Page 1196 – RTO Insider

September 22, 2019

Judge to Hear PG&E Takeover Plan

By Hudson Sangree

The judge overseeing PG&E Corp.’s bankruptcy case will probably get an earful Tuesday from lawyers advocating for two warring reorganization plans.

One was drafted by PG&E and its utility subsidiary Pacific Gas and Electric, the debtors in the case. It proposes using $14 billion in new equity financing to pay off wildfire claims and to emerge from bankruptcy by June, in time to take advantage of a new $21 billion wildfire recovery fund established by the California State Legislature. (See PG&E Offers $16.9B for Wildfire Claims in Chap. 11 Filing.)

The other is by PG&E’s unsecured bondholders, which recently partnered with fire victims. The bondholders propose injecting billions of dollars of cash into PG&E and paying $24 billion to settle wildfire claims in exchange for a controlling stake in California’s largest utility and full payment of their notes.

The bondholders and victims made an impassioned plea for their plan in a joint filing Thursday. It says PG&E’s proposal essentially is a sham offer intended to delay proceedings while benefiting one of the utility’s largest shareholders. That shareholder, a high-risk hedge fund from Boston called Baupost Group, bought up billions of dollars in claims from insurance companies, known as subrogation claims, which PG&E recently agreed to settle for $11 billion. (See PG&E and Insurers Agree to Settle Wildfire Claims.)

PG&E — Tulips bloomed this spring in a neighborhood of Paradise, Calif., leveled by the Camp Fire last November. | © *RTO Insider*

(Under PG&E’s plan, fire victims would get about $8.4 billion for damages stemming from November’s Camp Fire, the deadliest in state history, and a series of fires in Northern California wine country in October 2017.)

That means even if Baupost loses money on its PG&E stock, much of which it bought for three or four times its current worth, the hedge fund can still make a killing on PG&E’s payments for fire damages, the bondholders and victims argued.

“The settlement of the subrogation wildfire claims will enrich Baupost enormously at the expense of individual wildfire victims that have suffered actual loss,” the joint motion says. “Baupost is reported to hold more than $3.3 billion in subrogation wildfire claims, much of which, upon information and belief, was purchased at approximately 35% of face value. [PG&E’s plan] would pay Baupost’s claims at roughly 59% of face value, allowing it to reap hundreds of millions of dollars in profit from the debtors’ plan, at the expense of actual wildfire victims.”

PG&E said in a news release that the plan by bondholders, led by Elliott Management Corp. of New York and fire victims’ lawyers, is “a blatant attempt to unjustly enrich the noteholders who proposed it. The Elliott proposal would cost all PG&E customers billions of dollars in additional interest payments over 15 years – while providing an unfair windfall for the noteholders and plaintiffs’ attorneys.”

The bondholders and fire victims, called the Ad Hoc Committee of Senior Unsecured Noteholders and the Official Committee of Tort Claimants, asked U.S. Bankruptcy Court Judge Dennis Montali to end PG&E’s period of exclusivity, the time it has to file its own reorganization plan without interference. That period is set to end by the end of this month if Montali doesn’t extend it.

The judge will have to begin to sort through the arguments at Tuesday’s hearing in San Francisco. The parties to the case are all trying to move it along so PG&E can benefit from the state wildfire fund.

The California Public Utilities Commission, which also must approve a reorganization plan, will need months to consider it, adding to the time pressure. The CPUC is scheduled to consider a proposed order to begin an investigation of PG&E’s reorganization plan, and its effects on ratepayers, at its meeting Thursday.

September 22, 2019

MISO Board of Directors Briefs: Sept. 18, 2019

ST. PAUL, Minn. — Google gained a foothold in the MISO system last week as the RTO’s Board of Directors approved a subsidiary’s membership application.

Google Energy joined MISO’s Eligible End-User Customers sector. The subsidiary was founded nearly a decade ago in a push to power its parent’s operations with 100% renewable energy. It has multiple investments and power purchase agreements with wind farms along the western border of MISO’s footprint, enough by 2017 to match its annual electricity consumption.

“Although our 100% renewable milestone signifies that we buy enough renewable energy over the course of a year to match our annual electricity consumption, it does not mean that our facilities are matched with renewable energy in every hour of every day,” the company says. Its ultimate goal “is to source enough carbon-free energy to match our electricity consumption in all places, at all times.”

MISO Board of Directors — MISO’s Board of Directors meets Sept. 18. | © *RTO Insider*

MISO President of Market Development Strategy Richard Doying said the RTO is anticipating more non-traditional membership applications like Google as more companies become enmeshed with distributed resources’ push to join wholesale markets.

The RTO’s approval of Google’s membership came a day before the company anno u nced a $2 billion global investment in solar and wind generation across 18 new renewable energy deals.

