFO Tom Dunn pitched the committee’s recommendation to change the fee’s billing units from transmission metrics to energy metrics by charging market transactions.

The administrative fee, currently 42.9 cents/MWh, is collected under Schedule 1A of SPP’s Tariff on transmission contracts between transmission providers and customers. Point-to-point contracts are billed against reserved transmission capacity, and network service is billed against the prior year’s average monthly zonal peak.

Speaking at last week’s MOPC meeting, Dunn said regulators have issues with how some companies recover their costs, pointing to the use of historical data for current year costs and inconsistent calculations. The Integrated Marketplace has also resulted in a staff increase and additional IT costs, which have increased the costs to be collected.

spp administrative fee — SPP CFO Tom Dunn explains potential changes to the administrative fee’s recovery. | © *RTO Insider*

“Is there a way we can eliminate or mitigate issues utility customers are having with regulators?” Dunn asked.

He said using energy metrics could potentially reduce the administrative fee to 15 cents/MWh, because financial-only players who are currently not paying Schedule 1A fees would also be contributing. But Dunn also cautioned against adding the “new universe” of market participants.

“From an SPP Inc. standpoint, that’s not necessarily ideal,” Dunn said. “Our customer base is monopolistic entities carrying investment grade ratings. When you change that mix, you slightly change the credit outlook of SPP — slightly.”

The new scheme would also result in independent power producers paying more.

“The value that members and market participants realize in the marketplace comes through in terms of the energy cost customers pay,” said Board Chair Larry Altenbaumer, who also sits on the Finance Committee. “The largest cost component is the 1A fee, which is easy for regulators to lay their eyes on. Our recommendation basically does an automatic netting and captures the energy cost the consumer pays. Some regulatory agencies, we think, would allow this to pass through. Others we’re not clear on.”

Dunn said he had talked with MOPC leadership about setting up a task force, noting that full market participation would “result in a solution that’s tenable for everybody.” The group would return to the committee in January with a recommendation for approval, with the new fee going into effect in 2020.

SPP legal counsel visited with FERC in March and “talked through the concept,” Dunn said.

“FERC’s big concern is consistency across the markets,” he told members. “All of the organized markets have an unbundled rate structure. We don’t want to be put in a position where we’re showing the commission was wrong to put unbundled rates in regulated markets. It’s an issue we would have to address.”

Some stakeholders expressed concerns about forecasting energy usage, which is largely impacted by weather.

“I’m not sure how that brings stability to the administrative fee and cost recovery,” said Midwest Energy’s Bill Dowling.

Dunn responded that energy metrics would improve load forecasts, as market participants would be using 365 data points for each entity, as opposed to 12 data points from the previous year. He added that the methodology change would allow midyear adjustments to true up the remainder of the year should there be under- or over-recovery.

“The simpler we can do it, the better it is for everyone. We don’t want to focus on precision so that we gin up another Z2,” Dunn said, referring to SPP’s troubled method for assigning financial credits and obligations for sponsored transmission upgrades.

“What’s beneficial is keeping rate decisions simpler. We want something that doesn’t drive administrative costs and is easier to administer,” he said.

MOPC Chair Paul Malone, of Nebraska Public Power District, recommended the task force meet monthly.

“Continuing to lay everything on transmission doesn’t make sense to me on the surface,” he said.

July 24, 2018October 31, 2023

Massachusetts Seeks Input on Energy Plans

By Michael Kuser

WESTFIELD, Mass. — Massachusetts officials last week held three hearings across the state to get public input ahead of a September release of the statutorily mandated Comprehensive Energy Plan (CEP).

The state’s Department of Energy Resources is preparing the plan to project the state’s 2030 energy demands for electricity, transportation and thermal conditioning and help it meet its greenhouse gas emissions targets. The state’s Global Warming Solutions Act (GWSA) requires a 25% reduction in emissions by 2020 from the 1990 baseline and an 80% reduction by 2050.

The state accounts for 45% of electricity demand in New England.

Morin | © RTO Insider

“This report is really looking at supply and demand of energy going forward,” DOER Deputy Commissioner Joanne Morin said on July 19. “The CEP is going to demonstrate the modeling, the impact and required balance in pursuing these goals simultaneously, and looking at different pathways that we could take with our energy future.”

State lawmakers are now considering legislation to increase the state’s renewable energy and reduce high-cost peak demand. Earlier this year, two senators touted a goal to achieve 100% renewable electricity by 2035 and to make the heating and transportation sectors 100% powered by renewables by 2050.

Hopkins | © RTO Insider

Asa Hopkins of Synapse Energy Economics, the DOER’s consultant on the energy plan, sought feedback on its assumptions and analysis of 2030 scenarios.

“Have we got it right or have we got it wrong? Should we be designing these policy features in some different way?” Hopkins asked.

The public has until July 31 to submit comments at the CEP website.

“That’s not much time for public comment,” said Rosemary Wessel, director of “No Fracked Gas in Mass,” a program of the Berkshire Environmental Action Team.

Wessel also complained about what she called a lack of transparency in clean energy data, saying the DOER shows state emissions data only up to 2014. She also said the DOER website “has become much harder to use.”

Several audience members murmured their agreement to the website assessment, and Morin said, “I’ll have to follow up on that.”

Soft or Hard Push?

