California Gov. Gavin Newsom named new members to the CAISO Board of Governors on Tuesday, along with a new member to the Public Utilities Commission and members of the state’s newly created commission on catastrophic wildfires.
To the CAISO board, Newsom appointed University of California Berkeley Professor Severin Borenstein and Los Angeles Business Council President Mary Leslie. He also reappointed current CAISO Chairman David Olsen to a second two-year term.
“This is an exciting time for the ISO as the industry develops approaches to reliably integrate renewable energy,” Borenstein told RTO Insider in an email. “The board will have an important role facilitating opportunities for beneficial trade with the rest of the western market and continuing to support California’s climate goals.”
The five-member CAISO board will have to grapple with major issues this year, including the ISO’s new reliability coordinator role for much of the West. Service on the CAISO board pays $40,000 per year.
Borenstein has been a professor at Berkeley’s Haas School of Business since 1996. He serves as the faculty director of the business school’s Energy Institute. Previously he was a professor at the University of California Davis.
Leslie has been president of the LABC since 2002. She was the deputy mayor of Los Angeles under Mayor Richard Riordan from 1994 to 1995 and a commissioner at the Los Angeles Department of Water and Power from 2001 to 2003.
Challenges also await the PUC as it tries to deal with the fallout from PG&E Corp.’s collapse because of massive wildfire liability.
Newsom named Genevieve Shiroma, an elected director of the Sacramento Municipal Utility District, to fill the seat on the PUC left vacant when Commissioner Carla Peterman’s term expired in December.
Shiroma was a longtime member of the state Agricultural Relations Board and its former chairwoman. She was chief of the Air Quality Branch at the California Air Resources Board from 1990 to 1999 and an air quality engineer from 1978 to 1990.
The PUC position pays $153,689. Newsom’s nominees to the PUC and CAISO require State Senate approval.
Newsom appointed Peterman to an unpaid seat on the state’s new Commission on Catastrophic Wildfire Cost and Recovery, established as part of last year’s Senate Bill 901 to examine wildfires caused by utility infrastructure and “to produce recommendations on changes to law that would ensure equitable distribution of costs among affected parties.”
The six-member panel is required to hold at least four public workshops and provide recommendations to the governor and State Legislature by July 1.
In her last meeting with the CPUC in December, Peterman emerged as a strong proponent of giving utilities leeway to de-energize transmission lines under dangerous weather conditions. De-energization “is an option we don’t want to exercise often, but we do want the option to exercise,” she said at the time. (See Calif. Regulators to Scrutinize De-energization.)
Joining Peterman on the panel is former State Assemblyman Dave Jones, the state’s insurance commissioner from 2011 until earlier this month. Jones previously served as counsel to U.S. Attorney General Janet Reno and worked from 1989 to 1995 representing low-income families and individuals for Legal Services of Northern California.
The commission will also include Crowell & Moring attorney Michael Kahn, who was CAISO chair from 2001 to 2005 and head of the California Electricity Oversight Board from 2000 to 2001. Kahn was also a member of the California State Insurance Commissioner Task Force on Environmental Liability Insurance from 1993 to 1994.
The legislature will fill the other three seats on the wildfire panel. Appointees do not require Senate approval.
SACRAMENTO, Calif. — Could PG&E’s announcement that it plans to file for bankruptcy Jan. 29 be a ploy? A lawyer representing thousands of wildfire victims said she thinks it’s quite possible.
On the steps of the California state Capitol Tuesday, former state Sen. Noreen Evans, now a plaintiffs’ attorney, said she believes PG&E won’t go through with filing for Chapter 11 reorganization at the end of the month, as it has said it would.
The utility’s move likely is an attempt to get California’s new governor, Gavin Newsom, and lawmakers to intervene, Evans said.
“I think there’s a very huge possibility they won’t file as planned,” Evans said. “It would open a can of worms.”
If PG&E, the state’s largest utility, were to enter bankruptcy, it would call into question billions of dollars in energy contracts and payments to CAISO, among other obligations. (See PG&E Meltdown Could Cost CAISO Members, Generators.)
Evans, whose former district includes areas of Santa Rosa, Calif., devastated by wildfires in 2017, is now part of a legal team representing 4,000 fire victims in the state’s catastrophic blazes during the past two years.
The ex-lawmaker joined famed PG&E foe Erin Brockovich at the Capitol to protest the utility’s alleged efforts to avoid financial liability for the Camp Fire, which killed 86 residents and destroyed the town of Paradise, Calif., in November 2018. The wildfire was by far the deadliest blaze in state history.
Brockovich urged California leaders to do more than have a seat at the table in deciding PG&E’s fate. “Be the head of the table and take control of this runaway monopoly,” she said.
Brockovich gained movie fame after she helped build a case against PG&E in the 1990s for polluting the desert town of Hinkley, Calif., with hexavalent chromium. She has remained one of the utility’s most prominent critics.