The board also allowed Upper Peninsula Power Co. into the Municipals, Cooperatives and Transmission Dependent Utilities sector. Both applications for membership were approved unanimously.

Lurie Joins Board

The board also filled a vacant seat with former New York Power Authority CFO Robert Lurie. The selection was made without input from MISO membership, as the seat was vacated earlier in the year by Thomas Rainwater. MISO’s bylaws stipulate that vacancies are dealt with by solely the board, and not through the usual Nominating Committee process and subsequent stakeholder vote.

“We had a robust discussion of the candidates and their qualifications, and I think he will serve MISO well,” Chair Phyllis Currie said.

MISO could have seen up to four new faces on its board in 2020, but the Nominating Committee opted only for existing board members as eligible candidates: Todd Raba, Trip Doggett and Barbara Krumsiek. (See MISO Board of Director Briefs: June 20, 2019.) The RTO will again use VoteNet Solutions to conduct its membership vote on the candidates. Electronic polls are set to open Thursday for 37 days.

This year’s Nominating Committee consisted of Directors Baljit Dail, Mark Johnson and Theresa Wise; the two stakeholder seats were occupied by Minnesota Public Utilities Commissioner Matthew Schuerger and Ameren’s Jeff Dodd.

— Amanda Durish Cook

September 22, 2019

MISO Readies MTEP 19, Debates Futures Change

By Amanda Durish Cook

ST. PAUL, Minn. — MISO staff are done assembling the RTO’s 2019 Transmission Expansion Plan (MTEP 19), presenting a nearly $4 billion draft package to the Board of Directors last week.

Instead of concentrating solely on this year’s plan, however, MISO executives at the board’s System Planning Committee meeting Sept. 17 emphasized what changes they would make to modernize the 15-year future scenarios used annually to justify transmission projects.

The proposed 2019 portfolio — 472 new projects totaling nearly $3.9 billion — is open for stakeholder review through the end of the month. The latest draft is trimmed from an earlier version that contained 483 projects at a cost of $3.95 billion. Even with the reductions, it’s still the RTO’s second-most expensive transmission buildout. (See MISO 2019 Transmission Expansion Plan Takes Shape.)

Vice President of System Planning Jennifer Curran told the board to expect some additional changes in response to stakeholder comments.

MISO said MTEP 19 is “consistent” with MTEP 18 because the package primarily consists of reliability projects. That trend appears likely to continue in the 2020 package, as the RTO has announced it would recycle its futures next year. The RTO has promised an extensive reboot of its planning projections beginning with the 2021 portfolio. (See MISO Halts Futures Work for 2020, Plans 2021 Rebuild.)

“I think [with] the status quo coming for 2020, there will be more interest in the 2021 futures,” Director Nancy Lange predicted, urging careful thought from MISO on the new futures. “I think the pace of change is only accelerating, so it’s important for MISO to think about its key planning assumptions.”

Asked by Director Phyllis Currie if there was any discord as MISO prepared MTEP 19 with stakeholders, staff cited discussions over how prominently batteries should be featured in the planning landscape.

“That’s a big focus for our team,” said Executive Director of System Planning Aubrey Johnson, adding that MISO first must create a cost recovery mechanism for storage devices.

MISO MTEP — MISO Directors Nancy Lange (left) and Phyllis Currie | © *RTO Insider*

Director Trip Doggett asked if batteries are gaining more traction because of recent technological breakthroughs or because of their transmission capabilities.

“I think it’s a ‘Yes, and…’ question,” Johnson responded, noting that batteries can mimic generation.

MISO President Clair Moeller pointed out that MTEP 19, which recommended a single battery project, anticipates just 2.5 MW of load growth. (See MISO Recommending 1st Storage-as-Tx Project.) “For perspective, 2.5 MW is the size that could be compared to a large neighborhood’s load,” he said. Moeller said that although load growth has remained flat since about 2007, load has shifted with demographics.

“So, the standard load growth isn’t driving transmission decisions. … But people are moving around,” he said.

Moeller also said differing state goals regarding their energy mixes have emerged as a planning challenge in recent years.

“When we began the [MISO] market, everyone’s fleet was about the same,” he said. “Now, not everyone thinks high wind penetration is the future. So that complicates things.”

Currie asked if neighboring RTOs were planning transmission around battery storage buildout.

“To my knowledge, we haven’t seen a strong push toward batteries,” Johnson said.

Futures Edit too Late?

Clean Grid Alliance’s Beth Soholt made use of the public comment period to call for a rework to MISO’s transmission planning strategy sooner than MTEP 21.

She pointed to utility integrated resource plans full of renewable goals, carbon-cutting pledges from state governments and a “huge customer preference and demand for renewables” as evidence that MISO cannot afford another year of waiting before it reshapes its future scenarios.