Hopkins’ study included a status quo scenario and also analyzed the impact of adjusting “key levers,” including efficiency, renewables and electrification via electric vehicles and heat pumps.

Under the status quo or “sustained policies” scenario, renewables would supply 45.5 TWh in 2030, or about 35% of electricity in the region, with Massachusetts hitting its 25% renewable portfolio standard target. Under a “high renewables” scenario, the amount increases to 38% (49 TWh), with all of the increment serving Massachusetts, which would get about half its electricity from Class I renewables in 2030, Hopkins said.

Massachusetts CEP Comprehensive Energy Plan Electrification

2030 electric consumption is projected at 11% above 2018 under aggressive policies leading to high electrification in New England. | Synapse

“We’re looking at electrification, which in the case of electric vehicles, is associated with a substantial increase in efficiency, as it is with heat pumps, so there’s a common thread there,” Hopkins said. “There are distinctly more heat pumps in Massachusetts than there are EVs, but more people consciously see EVs than see heat pumps.”

Because they’re moving heat rather than generating it, heat pumps have efficiencies well over 100%.

“A typical seasonal average in Massachusetts would probably be well over 200%, and for a heat pump water heater it will go up well over 300%,” Hopkins said. A 300% efficient heat pump produces three units of heat for every unit of energy, Hopkins explained.

The “high electrification and high renewables” scenario includes a “clean peak” idea to incentivize generation or energy dispatch to be available to meet winter and summer peaks without emissions.

The scenario for increased efficiency, electrification and renewables would reduce the average commercial building’s heat energy by 25% or more with the state getting 50% of its electricity from renewables, Hopkins said.

Enhancing both electrification and renewables would push wind and solar growth to 33.7 TWh in 2030, while natural gas use would be 29% lower than today.

System demand graph shows results under aggressive policies leading to high electrification in New England. Regional demand increases 13% by 2030 but most of the increase is powered by renewables (+165%). Gas generation drops (-25%). | Synapse

“Once those clean peak resources are there, it’s not like they’re only there on the peak day; they also run all the rest of the time around the year and are impacting what’s going on with dispatch of different resources,” Hopkins said.

Massachusetts has a goal of 300,000 EVs on the road by 2025 and 1.7 million in 2030. Hopkins said the state can probably only reach 160,000 EVs by 2025 under current policies but could exceed its EV goals by enhancing all policy levers.

Several people asked about energy storage and whether EVs can act as batteries for the grid.

“The place where storage makes a difference is on an hourly basis,” Hopkins said. “One learning from this is that what you assume about the load shape of when all those 1.2 million or 1.7 million EVs are charging, it really matters a lot. And what you assume then about when those batteries will charge and discharge really matters a lot.”

If peaks are in the afternoon and you have everyone charge their cars overnight, “you create a giant super-peak at 3 in the morning,” Hopkins said. “That’s probably not the actual path forward, but things we learn there can flow into policy development.”

Solar Woes

Robert Camus, a Granby selectman and member of the town’s energy committee, said that if the state wants to increase solar energy by 50% by 2030, it should change policies to promote local ownership of solar farms.

“The SMART [Solar Massachusetts Renewable Target] program awards Eversource [Energy] and National Grid so much each year, but there’s no differentiating between a private landowner and a municipality,” Camus said. “If the municipality was to have the solar field, versus a private landowner, you’d have a lot more advantages.”

Attendees of one of three public hearings last week on Massachusett’s Comprehensive Energy Plan. | © RTO Insider

If a private landowner makes a deal with a solar developer, the money goes to one individual, he said.

“If you go to the municipality, every taxpayer in that town gets a share of the money, which would decrease the demand of the municipalities on the administration every year for money for schools, infrastructure and everything else,” Camus said. “If the money goes to the taxpayer[s] of Massachusetts rather than to out-of-state developers, we can more enhance our own economic growth, because the money stays.”

He suggested that the SMART program devote 75% of its money to municipalities, leaving 25% for individual landowners.

Morin directed Camus to contact Michael Judge, director of DOER’s renewable energy division. The CEP is intended to complement another effort, the Clean Energy and Climate Plan (CECP), which talks about emissions targets and how the state is going to meet them, Morin said.

July 24, 2018November 13, 2023

SPP Markets and Operations Policy Committee: July 17-18, 2018

OMAHA, Neb. — Given a proverbial second bite of the apple, SPP stakeholders easily approved a revision request that requires non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs) within a multiyear transition period.

The Markets and Operations Policy Committee rejected the measure (RR272) during its April meeting. The Board of Directors/Members Committee tabled the request but asked for a review of RR272’s economic impact and that the Market Working Group build greater consensus among the membership. (See “Board Forced to Table NDVER Conversion Change,” SPP Board of Directors/Members Committee Briefs: April 24, 2018.)

MWG Chair Richard Ross, of American Electric Power, began discussion of the change by noting he was one of the few people in the meeting room wearing a tie.

“I’m not trying to make anyone nervous,” he quipped. “But if you get unruly, I’ll take the tie off.”

There was no need. The measure passed with more than 81% approval, almost 20 points better than it fared in April. It was opposed by only two transmission owners (Empire District Electric and Omaha Public Power District) and eight transmission customers with various ties to renewable energy. Seven transmission customers abstained.