Brockovich, Evans and other victim advocates don’t want PG&E to enter bankruptcy because it would put plaintiffs and their lawyers in line for payment behind PG&E’s secured creditors. A bankruptcy judge would parcel out compensation, not jurors.
Investors, too, are arguing against PG&E’s bankruptcy plan. BlueMountain Capital, a major shareholder, sent the utility a second letter this week urging it to postpone filing for bankruptcy protection and arguing bankruptcy is unwarranted. PG&E shareholders would likely lose their investments in a Chapter 11 reorganization.
Evans and other PG&E critics, notably public interest group Consumer Watchdog, have said PG&E’s bankruptcy is a ruse to get state lawmakers to do what they wouldn’t do last year — get PG&E off the hook for billions of dollars in liability.
After the wine country fires of 2017 devastated Napa and Sonoma counties, PG&E lobbied lawmakers to overturn California’s longstanding use of inverse condemnation to hold utilities strictly liable, regardless of negligence, for damage to private property caused by their equipment.
Gov. Jerry Brown sided with PG&E last year because he was worried the giant utility would renege on the billions of dollars it plans to invest in renewable energy. In passing Senate Bill 901 last year, lawmakers didn’t alter inverse condemnation, but they provided a process by which utilities could seek long-term bond financing for wildfire debts. (See California Wildfire Bill Goes to Governor.)
The process, however, didn’t apply to 2018 fires, including the Camp Fire. Lawmakers initially showed interest in amending SB 901 to include last year’s fires but have recently backed off because of public anger against the utility.
Though state officials have yet to determine the cause of the Camp Fire, PG&E has said its transmission line sparked flames near the start of the Camp Fire on the morning it began.
PG&E announced earlier this month it would file for bankruptcy because it faces at least $30 billion in financial exposure for the Camp Fire and wine country fires. Absent state intervention, it said, bankruptcy was its only viable option.
SPP saw an increase in price spikes and overall prices during October and November thanks to above-normal scarcity pricing, according to the Market Monitoring Unit’s fall State of the Market report.
The Monitor attributed the scarcity increases to higher volatility in wind output, pointing to an increase in mid- and long-term wind forecast errors as the primary culprit. It also said a 72% increase in natural gas spot prices at the Panhandle hub ($2.13/MMBtu to $3.67/MMBtu) and unplanned generator outages or derates contributed to the uptick.
Volatility of wind output | SPP
Redispatch costs increase faster with more expensive gas until scarcity occurs, the MMU said, driving up the number of scarcity events.
“Since the scarcity caps are price-based, they are reached more frequently due to increased gas prices,” the report said.
The long-term wind forecast, used for the day-ahead reliability unit commitment’s wind output, had an average error rate of 7.8% in 2018, almost double the 2016 average of 4.3%. The mid-term load forecast, used four hours ahead of the intra-day RUC processes, had an average error rate of 4.5% last year, 28% higher than 2016’s average of 3.5%.
When large wind dips are not accurately forecasted, the market will often be short rampable capacity, the MMU said. This forces SPP operators to manually force more capacity online.
The real-time marginal energy price peaked at $1,575/MWh at 2:40 p.m. on Sept. 3. Operators responded to an unexpected sudden drop in wind output by adjusting the load offset and manually committing quick-start units. It took three intervals before prices dropped back below triple digits.
The Monitor said there is no “current answer for better forecasting” fluctuations in wind energy but noted a ramp product would “help abate these price spikes” by reducing their frequency and effects.
“By reserving ramp for unexpected conditions, such as wind drops or unit trips, the market will be better positioned when these events occur,” the MMU said.
SPP’s Market Working Group is coordinating staff’s development of a ramping product. Staff is currently testing different alternatives.
The fall report covers September, October and November. The MMU will host a webinar on Friday at 1 p.m. CT to discuss the report.
The report also indicates the following:
Energy prices have climbed slightly, with fall prices averaging around $27/MWh.
The number of intervals with negative energy prices continues to decline.
Overall congestion across the SPP footprint has declined.
Commission Welcomes Legislative Input on Energy Storage
Texas regulators last week agreed to let state lawmakers help them determine who will own energy storage devices in the ERCOT market.
DeAnn Walker, chair of the Texas Public Utility Commission, said during the commission’s Jan. 17 open meeting that she prefers to hear from legislators before developing rules, reiterating a position expressed in a recent report to the 86th Texas Legislature. (See “PUC Asks Legislators for Clarity on Battery Storage Ownership,” ERCOT Briefs: Week of Jan. 7, 2019.)
“If they don’t, we can circle back in June … because we or the legislature need to address this,” Walker said. “I’d like to give them the opportunity, because we asked them to weigh in.”