“Over another year, we’re going to use static futures,” Soholt said. “We risk the MISO system not being able to deliver what customers want in the Midwest.”

Soholt cited MISO’s February 2017 interconnection queue cycle, where all but 250 MW of the originally proposed 5 GW of renewable generation projects dropped out because of prohibitively expensive transmission upgrades.

“The processes and the systems in MISO are misaligned to solve these challenges,” Soholt said, calling the RTO’s current planning method and assumptions “frustrating and irrelevant.” She said needed transmission projects are being overlooked because of MISO’s continued underestimation of renewable growth.

Soholt said the $32 million, 345-kV Helena-to-Hampton Corner circuit project, originally identified in this year’s Market Congestion Planning Study, should have made the cut into MTEP 19. The project was set to solve congestion in southern Minnesota, but MISO said that once forecasted wind generation was removed from the equation, the project quickly lost value.

A System from Interconnection Upgrades?

Organization of MISO States President and Missouri Public Service Commissioner Daniel Hall said the RTO is ignoring “substantial” renewable growth and expressed concern over a “number of interconnection projects dropping out very late” in the queue process. He said some renewable projects were already approved by state commissions and under power purchase agreements when they were forced to exit the queue.

“We’re currently trying to plan a transmission system one interconnection at a time. … It’s a wake-up call,” Hall told the board at its meeting Thursday.

“They’re stale,” Moeller admitted of the four futures.

Board members also inquired about the lack of interregional projects with MISO, SPP Empty-handed After 3rd Project Study.)

“I think there’s [been] more planning and more discussion over the two years I’ve been here. … I’ve seen more coordination. I really think it’s a case of just because there’s congestion there doesn’t necessarily mean that it warrants a project to correct it,” Johnson said.

September 22, 2019

MISO Seeks Market Changes After Meek Summer

By Amanda Durish Cook

ST. PAUL, Minn. — The MISO footprint didn’t come close to its forecasted summertime peak and is unlikely to hit its forecasted fall peak either. But ways to improve resource adequacy in a time of grid transformation were on the minds of those at MISO Board Week here.

Times a-Changin’

MISO’s interconnection queue is further evidence of the urgency of its resource availability and need (RAN) project, Richard Doying, president of market development strategy, told the Markets Committee of the Board of Directors on Sept. 17. RAN ideas currently include a 30-minute reserve product, a resource accreditation rethink, a seasonal capacity auction and a multiday forecast. (See MISO, Stakeholders Debate Merits of Seasonal Auction.)

Based on utility and state announcements, MISO forecasts wind and solar generation will overtake coal and natural gas. By 2030, wind and solar will total 30 to 35% of generation output, while natural gas and coal will have 29% and 24 to 29% shares, respectively. Nuclear’s contribution is projected to be nearly halved to 9%. In 2018, MISO reported a fuel mix of 48% coal, 26% gas, 16% nuclear and 7% wind and solar combined.

Proposed solar projects currently comprise 59 GW of MISO’s 101-GW interconnection queue. Wind generation has a 27-GW share, while natural gas-fired resources represent 9 GW. Storage resources, still nascent in MISO, total only 3 GW. No new nuclear generation is proposed in the queue.

“We do expect to see more storage,” Doying told the board, adding that MISO is particularly anticipating solar-and-storage hybrids.

“I think you can get the whole community behind this,” Director Baljit Dail said, commending the RTO on RAN’s catchphrase, “All hours matter.”

Dail compared it — in rhetoric only — to 2001’s No Child Left Behind Act. Since last year, MISO has said it needs to shift from its one-day-in-10-years loss-of-load expectation to an approach that accounts for different risks across all operating hours.

“We have not considered ‘No Hour Left Behind,’” Doying laughed.

Director Barbara Krumsiek compared the RAN effort to “changing a tire [while] going 60, 70 mph on the interstate.”

Director Trip Doggett asked if NERC appeared to be also shifting from its one-in-10 reliability standard.

“It is something that lots of other folks are looking at,” Doying said.

But WPPI Energy economist Valy Goepfrich was quick to remind leadership that RAN is merely studying whether MISO needs to pivot to an all-hours risk. She said it could turn out that preparations for a summer peak still cover reliability risks in every other operating hour of the year.

“We’re letting the data drive what the peak is,” she told the board.

“It’s still that one hour that we have to meet. The problem is we don’t know when that hour is any more. It used to be a warm day in July or August. Now that’s shifted,” MISO CEO Joh Bear explained at Thursday’s board meeting.

Peak Forecasts Averted

MISO Executive Director of Market Operations Shawn McFarlane predicted that the RTO won’t hit its forecasted 112-GW fall peak, saying the highest risks of September’s heat have passed. (See MISO Unruffled by Fall Supply-demand Outlook.)

“Right now, the highest load we’ve had is 107 GW on Sept. 7,” McFarlane said.