“We wanted to see this happen, sooner than now,” said Southwestern Public Service’s Bill Grant. “This is a compromise we can live with. It took a lot of work to get to this point, but we’ve moved to a point where most people are happy.”

Staff shared its analysis of RR272’s economic effects, which compared the conversion of NDVERs to DVERs against a base case using real-time security-constrained economic dispatch data. They found the conversion resulted in improved congestion management and, with it, better convergence of real-time and day-ahead prices. That resulted in about $15,000 in additional monthly real-time energy payments to converted NDVERs and about $20,000 in additional revenue to other resources.

The data also indicated a significant reduction in the number of operating hours with negative pricing.

The MWG revised the proposal to exempt run-of-river hydro not capable of following dispatch instructions and to provide additional time for certain NDVERS to convert. They now face a deadline of either Jan. 1, 2021, or the 10-year anniversary of a resource’s original commercial operation date.

Market Monitoring Unit Executive Director Keith Collins said he supports the proposal, saying the benefits come from “an increase in prices at locations that are primarily non-dispatchable.”

“We’re investing upgrades for controls we don’t own, which increases the [power purchase agreements] for our customers. That’s not something we’re keen on,” said Empire’s Aaron Doll. “Our specific limitation is contractual language that limits curtailments to a certain amount in a 24-hour period. The dispatch signal puts us in bad spot pretty quickly. Anything short of providing an exemption for entities with contract language that precludes curtailment is not something we can support.”

The MOPC also approved RR266, which would model a joint-owned unit (JOU) as a single resource in market-clearing decisions, while performing an after-the-fact allocation of revenues based on ownership shares. Other JOU shares would be used for settlement purposes, and each share would exist only in the context of settlements where final clearing results are split based on the submitted ownership share percentages.

The change is contingent upon final approval by the Regional Tariff and Operating Reliably working groups. Nebraska Public Power District and Oklahoma Gas & Electric’s Transmission and Electric Services divisions opposed the measure, citing problems with the language.

“We have a couple of JOU situations we manage fine ourselves,” said OG&E-Transmission’s Greg McAuley. “We’ll continue to pound the table as it relates to some of these administrative costs.”

Stakeholders approved against minimal opposition three other revision requests brought forward by the MWG:

- RR306, which would minimize potential gaming opportunities identified by the MMU. The change allows market-committed resources that have a minimum run time extending beyond initial reliability unit commitment or day-ahead commitment periods to be eligible for make-whole payments after their initial commitment period.
- RR304, which streamlines the process by which frequently constrained areas are re-evaluated, in order to make adjustments in a timely manner.
- RR312, which would calculate the FERC Schedule 12 rate based on current data. The change aligns the collections of revenue against the customers’ megawatt-hours being assessed.

SPP Prepared for January’s ‘Big Chill’

Staff’s update on what they call “The Big Chill,” the abnormally frigid temperatures Jan. 17-18 that led to heavy north-south transfers of MISO flow across SPP’s system and a maximum generation alert in MISO South, caused one member to recall his scouting days.

“I wouldn’t call this an emergency event,” said MOPC Chair Paul Malone, of NPPD. “It was pretty well known we would have severe weather over a wide area. That begs for proper planning. As the Boy Scout motto says, ‘Be prepared!’”

“Let’s just say, some people are surprised every day by what happens,” said SPP COO Carl Monroe, “and some people were surprised that day.”

MISO exceeded its 3,000-MW regional dispatch limit on transfers between its North and South regions over the SPP system during the event and was forced to make emergency purchases from Southern Co.

SPP Vice President of Operations Bruce Rew said the RTO never had to issue an emergency alert, as it was never short of generation. “It was uncomfortable for us,” he said. “We have to make sure it doesn’t happen again.”

David Kelley, SPP’s director of seams and market design, credited SPP’s and MISO’s neighboring reliability coordinators with helping to prevent load shed and keeping the lights on during the event. He said recent discussions among the Regional Transfers Operating Committee (RTOC), a six-person group comprising two representatives each from SPP, MISO and joint parties to a 2016 settlement agreement, centered on better understanding the non-firm, available nature of MISO’s north-south flows and their effects on neighboring entities. (See SPP, MISO Reach Deal to End Transmission Dispute.)

“Anything over 1,000 GW is on a non-firm, as-available basis. To us, that means SPP’s service should not be in jeopardy of load shed,” Kelley said. “When this event happens again, and will happen again, we’ll be prepared.”

Kelley said staff has also met with FERC staff to “ensure FERC had a clear understanding of what happened that day,” given “very inaccurate statements that found their way into the media.” (See SPP Seeks FERC Meet in MISO Tx Dispute.)

Kelley also briefed the MOPC on a proposed interregional project with Missouri-based Associated Electric Cooperative Inc., a new 345/161-kV transformer at AECI’s Morgan Substation near Springfield and the rebuild of a 161-kV line.

The project’s regional cost allocation was rejected by FERC last year. (SPP would be responsible for 89% of the $13.75 million in engineering and construction costs). SPP staff have since developed data that indicate the project would yield the region $17 million in load ratio share benefits by eliminating the need for upgrades at City Utilities of Springfield’s John Twitty Energy Center and also reduce day-ahead market uplift costs.

“We feel like we’re in much better shape,” said Kelley, who met with FERC staff on July 12. “They look forward to seeing our next filing.”