The PUC has already opened a rulemaking on energy storage ownership (Project 48023) after last year rejecting AEP Texas’ request to connect two West Texas battery storage facilities to the ERCOT grid. Transmission and distribution providers have squared off against generators over the devices’ ownership.
Walker said in the meantime she wants to start a discussion on electric vehicles and asked staff to open a project on the subject. She has suggested the PUC work with the Texas Commission on Environmental Quality in planning how the distribution system will support the charging stations’ infrastructure.
“There’s going to have to be a charging station in Marfa, Texas,” Walker said, referring to the artistic community of about 2,000 people in the West Texas desert. “No one’s going to be able to get from El Paso to [Austin] without one.”
Walker hopes to have recommendations ready for the next legislative session in 2021.
Prelim Order Sets Issues in Oncor-Sharyland-Sempra Deal
The PUC issued a preliminary order identifying issues to be addressed in proposed transactions involving Sempra Energy, its Oncor subsidiary, Sharyland Utilities and Sharyland Distribution & Transmission Services — but not before first chiding the parties for clouding the issue of who will own what and where (Docket 48929).
The companies in October announced deals worth $1.37 billion, with Sempra buying a 50% stake in Sharyland D&T and Oncor acquiring transmission owner InfraREIT. (See Sempra, Oncor Deals Target Texas Transmission.)
“It would be helpful if you could file a table” listing the assets, Walker said. “Not a chart, because your charts make no sense.”
“We could have done a better job in our application setting forth exactly what we’re asking for,” said an apologetic Lino Mendiola, legal counsel for the Sharyland companies. “It’s a complicated transaction. We recognize that.”
Of specific concern to Walker is who will own the transmission assets necessary to integrate Lubbock Power & Light into ERCOT. The PUC last year approved Lubbock’s transfer of 70% of its load from SPP into ERCOT. Coincidentally, it came during the same meeting that Sempra’s acquisition of Oncor was approved. (See Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)
The transactions would result in Sharyland T&D becoming an indirect, wholly owned subsidiary of Oncor, owning transmission and distribution lines in Central, North and West Texas. Sharyland Utilities would remain in South Texas, with Sempra owning an indirect 50% interest.
Mendiola said the geographic split between Oncor and Sharyland complicates the situation, but that the parties had worked out an 86-14 split of assets. Most of the transmission infrastructure would reside in the north with Oncor.
“Our group wants to ensure there are not things in the transmission rates that shouldn’t be in the transmission rates,” said legal counsel Phillip Oldham, representing Texas Industrial Energy Consumers, the lead intervenor in the proceeding.
A hearing on the merits is scheduled for April 10-12.
ERCOT Governance Changes Approved
The PUC approved by consent amendments to ERCOT’s Articles of Incorporation and bylaws (Docket No. 48677). The changes were approved by more than the necessary two-thirds of the grid operator’s corporate membership in September.
CARMEL, Ind. — With spring maintenance season approaching, MISO is opening the floor to encourage stakeholders to offer ideas to address the growing divide between resource availability and need.
MISO is commencing work on longer-term solutions in its multiphase resource availability and need project, focusing on possible revisions to its loss-of-load expectation study and load-modifying resource (LMR) accreditation. It is also exploring further changes to outage scheduling, new seasonal capacity modeling and a possible development of a seasonal capacity auction. Discussions on more major changes will continue through 2019.
During a Jan. 17 Market Subcommittee meeting, Chair Megan Wisersky said the discussions are now “de rigueur” at the large public MISO stakeholder meetings.
The RTO will this month also file a proposal requiring resources to provide 120 days’ notice for planned outages, with only one “limited adjustment” to the outage schedule allowed up to 60 days before it begins. Those outages would not be permitted during predefined periods with expected low margins.
MISO had planned by April 1 to implement a firm policy of considering outages scheduled during low-margin periods as forced, impacting a resource’s accreditation. However, the RTO is now pledging to grant an exemption to outages and derates starting between April 15 and July 29 if resource owners provide two weeks’ notice and “adequate margin is projected when requests are scheduled.” The revision comes after several stakeholders this month called for less stringent rules. (See Stakeholders Press MISO for Flexibility in Outage Proposal.)
MISO market design adviser Dustin Grethen said the Market Subcommittee should now shift focus to what’s needed to meaningfully improve price signals to spur more available and flexible supply. MISO may make at least two more FERC filings, one late this year focused on resource adequacy — if needed — and one in the first half of 2020 focused on new market mechanisms.
“The start of the 2016 planning year, we saw energy offers significantly drop. We used to see about 8 GW more in energy offers,” Grethen said, adding that since that time, MISO has used less traditional sources such as wind power and reserves to cover its load and supply requirements.
Grethen said the drop coincided with EPA’s rollout of the Mercury and Air Toxics Standards, which forced many coal-fired generators into retirement.