MISO also fell short of its nearly 125-GW forecast summer peak, instead experiencing a 121-GW summer peak July 19.

The RTO weathered a heat wave and a hurricane in July without reliability problems. It declared conservative operations on July 18 and issued an open-ended maximum generation capacity advisory effective 10 a.m. ET on July 19 as several Midwestern cities issued excessive heat warnings and heat indexes exceeded 100 degrees Fahrenheit even in Minneapolis. Both alerts were terminated July 20. MISO’s capacity advisories ask members to prepare for emergency conditions, ready load-modifying resources for a possible call-up and ensure resource availability is up to date in the RTO’s communication system.

On July 11, MISO declared a severe weather alert for its Gulf Coast region for July 12 to 15 as Tropical Storm Barry was forming over the gulf. MISO’s weather alerts ask that maintenance and testing on any critical transmission or generation system be deferred or canceled. The alert lasted through July 20 as Entergy mobilized crews to restore power in flooded portions of Louisiana.

Independent Market Monitor David Patton said the most exciting part of the summer occurred in eastern Texas on Aug. 13, when a transformer lost cooling in the West of the Atchafalaya Basin load pocket from 4 to 6 p.m.

“We were extremely close to shedding load; if there had been another contingency…” Patton trailed off.

Prices during the contingency spiked to $560/MWh, but just over the border in sunbaked ERCOT — which was experiencing high load — prices were $8,800/MWh

Patton said the area should have been more appropriately priced at about $4,000/MWh. He added that ERCOT prices had to be attractive to MISO members, who were prohibited from lending supply because of the RTO’s own reliability risks.

“The reliability situation was far more dire in MISO than in ERCOT,” Patton said.

He again called for MISO to “beef up” its emergency and shortage prices, especially for times when portions of the footprint are “on the verge of load shedding.”

“As we grow our intermittent sources, we’re going to see more shortages,” he warned.

September 22, 2019

CAISO Takes Step Toward EIM Day-ahead Market

By Hudson Sangree

The effort to expand CAISO’s Western Energy Imbalance Market from a real-time trading platform to a day-ahead market took a significant step forward Wednesday, when members of the ISO’s Board of Governors and the EIM’s Governing Body said they supported launching a stakeholder process in October.

The first step will be an issue paper. Then the stakeholder process is expected to continue well into next year, said Keith Casey, CAISO’s vice president of market and infrastructure development. It will address issues such as resource sufficiency in a tightening Western market and interstate transmission challenges, ISO staff said.

Board Chair David Olsen and EIM Governing Body Chair Carl Linvill gave their verbal support to the stakeholder process; there was no formal vote. The occasion was a briefing on the results of an eight-month feasibility study of the extended day-ahead market (EDAM).

Fourteen current and future EIM entities, in addition to CAISO, participated in the assessment.

The non-CAISO entities wrote a join t letter to ISO and EIM leaders emphasizing they have not committed to the EDAM and want to make sure it addresses a number of concerns, including the continued independence of the Governing Body and the representation of a range of interests from across the West.

A continuing worry among EIM participants is that California politicians and CAISO might try to dominate the regional market. CAISO’s bid to form a Western RTO stalled in part because CAISO’s governors are appointed by the governor and approved by the State Senate.

“The issues to be resolved to make EDAM a reality should not be underestimated,” the entities wrote. Those that signed the letter included Arizona Public Service, Idaho Power and PacifiCorp.

“Governance structures must be considered that reflect the new market design and the legitimate interests that all within the broader market footprint will have in the operation and rules of the day-ahead market,” it said. “In addition, it is likely EDAM will need to include a test to ensure that all participating balancing authorities are not leaning on neighbors to meet their continued reliability obligations.”

Estimated Benefits

A goal of the feasibility study was to estimate the financial benefits to EIM participants to gauge their potential level of interest, Mark Rothleder, CAISO vice president of market quality, told the board and Governing Body.

The EIM has continued to add new members, but some entities from the interior West have cited the economic bonuses as their primary motivation while lamenting the tie to California. The uneasy political alliance is part of the reason SPP recently launched its own Western Energy Imbalance Service. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)

Rothleder said the study group and its consultants, E3 and Brattle Group, had projected the operational benefits of a day-ahead market at $119 million to $227 million annually, which he called a conservative estimate. (In their letter, the EIM entities pointed out that the estimate doesn’t consider how “benefits may be reduced should only a limited number of EIM entities elect to participate in EDAM.”)

The expected financial benefits will come partly through more efficient day-ahead hourly trading and better use of available transmission in an organized market, according to Rothleder’s presentation.

The EIM says its real-time market has saved participants more than $736 million since it began in 2014.

A day-ahead market could limit the curtailment of excess renewable resources by up to 2 GWh a year, sending energy where it’s needed and producing tens of millions of dollars in additional revenue for generators, Rothleder said.