Kelley said that filing should be made in late July or early August.

Stakeholders Endorse $47.4 Million in Near-term Tx Work

The MOPC endorsed the Transmission Working Group’s recommendation to approve the Integrated Transmission Planning process’s 2018 near-term assessment portfolio, a package of 13 transmission projects with an estimated cost of $47.4 million

However, when taking into account four withdrawn projects from previous assessments that cost a total of $53 million, the portfolio has a net cost of -$5.6 million.

Several of the Kansas and Missouri projects are being driven by the retirement of about 1.9 GW of 50- to 60-year-old generation later this year and in early 2019.

The projects will solve 101 reliability needs. They include a new 345-kV, 50-MVAR reactor at City Utilities’ Brookline substation, a project originally identified as an interregional project with AECI.

OG&E’s Travis Hyde, who chairs the TWG, noted SPP approved nearly $8 billion in construction between 2006 and 2014. With the strategic shift to maintaining “an economical, optimized transmission system,” he said, the RTO has since approved just more than $1 billion in base plan funded investment.

Staff developed a summary presentation of the assessment using a story map tool.

Stakeholders also endorsed NorthWestern Energy’s sponsored upgrade of less than 4 miles of new 115-kV line in Aberdeen, S.D., and a working group recommendation to approve the 2019 ITP’s needs sensitivity scope addressing study results affected by Lubbock Power & Light’s potential exit from the system.

RC Efforts in West Absorb MWTG Integration

Monroe told members that the integration of the Mountain West Transmission Group has been “subsumed” in the debate out West over who will provide reliability coordinator (RC) services — a debate that involves SPP.

The RTO said in June that it plans to offer RC services in the Western Interconnection, matching an earlier announcement by CAISO. Not coincidentally, Peak Reliability said last week it will wind down its RC role by the end of 2019. (See related story, Peak Reliability to Wind Down Operations.)

SPP’s Carl Monroe (c), NPPD’s Paul Malone, NE Texas Electric Co-op’s Jason Atwood, GDS Associates’ Jack Madden anchor the MOPC’s head table. | © RTO Insider

“There’s still interest in [joining SPP],” Monroe said. “The importance of making sure RC is provided, and in an efficient and reliable way, has subsumed their work right now.”

SPP’s efforts to integrate Mountain West were dealt a blow in April when Xcel Energy announced it was withdrawing from the Rocky Mountains group and its efforts to join the RTO. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

Monroe said there have been no changes to the Mountain West’s initial proposal to join SPP, adding he hopes to be able to provide “what kind of a footprint we would have with RC services” by Sept 1.

“As we work through the process, our intent is to meet the goals of what we normally do through contract service, which is providing benefits back to the members themselves,” he said.

MRO’s Patrick Welcomes New Entities

Midwest Reliability Organization CEO Sara Patrick introduced herself to SPP members, many of whom were among the 100 registered entities that joined the organization after the SPP Regional Entity’s recent dissolution. (See SPP RE Ending Compliance Monitoring, Enforcement Activities.)

Patrick said all compliance monitoring and enforcement program (CMEP) data was successfully transferred from the SPP RE to MRO on July 3, and that all entities in its expanded footprint are now using MRO’s webCDMS portal.

Patrick gave credit to the SPP RE’s staff in a “well-coordinated” transition and data transfer. The $1.5 million in transition costs will be recovered by transferring assessments from the SPP RE to MRO, she said.

The MRO’s board of directors last month approved a $4.3 million increase, reflecting the expanded footprint. Patrick said the budget will result in $4.8 million in savings, when compared to the combined MRO and SPP RE budgets.

The board also agreed to add four new directors next year, including two regional directors from the SPP RE’s footprint.

MOPC Sends Two Initiatives Back

The MOPC declined to take action on a pair of work efforts, asking that both be returned to the stakeholder process for further clarification.

Following an update on SPP’s prioritization process for revision requests and project proposals, stakeholders debated potential improvements to the process before the committee’s leadership said it would return to the next meeting in October with ideas on how to proceed.

Stakeholders complained about a lack of transparency, the amount of information they had to deal with and not knowing where decision-making authority lies. Staff said it stopped the quarterly meetings because of a lack of feedback.

Several members familiar with ERCOT’s stakeholder process suggested the Texas grid operator’s Protocol Revisions Subcommittee (PRS) as a good model to follow. Tenaska’s John Varnell, who once chaired the PRS, said if members listened in on the group’s meetings, “You will see how we can do better at this process.”

“That’s one thing that ERCOT does quite well,” said Golden Spread Electric Cooperative’s Mike Wise, who sits on ERCOT’s MOPC equivalent, the Technical Advisory Committee.

“[The PRS] does a really good job of ensuring financial stability or accountability. [Members] debate [revision requests] quite substantially before they ever enter in the queue for approval at the TAC. Many of us want this to be like what we have at ERCOT. It puts more decision-making in the hands of the stakeholders, rather than SPP.”

Grant, who headed the task force that developed the prioritization process, called for more stakeholder involvement in the process. He reminded the committee that the task force hasn’t been disbanded.

“If we’re going to spend the time and effort to improve the process, we need better participation and more dedication to the issue,” he said. “It doesn’t matter what we set up if the stakeholders aren’t going to participate in the process.”