Environmentalists have generally supported regional markets as a way to maximize the sharing of renewable resources, for example, by sending wind energy from New Mexico to California and solar power from California to the Pacific Northwest.

Jennifer Gardner, senior staff attorney with Western Resource Advocates and a member of the committee that nominates Governing Body members, praised the move in a news release. Adding a day-ahead market to the EIM would “allow utilities to better plan for and optimize renewable energy use on the grid through more efficient unit commitment and more effective integration of variable energy resources across a larger footprint,” Gardner said.

Sarah Edmonds, transmission director at Portland General Electric, and Jim Shetler, general manager of the Balancing Area of Northern California, were part of the assessment team. They spoke at Wednesday’s meeting and acknowledged the challenges and effects of a day-ahead market that stretches across the Western Interconnection.

“This is going to be significant and complex,” Edmonds said. “It could have consequences for the Western market as a whole.”

EIM Governance Review

The board and Governing Body also named 10 members of a committee to review the governance structure of the EIM, as required by the market’s original charter. (See CAISO OKs EIM Governance Review.)

The charter recognized that the EIM would evolve over time, and the expansion to a day-ahead market could necessitate governance changes, said Stacey Crowley, CAISO vice president of external affairs.

Members named to the Governance Review Committee (GRC) included Gardner; Therese Hampton, chair of the EIM’s Regional Issues Forum and executive director of the Public Generating Pool in the Pacific Northwest; and Eric Eisenman, PG&E’s director of ISO and FERC relations.

Their colleagues nominated Governing Body member Valerie Fong and CAISO Governor Angelina Galiteva as representatives to the GRC.

Board Chair Olsen said he’s hoping to add another member from the EIM’s investor-owned utilities because he felt the committee was light on IOU representation.

The committee will eventually include 11 to 13 members, said Peter Colussy, CAISO manager of regional affairs.

September 22, 2019

Affected-system Rules Unclear, FERC Says

By Christen Smith

FERC told MISO, PJM and SPP last week that their joint operating agreements don’t provide enough clarity on how the RTOs’ handle generator interconnections along their seams (EL18-26).

The commission agreed in part with EDF Renewable Energy and ordered the RTOs to update their JOAs and Tariffs to make the queue priority process more transparent within 60 days of its ruling Thursday. The commission declined the company’s related request (AD18-8) to expand the review of affected-system coordination in the generation interconnection process beyond MISO, PJM and SPP, however.

“Because the queue priority processes are not described in their tariffs or JOAs, we find that there is a lack of transparency in MISO, SPP and PJM that makes it difficult for interconnection customers to understand how affected-system network upgrade costs are being allocated to them,” FERC wrote. “Requiring the RTOs to detail this information in their JOAs will provide additional transparency to interconnection customers on their potential responsibility for affected system network upgrade costs, thereby reducing uncertainty that may hinder interconnection development.”

FERC advised three RTOs that their Joint Operating Agreements were unclear — | *EDF Renewable Energy*

The order comes nearly 18 months after FERC staff held a technical conference with the RTOs to address the issues raised in EDF’s October 2017 complaint that their governing documents, particularly the JOAs, lack details about the timing of affected-system analyses, the standards applied to determine impacts from proposed interconnections and how network upgrade costs are assigned. (See FERC Orders Review of PJM, MISO, SPP Generator Studies.)

FERC Order 2003 requires a transmission provider to coordinate interconnection studies and planning meetings with affected systems — electric systems other than the host transmission provider that may be affected by a proposed interconnection.

EDF argued that the lack of clarity regarding the RTOs’ delivery requirements and modeling standards violates the commission’s requirement for transparent, open-access interconnection service.

FERC said that despite insistence from the RTOs to the contrary, their existing documents lack transparency and cause “harm due to uncertainty” for EDF and other interconnection customers who struggle with decisions about whether to remain in the queue for fear of incurring unknown costs.

“Cost uncertainty presents a significant obstacle to the development of new resources, as some interconnection customers are less able to absorb unexpected and potentially higher costs for interconnection facilities and network upgrades that may occur once affected-system study results are considered,” FERC wrote. “This lack of transparency in the current affected-systems coordination process between MISO, SPP and PJM has the potential to hinder the timely development of new resources and thereby to stifle competition in the wholesale markets, resulting in rates that are not just and reasonable or are unduly discriminatory or preferential.”

The commission, however, rejected EDF’s request that the RTOs unify their modeling systems and study timelines, deeming neither necessary for providing greater transparency.