The MOPC also sent back a Credit Practices Working Group (CPWG) revision request, saying it needed more information and noting the Finance Committee had tabled the request. The CPWG reports to the committee.

The CPWG’s RR311 would change the way reference prices are used to estimate the settlement exposure of transmission congestion rights (TCRs). The group’s analysis of a two-year period indicated its proposed methodology would have reduced collateralization in the TCR market by $124 million to $327 million, and more than doubled under-collateralization from $17 million to $39 million.

Staff recommended tabling the change, saying it needed more analysis in light of a market participant’s recent default in PJM’s financial transmission rights market. (See “Credit and Default,” PJM MRC/MC Briefs: June 21, 2018.)

“It sounds like the hesitancy to move forward is lack of understanding of what’s happening in the PJM situation,” said Kansas City Power & Light’s Denise Buffington.

Given that the CPWG has yet to gain approval from the Finance Committee and the Regional Tariff Working Group, stakeholders agreed to send CPWG RR311 back to the working group so that it can be properly shepherded through the stakeholder process.

Members Endorse RRs, Process Language Change

Members endorsed language changes to improve efficiency of the revision request process by reducing the time it takes to gain approval for a change and removing duplicate references that cause unnecessary changes.

The proposal (RR291) would allow a revision with approved “normal status” to progress through the stakeholder process while its primary working group waits on the impact analysis. It would also revise language to reference the applicable documents as SPP revision request documents and remove their multiple references.

The MOPC’s consent agenda, which passed unanimously, included nine revision requests and a new baseline cost estimate for SPS’ 115-kV loop rebuild in West Texas. The project’s original cost of $28.4 million was reduced almost 23% to $21.9 million.

- BPWG RR307: Clarifies that partial service may be offered to short-term transmission service requests when the full amount requested cannot be granted.
- CTPTF RR279: Modifies the competitive project proposal process to allow a re-evaluation request before awarding a notice to construct.
- MWG RR177: Clarifies references to NERC standards in the Integrated Marketplace’s protocols and the Tariff’s Attachment AE, the marketplace’s governance, to eliminate confusion over whether entities are performing obligations for market or NERC standard reasons. Also modifies the attachment’s definition of operating reserve to that defined in the Tariff.
- MWG RR277: Corrects language in Attachment AE to accurately reflect the settlement formula for the auction revenue rights daily amount by reversing the sequence of the source and sink.
- MWG RR310: Adds three reporting requirements to comply with FERC Order 844: zonal make-whole payment reports, resource-specific make-whole payment reports and operator-initiated commitment reports. Also requires public posting of transmission constraint penalty factors; circumstances if violation relaxation limits (VRLs) could set prices; and procedures for temporarily changing VRLs in the Tariff.
- ORWG RR309: Removes section 7.3.1 (FAC-011-3 System Operating Limits Methodology) from SPP’s planning criteria and places it in a separate document for reliability coordination purposes.
- RTWG RR278: Corrects Attachment O’s Addendum 1 to include only current and applicable interregional coordination agreements and an update link to the joint operating agreement with MISO.
- RTWG RR315: Removes references to the SPP RE in the governing documents.
- RTWG RR314: Adds clarifying language to the ITP manual addressing ambiguity in the base reliability and short-circuit model builds.

— Tom Kleckner

July 24, 2018

Little Work Needed to Comply with Order 845, MISO Says

By Amanda Durish Cook

CARMEL, Ind. — MISO staff say the RTO is mostly up to speed with a recent FERC order aimed at increasing the transparency of the generator interconnection processes — but they continue to tackle issues related an overbooked queue.

Compliance with Order 845 largely involves inserting FERC-directed language and existing Business Practices Manual text into the Tariff, MISO said last week.

MISO FERC Order 835 interconnection — Supino | © *RTO Insider*

“Most of the compliance directives we already comply with in some shape or form,” counsel Chris Supino told stakeholders at a July 17 Interconnection Process Task Force meeting. He said MISO is “early” in its compliance plan and plans to share draft Tariff language in September.

“Most of these are fairly administrative; some we’ll have some more discussion around,” Supino said.

FERC issued the order in April, setting out 10 new rules intended to increase the transparency and timeliness of RTO generator interconnection processes. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.) MISO in mid-May joined an ISO/RTO Council request to extend the original Aug. 7 filing deadline, which FERC pushed out to Nov. 5.

Supino said most of MISO’s remaining work will focus on a new requirement to post quarterly summary statistics on its queue, including the number of withdrawn projects, completed projects and delayed projects; the proportion of studies completed by Tariff deadlines; and average study completion time.

MISO is now also obligated to file informational reports for four consecutive quarters if it misses deadlines on 25% or more queue studies during two consecutive quarters. The reports must explain reasons for the delays, steps taken to minimize them and the total number of employee and consultant hours spent on studies during the quarter.

Supino told stakeholders:

MISO generally complies with a directive to list specific study processes and assumptions because it already posts study models for review on its nonpublic Open Access Same-Time Information System. It will examine how the directive interacts with its existing nondisclosure agreements and whether it should issue more NDAs in order to share the models with a broader group.
The RTO will revise its generator interconnection agreement to give customers the option to build interconnection facilities and standalone network upgrades regardless of whether a transmission owner can meet a customer’s proposed in-service dates. It will also likely leverage its existing alternative dispute resolution language used for settlements to apply to members’ queue disputes.
MISO’s net zero interconnection option should cover a directive to allow customers to utilize or transfer surplus interconnection service at existing generating facilities. Net zero permits customers to transfer existing interconnection rights to a new generator at the existing point of interconnection, provided the total interconnection does not exceed the original service limit granted in the interconnection queue.
MISO will revise procedures to allow interconnection customers to request service lower than their generating facility capacity.
The Tariff will be updated to include a definition of permissible technological advancements to generators that it can accommodate without a change being considered a material change, something FERC has left up to the RTOs. Instead of listing every permutation of acceptable changes, MISO will instead develop a standard to study changes.

Further GIP Alterations

Meanwhile, MISO is once again tinkering with its proposal to make generation owners more accountable for site control earlier in the interconnection queue.

MISO is now proposing to require that interconnection customers have 90% site control at the time of application based on a per acre format, with 50 acres/MW for wind generation, 5 acres/MW for solar, 1 acre/MW for battery storage and a flat 50 acres for conventional generation. All generation types must provide a detailed site map showing turbine layout. All generators would be required to demonstrate 100% site control by the second decision point of the queue.

Apex Clean Energy’s Swaraj Jammalamadaka asked whether it is fair to require generation developers to hold that amount of land especially if MISO’s queue studies become delayed.

“It’s not a bad thing to have site control, but is this reasonable?” he asked.

WEC Energy Group’s Chris Plante also questioned whether the flat 50-acre requirement for conventional units was a reasonable standard. Neil Shah, MISO manager of resource interconnection, said the requirement was based on SPP standards, but staff are open to stakeholder suggestions.

MISO last month softened its original stance that developers should provide evidence of 100% site control before their projects can enter the queue and unveiled a plan to increase the deposit due upon entry from the current $100,000 to anywhere between $500,000 and $2 million in cash, depending on project size. (See “MISO Softens Site Control Requirements in Queue Streamline,” MISO Planning Advisory Committee Briefs: June 13, 2018.) Now, the cash deposit option will only apply to projects that demonstrate regulatory restrictions to procuring site control.

MISO also still plans to remove its dynamic stability, short-circuit and affected-system analyses from the first phase of the definitive planning phase. Staff said the revisions are needed because the overbooked queue currently contains almost 93 GW of prospective generation.

“It’s in a glut, or it’s clogged, and everyone, MISO included, needs to do something,” Shah said.

Revised Milestones

MISO also plans to revise the queue’s existing milestone payment and refund structure to include a percentage of upgrades identified in affected-system studies and introduce more monetary risk for customers who keep unprepared projects in the queue.

The RTO plans to keep its current format of a $4,000/MW initial payment upon entering the DPP with two subsequent milestone payments based on a percentage of upgrade costs. However, MISO now proposes to introduce upgrade costs found in affected-system studies that occur during the phase two system impact study. The third milestone payment will now consist of 10% of necessary network upgrades and another 10% of costs associated with needed upgrades uncovered in the affected-system study. The two combined percentages are a departure from MISO’s existing third milestone payment of a flat 20% of network upgrades.

Multiple stakeholders said MISO’s proposal will make milestone payments more burdensome and riskier to stakeholders by adding the affected studies element.

Jammalamadaka pointed out that MISO cannot control the outcome of affected system studies, which to date have shown inconsistent findings.

“That more money should be a percentage of something that’s predictable,” Jammalamadaka said.

Milestone refunds will also be slightly altered under the plan. MISO will offer to refund 50% (instead of the current 100% ) of the second and third milestone payments if a project opts to withdraw at the corresponding decision points. Projects that do not elect to withdraw at a decision point risk losing their entire milestone payment even if they fail to complete a GIA.

Shah said none of the refund changes will affect the penalty-free withdrawal options that MISO built into its queue overhaul last year. Penalty-free withdrawals are allowed in MISO if network upgrade costs increase too dramatically from one phase to another in the DPP.

“We want to make sure the new rules accomplish the goal of moving projects and incentivize the not-ready projects to get out as early as possible and potentially not even enter the queue,” Shah said. “We want ready projects to progress through the process. We want non-ready projects to drop out as soon as possible. This is our intent with this proposal, and we want to process the queue as quickly as possible.”

“We’re not changing too many things here,” said MISO Resource Utilization Director Vikram Godbole. “If you’re not willing to put money up for your project, maybe you don’t belong in the [definitive planning phase], I’m sorry to say. We’re designing a process for real and ready projects.” Godbole added it would be impossible to eradicate all speculative projects from the queue.

Shah said MISO hopes to file the new queue milestone details by the latter half of September.

Some stakeholders indicated that they might contest the filing with FERC.

MISO’s Patrick Brown reminded stakeholders that the RTO will collect two more rounds of feedback on the proposal, including a discussion before the Planning Advisory Committee.

“This is not set in stone. This is wet cement here. I think it’s a little premature to talk about contesting the filing,” he said.

Brown pointed out that MISO estimates it currently has a 20% completion rate of prospective projects that enter the queue. He said MISO is trying to “thin the herd to the most viable projects” and said he hopes the RTO can achieve a 50% completion rate of queue entrants in the future.