The RTOs’ compliance filings must include:

Current affected-system coordination processes, including the provision of clear references to where affected-system study information can be found in their business practice manuals;
A description of the modeling standard (external resource interconnection service or network resource interconnection service) they use to study, as the affected RTO, interconnection customers that request ERIS in the host RTO and interconnection customers that request NRIS in the host RTO;
The location in their manuals or other coordination documents where interconnection customers can find the modeling details that they use when studying a project as ERIS or NRIS for interconnection requests on their own systems;
For MISO and SPP specifically, a description of how they study the impacts on the affected RTO and clarify that the each RTO’s study criteria apply to its own facilities;
How the three RTOs monitor each other’s systems during the course of each of their interconnection studies;
PJM’s process for monitoring neighboring systems for affected-system impacts; and
PJM’s timeline provided to interconnection customers to review affected-system study results.

September 22, 2019January 18, 2024

SPP Board OKs $9.5M to Build Western EIS Market

By Tom Kleckner

SPP’s dream of operating an energy market in the Western Interconnection came closer to reality Friday with its Board of Directors’ approval of start-up funding for the Western Energy Imbalance Service (WEIS) market.

The board accepted staff’s recommendation to budget $9.5 million to develop and stand up the market. The Members Committee supported the recommendation, with only Xcel Energy’s Southwestern Public Service abstaining from the vote during a conference call.

Committee members peppered SPP staff with questions about the proposal’s costs to existing members and whether the RTO will maintain a division between Eastern and Western members. Staff assured members there will be no increase to corporate overhead.

Asked how the market will help “East-side members,” Senior Vice President of Operations Bruce Rew said current members would benefit from the “additional use of the SPP system.”

“That will provide additional revenue through corporate overhead costs and reduce the SPP administrative fee accordingly,” Rew said.

Staff said they have been tracking expenses to develop the market proposal and will continue to do so. The RTO said it will add 13 employees to perform the WEIS functions and will begin the hiring process “as soon as practical.”

“We have a 16-month schedule, and there’s a lot of work to be done,” Rew said.

SPP says it will finance the costs during the implementation period by issuing debt. It will then recover the costs from the WEIS participants over eight years, beginning in December 2020, using a formulized rate that includes projected annual production costs, start-up principal and interest charges, and current net energy for load.

Market participants who terminate WEIS services within the first eight years are obligated to pay their portion of the remaining implementation costs. Additional participants who enter the market within that period will be allocated a portion of the original implementation costs.

The WEIS will operate similarly to SPP’s imbalance market, which ran from 2007 to 2014, centrally dispatching energy on a five-minute basis under a Western joint dispatch agreement. Members will operate under a separate tariff and market protocols from SPP’s Eastern Interconnection members. Should a WEIS member decide to join the RTO as a transmission owner, the balance of its implementation costs would be spread out among the market’s remaining participants.

SPP has long explored offering market services in the Western Interconnection and seeking new members. An effort to integrate the Mountain West Transmission Group fell apart last year, but the grid operator’s attempt to provide reliability coordination services to 12% of the region’s load is on schedule to meet a December timeline. (See SPP Western Reliability Briefs: Week of Sept. 16, 2019.)

The WEIS market will become the West’s second, joining CAISO’s Western Energy Imbalance Market.

SPP says the WEIS will go live in February 2021. It already has five market participants in Basin Electric Power Cooperative, Tri-State Generation and Transmission Association, and three Western Area Power Administration entities: Colorado River Storage Project, Rocky Mountain Region and Upper Great Plains. All five organizations signed contracts in September to fund the market’s development. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)

The grid operator said it will accept additional participants through Oct. 25. Market participants who want to join the WEIS after that date will be onboarded through SPP’s normal processes.

Xcel, Colorado’s largest load-serving entity, and three partners — Black Hills Energy, Colorado Springs Utilities and Platte River Power Authority — have announced they are evaluating both the WEIS and the EIM. (See Colorado Utilities Examine Market Membership.)

SPP made the WEIS public in June, distributing a proposal to 19 interested parties in the interconnection.

It expects to file a WEIS Tariff with FERC early next year. Legal staff said they were not aware of any necessary state regulatory filings.

September 20, 2019

CAISO, CPUC Warn of ‘Reliability Emergency’

By Hudson Sangree

FOLSOM, Calif. — CAISO’s Board of Governors on Wednesday heard that the ISO could face capacity shortages as soon as next year if steps aren’t taken to address the potential shortfall, including keeping aging natural gas plants from retiring as planned.

In a presentation to the board, CAISO Vice President Mark Rothleder said summer peak demand is shifting from late afternoon to early evening. People now are going home and turning on their air conditioning around 7 p.m., just as solar power peters out, he said.

“The issue is not so much at the peak hour,” Rothleder said. “It’s at the near-peak hour as the sun goes down.”

By next summer there could be insufficient capacity to meet the ISO’s system reliability requirements, which include a 15% planning reserve, Rothleder said.