July 24, 2018

FERC Grants KCP&L Greater Missouri’s Dividends Petition

By Tom Kleckner

FERC last week found that KCP&L Greater Missouri Operations’ proposed payment of dividends complies with the Federal Power Act (EL18-146).

The commission found that Greater Missouri had clearly identified the source of its proposed dividends and that “nothing in the record indicates that the dividends will be excessive.” FERC found that the dividends would be “generally consistent with the amount and timing of the dividends” the utility has traditionally paid to its parent Great Plains Energy.

ferc kcpl federal power act — KCP&L’s Slate Creek Wind Project | *KCP&L*

The commission said that, “consistent with prior precedent,” the issuance of dividends would not harm GPE. It conditioned its approval on the utility’s compliance with its capitalization and credit rating commitments.

Greater Missouri filed the petition in May, saying it had deferred income tax assets and liabilities related to its regulated operations and significant deferred income tax assets for net operating losses (NOLs) generated prior to it’s acquisition by GPE in 2008. The utility said last year’s Tax Cuts and Jobs Act required it to revalue all of its deferred tax assets and liabilities in December based on the lower 21% corporate tax rate, and to revise its assumptions regarding the use of certain tax credits and NOLs.

The utility recognized a $111.6 million one-time, non-cash charge to income tax expense, approximately 1.6 times its average net income from 2014 through 2016 ($71.4 million). The charge caused Greater Missouri to have an accumulated deficit in its retained earnings account, which, according to FPA Section 305a, restricted the utility’s ability to pay dividends to GPE.

Section 305a forbids any public utility’s officer or director to receive “for his own benefit” any security issued or to share in any of the proceeds from any funds properly included in the capital account. The commission said a key concern was “corporate officials raiding corporate coffers for their personal financial benefit.”

FERC used a three-factor analysis to determine whether the proposed dividends payment violated the FPA. The commission considered whether: (1) the utility clearly identified the dividends’ sources; (2) the dividends would be excessive; and (3) the proposed dividends would have an adverse effect on the value of shareholders’ interests.

GPE recently acquired Kansas-based Westar Energy. (See Westar-Great Plains Merger Wins Final Approval.)

July 24, 2018

MISO Files Revised Upgrade Funding Provisions

By Amanda Durish Cook

CARMEL, Ind. — MISO has submitted a pre-emptive Section 205 filing to retain the option to allow new generators to self-fund interconnection transmission upgrades after the D.C. Circuit Court of Appeals vacated related FERC orders from 2015, stakeholders learned last week.

MISO facility construction transmission upgrades — Blackwell | © *RTO Insider*

“We asked for the commission to issue an order within the requisite 60 days,” MISO counsel Mike Blackwell said during a July 17 Interconnection Process Task Force meeting.

MISO policy previously allowed incoming generators to self-fund new construction regardless of whether transmission owners wanted to fund the construction themselves. FERC in 2015 directed the RTO to remove the option for a TO to elect to fund the interconnection upgrades.

The D.C. Circuit in January vacated FERC’s decisions on the self-funding option, saying the commission didn’t consider complaints from Ameren and five other TOs who claimed the policy forced them to accept “risk-bearing additions to their network with zero return” and essentially act as “nonprofit managers” of network “appendages.” The TOs had argued the Federal Power Act and Constitution prohibits FERC from forcing them to construct and operate generator-funded network upgrades. The case was remanded back to FERC. (See MISO Awaits FERC Following Remand on Tx Upgrade Funding.)

MISO made two separate filings July 5: one to reflect the vacatur (ER18-1964), and the other to propose a revised option that removes the requirement that an interconnection customer must consent before a TO can fund an interconnection upgrade (ER18-1965), a move intended to preserve the option for generators to self-fund upgrades. If FERC agrees, the change would apply to MISO’s generator interconnection agreement, Facility Construction Agreement and Multi Party Facility Construction Agreement.

Fallout Undetermined

Blackwell said a FERC decision on MISO’s filing could affect GIAs dating back to 2015. In both early July filings, the RTO committed to working “with parties to GIAs executed since June 24, 2015,” over the next three months to “establish a process for reviewing and revising those agreements to reflect the legal consequences.”

Wind on the Wires’ Rhonda Peters asked if the impacts of the decision could render some past GIAs uneconomic.

“MISO’s intent is merely to bring its Tariffs up to a state that’s as current as possible. We haven’t analyzed the financial impacts for specific interconnection projects,” Blackwell said of the proposed revision.

Peters also asked what would happen if the terms of an upgrade change after it is already funded. Blackwell said he would consult MISO staff on the consequences of such a scenario before attempting to answer the question.

In its filing, MISO warned FERC that not accepting its agreement amendments in a timely manner could have dire consequences: “MISO estimates that agreements already in process contain millions of dollars of affected systems upgrades. … These agreements (and the parties to them) would be subject to significant confusion and uncertainty if the commission does not act promptly to accept this filing, and delays associated with such confusion and renegotiations of agreements of this magnitude could implicate the timely construction of these upgrades.”

July 22, 2018

ERCOT Shatters Demand Records as Texas Bakes

By Tom Kleckner

Hell may be hotter, but it has nothing on Texas these days.

A high-pressure system that has swamped much of the state with triple-digit temperatures has triggered numerous heat advisories and led to all-time systemwide peak records in ERCOT.

ercot demand records — Sunday’s forecasted highs | *National Oceanic and Atmospheric Administration*

The grid operator broke its previous high for system demand on Thursday, when load topped out at 73.3 GW between 4 and 5 p.m. That was more than 2 GW over the previous record of 71.1 GW, set in August 2016.

All told, demand surpassed the old record nine times last week as temperatures reached 110 degrees Fahrenheit and heat indexes were as high as 115. On Sunday, ERCOT set a new weekend demand record of 71.4 GW between 5 and 6 p.m., breaking the old mark set last July by almost 3 GW after surpassing it three times on Saturday.

The ISO came up short of another record Monday, but cracked 73 GW for the second and third times during the intervals ending at 4 and 5 p.m. System load also exceeded the 2016 record during the intervals ending at 3 and 6 p.m.

Demand has exceeded 70 GW every day since July 16. The grid operator in spring projected a peak demand of 72.97 GW in August, assuming normal weather conditions.

Through it all, ERCOT has met demand without issuing conservation appeals. Staff in spring said it would have as much as 78.2 GW of capacity available, with a planning reserve margin of 11%. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)

“Everyone in the ERCOT market — from our operators to generators to transmission providers to retailers — is doing what they can to keep the power on for consumers,” said ERCOT spokesperson Theresa Gage.

Dallas/Fort Worth International Airport set a daily record for the third day in a row Saturday at 109, while Waco has broken its daily record five consecutive days, topping out at 109. Lubbock in West Texas saw a daily low of 81 on Thursday, the first daily low in the 80s in more than 100 years of record-keeping, according to The Weather Channel.

Houston and Dallas both opened cooling centers over the weekend for residents without access to air conditioning.

A jet stream is expected to shift the high-pressure dome to the West this week, cooling Texas temperatures down into the 90s.

“We fully expect to keep hitting new demand records as summer 2018 continues,” ERCOT said in a written statement.

Real-time hub average prices peaked at $1,922.20/MWh on Thursday in the 15-minute interval ending at 4 p.m. Wednesday’s high price of $2,281.95/MWh in the West zone was the highest seen since August 2015, when they hit $2,233/MWh, according to Bloomberg data.

Several retail providers have asked their customers to reduce their usage between 2 and 6 p.m. Cirro Energy, Reliant Energy and Xcel Energy have all offered conservations tips to their customers.

July 22, 2018

PJM MRC/MC Preview: July 26, 2018

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members Committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:30)

Members will be asked to endorse the following manual changes:

A. Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance (QA). Revisions developed to include or update technical specifications and procedures.

B. Manual 11: Energy & Ancillary Services Market Operations. Revisions developed to address inconsistencies between PJM’s governing documents regarding price-based offers above $1,000. The RTO hopes to introduce additional system controls to improve validation of price-based offers by November. (See “Energy Market Caps,” PJM Market Implementation Committee Briefs: July 11, 2018.)

C. Manual 14A: New Services Requests Study Process and Manual 14G: Generation Interconnection Requests. PJM is seeking to split out part of Manual 14A into a new Manual 14G to better organize interconnection information. (See “Interconnection Procedure Split,” PJM PC/TEAC Briefs: June 7, 2018.)

3. Governing Document Revisions for Seasonal Demand Response Registration (9:30-9:45)

Members will be asked to endorse revisions to Manual 18: PJM Capacity Market, the Tariff and the Reliability Assurance Agreement associated with the registration process for aggregated seasonal demand response resources. (See “Seasonal Aggregation,” PJM Market Implementation Committee Briefs: July 11, 2018.)

4. Revisions to RAA and Manual 18: PJM Capacity Market (9:45-10:00)

Members will be asked to endorse revisions to the RAA and Manual 18 associated with changes developed by the Demand Response Subcommittee to address issues identified with atypically low customer load during winter peak load calculation period. The Market Implementation Committee endorsed the changes in June.

5. Fuel Requirements for Black Start Resources Problem Statement & Issue Charge (10:00-10:20)

Members will be asked to approve a proposed problem statement and issue charge on fuel requirements for black start resources. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: July 10, 2018.)

6. FTR Credit Proposal (10:20-10:50)

Members will be asked to endorse proposed Tariff revisions to implement a 10-cent/MWh minimum monthly credit requirement for financial transmission rights bids submitted in auctions and cleared positions held in FTR portfolios. (See “Credit Requirements,” PJM Market Implementation Committee Briefs: July 11, 2018.)

7. Variable Operations & Maintenance Packages (10:50-11:30)

Members will be asked to endorse one of four proposals on what maintenance cost components should be included in generators’ cost-based offers. A proposal sponsored by American Electric Power will be considered first, followed by proposals from PJM, the Independent Market Monitor and Rockland Electric. (See “VOM Update,” PJM Market Implementation Committee Briefs: July 11, 2018.)

Members Committee

1. FTR Credit Proposal (1:10-1:25)

Members will be asked to endorse proposed Tariff revisions to implement a minimum per-megawatt-hour FTR credit requirement. (See MRC item 6 above.)

2. Variable Operations & Maintenance Packages (1:25-1:40)

Members will be asked to endorse the proposal on where and how to include VOM costs in generators’ offers that is endorsed in the MRC meeting. (See MRC item 7 above).

— Rory D. Sweeney