Imports that aren’t already under contract could fill the gap, but tightening supply in the West makes those imports unreliable. California’s neighbors are using more of their own electricity instead of exporting it, he said.

Rothleder said the shortages could start in the hot summer days of 2020 with a 2,300-MW shortfall at 7 p.m., increasing to 4,400 MW in 2021 and 4,700 MW in 2022. The problem could worsen when Pacific Gas and Electric’s Diablo Canyon Power Plant, the state’s last nuclear generating station, shuts down in phases starting in 2024, he said.

California is on an ambitious push to use carbon-free energy, but to avoid a crisis it may be necessary to prevent older natural gas peak plants from shutting down, Rothleder told the board.

“We’ve got the last tranche of once-through cooling scheduled for retirement” near the end of 2020, Rothleder said. Those plants can generate about 4,000 MW, he said.

Once-through-cooling (OTC) plants are being phased out because they use water from oceans and estuaries, killing billions of marine organisms including fish larvae and shellfish, according to the California Energy Commission.

“We need to get on the track of procurement” to generate more energy, Rothleder said.

Increasing wind and geothermal energy production, and adding more short- and long-term storage, would provide energy after sundown without greenhouse gases, he said.

In public comments Wednesday, speakers encouraged the board to move quickly to address the resource adequacy problem.

“We urge the ISO to continue to work on this expeditiously. Soon. Now. Not later,” said Eric Eisenman, PG&E’s director of FERC and ISO relations.

Board Chair David Olsen responded, “This is obviously our top priority. Front and center for us.”

Edward Randolph, director of the California Public Utilities Commission’s Energy Division, told the board that the commission also is acting on the threat.

“We do take what is being raised here today pretty seriously,” Randolph said.

On Sept. 12, a CPUC administrative law judge issued a proposed decision requiring load-serving entities in Southern California Edison’s service area to procure 2,500 MW of additional resources between August 2021 and August 2023. ALJ Julie Fitch also recommended keeping the OTC plants operating, a decision that’s ultimately up to the state Water Resources Control Board.

“Procurement shall be conducted on an all-source basis, including both existing and new resources, and may include LSE-owned resources when justified,” Fitch wrote.

“The commission should act now to forestall a potential system reliability emergency by 2021 and require ‘least regrets’ actions with respect to OTC deadlines and LSE procurement,” she said.

The CPUC could vote to adopt the decision as early as Oct. 24, it said.

September 20, 2019March 13, 2025

NERC Agrees to Increase New Committee’s Membership

By Rich Heidorn Jr.

MINNEAPOLIS — NERC’s Stakeholder Engagement Team (SET) has agreed to expand the membership of the new committee that would replace the Planning, Operating and Critical Infrastructure Protection committees, stakeholders were told last week.

SET member Lloyd Linke, of the Western Area Power Administration, told a joint meeting of the OC and PC that the new Reliability and Security Council (RSC) will have 34 voting members: two each from Sectors 1-10 and 12, for a total of 22; 10 at-large members, a chair and a vice chair. The committee will also have five nonvoting members, including a NERC staffer as secretary, along with two U.S. federal representatives, and two Canadian representatives: one federal and one from the provinces.

If a sector does not have two members, the vacant slot will be filled by an additional at-large member to keep the total at 34 members.

The RSC will be only about a quarter of the size of the three technical committees it will replace, which have almost 120 voting members. But the SET’s original plan called for only one member from each sector, a proposal that met opposition. (See NERC Board Hears Debate over Committee Reorg.)

Linke also said the RSC meetings will be open to other stakeholders.

He said the move was driven by a desire for a “better functional alignment” between the technical comms and the Reliability Issues Steering Committee (RISC). Reducing travel and hotel costs “wasn’t a primary driver,” he said. “It wasn’t a big driver at all.”

The RSC members will have three- and two-year terms initially, then revert to staggered two-year terms. Once the committee is set up, the RSC nominating process will follow the model of the Compliance and Certification Committee.

Linke said one of the initial tasks of the RSC will be determining how to continue the “lessons learned” sharing and awareness functions used by the technical committees.

“We don’t want to lose that engagement,” said John Moura, NERC director of reliability assessment and technical committees. Concerns about the potential loss of functions “hit [NERC] staff strongly,” he said.

The SET rejected suggestions that the technical committees evaluate their subcommittees to determine their future. “There was a desire not to tie the hands of the new RSC,” Linke said.

The schedule calls for the RSC to hold its first meeting in March along with the three technical committees, which would end their operations effective June 1.

Some members expressed opposition to the proposed committee merger after the OC and PC split for their separate meetings.

“I don’t think the new structure is going to have the amount of expertise or dedicate as much time as [the technical committees] do,” Peter Brandien, vice president of systems operations for ISO-NE, said at the PC meeting.

“I think the most important aspect of this plan is the change of this legislative structure from one that is wholly elected to one that is partly elected and partly appointed. The world’s currently best-known example of that kind of legislature is Hong Kong,” said Robert Blohm, managing director of Keen Resources. “That’s my comment.”

September 20, 2019

SPP Western Reliability Briefs: Week of Sept. 16, 2019

SPP’s efforts to extend reliability coordination services to about 12% of the Western Interconnection’s load remains on a glide path, staff said this week during a pair of meetings with Western entities at Black Hills Energy’s offices in Rapid City, S.D.

The RTO is preparing for the start of shadow operations and a second certification visit by regulatory representatives in October. It plans to go live with RC services in the West on Dec. 3.

C.J. Brown, SPP’s director of system operations, told the Western Reliability Executive Committee on Wednesday that the grid operator is focused on closing issues identified by a Western Electricity Coordinating Council-led certification team’s August site visit. (See Certification Team Checks SPP’s Western RC Function.)

“Everything is on track,” he said.

The team did not find any “showstoppers,” Brown said, but left behind several issues it felt SPP needs to resolve before going live. Staff expect to close those issues by October and are on track to close about 40% of “recommended” issues before the certification team’s return visit on Oct. 9.

By then, SPP will have begun two months of shadow operations with Peak Reliability, WECC’s incumbent RC. Peak said in August 2018 it would wind down operations by the end of this year. SPP, CAISO RC Wins Most of the West.)

Shadow ops begin on Oct. 7, but SPP operators will begin staffing the RC desk on Sept. 25. A shadow ops model is expected to be in production on Oct. 1.

Brown said SPP staff have received a separate request from WECC, FERC and NERC staff to visit the RTO’s Arkansas headquarters in early November. The agencies conducted a similar visit to CAISO’s RC West.

“If it’s a good idea for California, it’s a good idea for SPP too,” Brown said.

Tri-State Generation and Transmission’s Keith Carman, chair of the WREC, offered words of praise for Peak employees, who have been working closely with staff from the incoming RCs.

“These employees have been nothing but professional, responsive, kind and receptive,” Carman said. “It’s way unexpected too, considering the predicament they’re in.”

RCs have been compared to top cops for transmission reliability across wide geographic areas. They are responsible for ensuring each member focuses on reliability, particularly across the seams from one area of responsibility to the next.

Brown also briefed the NERC Operating Committee on the RC transition last week, telling members said SPP “will be more proactive” in November before going live at noon MT on Dec. 3.

Staff Reconciling CAISO ICCP Data

SPP’s Yasser Bahbaz told the Western Reliability Working Group it has received more than 10,000 inter-control center communications protocol (ICCP) data points from CAISO as it works to stand up its western RC model. Staff is currently validating about 4,000 of those points, which changed from Peak’s model to CAISO’s.

“Someone made a change from an old name to a new name,” Bahbaz said. “We’re having to go one-by-one to reconcile.”

Brown said the CAISO model will become SPP’s primary model, with an earlier Peak model becoming secondary.

SPP has also downloaded Peak’s outage data into its systems and was to spend this week validating software applications with Peak’s balancing authorities. The RTO has already completed ICCP connectivity with its 13 RC customers.

SPP has ‘Good Handle’ on Reserve Sharing Groups

SPP is not concerned with “special circumstances” surrounding reserve sharing groups (RSGs) in the West, Brown told the WRWG. RSGs consist of two or more BAs that collectively maintain, allocate and supply operating reserves for use in recovering from contingencies within the group.

The Northwest Power Pool’s RSG has reserve requirements for the Western Area Power Administration’s Colorado and Missouri (WACM) region’s BA, while other WACM entities are part of the Southwest Reserve Sharing Group.

“I believe we have a good handle on the RSGs,” Brown said. “It’s pretty basic. We run one.”

SPP is working to receive contingency reserve data from the NWPP and Bonneville Power Authority RSGs. It plans to soon request the contingency reserve data for each BA within its RC footprint.

“We want to ensure every resource is covered by an RSG or a reserves requirement,” Brown said. “We just want to know how it’s done in the West. We want to understand the situation, so we have [it] accurately modeled.”

Brown said SPP would only issue energy emergency alerts in the West for reliability concerns. BAs will be responsible for meeting NERC’s BAL-002 requirements.

“We don’t expect anyone to shed load for a compliance violation,” he said.

WREC Approves Doc Modification Process

The WREC unanimously approved a modification oversight process (MOP) to manage document modifications related to the RTO’s Western RC services. The WRWG had been working to finalize the document since May.

The MOP applies to documentation established by SPP or SPP working groups that might affect operations or have a compliance or financial impact on its Western RC services customers. (See “SPP’s MOP ‘Cleans Up Stuff,’” SPP Western Reliability Briefs: Week of May 13, 2019.)

— Tom Kleckner