Some stakeholders debated whether MISO should extend its official calendar summer season, pointing out that the latest maximum generation event took place in mid-September, on a blisteringly hot day but still outside of what the RTO considers summer. Outside of MISO’s peak summer season, LMRs are not required to respond to emergencies.
MISO staff said the event technically occurred in what the RTO considers fall, despite the heat.
“Timing is everything,” Customized Energy Solutions’ David Sapper commented wryly.
Sapper urged MISO to incentivize more supply by staying away from solutions that include generator penalties. “I think you’ve heard from stakeholders that we want more carrots than sticks,” he said.
CES’ Ted Kuhn asked why MISO’s LOLE study doesn’t predict likely emergency frequency when the study projects other system conditions. He said the LOLE study could be redesigned to show when and where MISO will likely face tight operating conditions.
“When is the number of emergencies more than what we really plan on?” he asked.
Sapper asked if MISO might revive discarded market ideas, such as financially binding multiday commitments.
“I think a lot of that’s to be determined,” Grethen said. He added that any solution that MISO recommends will be supported by studies and simulations.
Grethen said he would return in February for a more in-depth discussion on long-term supply fixes and a formal request for solution submissions.
NEW ORLEANS — SPP staff have been tasked with providing “at least an outline” of comments next week for submittal to EPA in response to its proposed rulemaking under Clean Air Act Section 111b.
Usha Turner, OGE Energy’s director of environmental affairs and federal public policy, appeared before SPP’s Strategic Planning Committee last week to make the request, saying that the RTO’s role as a reliability manager “carries significance” on this issue.
EPA in December proposed revisions to a 2015 Clean Air Act rule stipulating that partial carbon capture and storage (CCS) technology was the best system of emission reduction (BSER) for new coal-fired plants. Turner said the changes would mainly revise CO2 emissions limits that apply to new coal plants but pointed out that the agency is also accepting comments on the need to revise the rule to allow more flexibility in operating simple cycle combustion turbines (SCCTs).
“It would be important for SPP to engage,” Turner told the SPC during its Jan. 16 meeting. “We found in talking with the EPA last year a lack of understanding of how this market works, and why the diversity and flexibility of resources and the diversity in technology is very important in your role of providing affordable and reliable electricity in your service territory.”
The comment period is open through Feb. 21. Turner said the deadline could be delayed, however, by the partial government shutdown.
Turner said SCCTs have a rolling 12-month efficiency-based generation output limit, but if a unit exceeds this limit, it must comply with combined cycle units’ CO2 limits.
“The rule establishes output-based restrictions for simple cycle units,” Turner explained. “If you operate those units above a certain capacity factor, you must meet the emissions standards of a combined cycle unit, which, by design, is unachievable.”
“This is a pretty substantial issue,” said Golden Spread Electric Cooperative’s Mike Wise, noting his company discussed the issue with EPA recently when installing its own CTs. “We’re concerned about these rules. The pool’s need for these resources shouldn’t be unduly constrained.”
“Our area is really a good laboratory,” SPP Vice President of Engineering Lanny Nickell said. “We should not be constraining these units that absolutely keep the grid’s reliability functioning properly.”
Nickell said he wasn’t sure whether the Feb. 21 deadline would provide SPP enough time to study the rule’s impact, but he said common sense told him that “new units, more efficient and economical, are being punished.”
“I believe that’s where we end up. We’ll see more emissions,” he said.
Michael Desselle, the RTO’s chief compliance and administrative officer, reminded the SPC about the organization’s agnostic view of resources.
“If there’s any advocacy we should be talking about, it’s to leave us the flexibility in the marketplace, and the RTO, for reliability purposes,” he said. “You need a diverse portfolio of resources.”
Steve Gaw, representing the Advanced Power Alliance (formerly The Wind Coalition), said he was concerned about a lack of analysis about the rule’s impact on the market. “I’m not sure SPP should be advocating for individual companies with varied interests,” he said.
Altenbaumer Continues to Exert his Influence
Larry Altenbaumer is playing a strong hand in his first year as chairman of SPP’s Board of Directors.
In the few months since replacing Jim Eckelberger last year, Altenbaumer has revamped board meetings, shortening the duration and focusing them on strategic discussions with members and the Regional State Committee. (See “Altenbaumer Tweaks New Governance Schedule,” SPP Board of Directors/Member Committee Briefs: Oct. 30, 2018.)
Pointing to stakeholder satisfaction surveys that indicate shortfalls in strategic planning, Altenbaumer said he wants to make better use of the opportunities for the board and its interaction with the Members Committee and the RSC.
Altenbaumer has also assumed chairmanship of the SPC. Long-time committee chair Wise is now vice chair.
Altenbaumer told the SPC he will also chair a task force on affordability and value, an initiative he has been pushing since last January. He hopes the group’s work will be incorporated into SPP’s 2020 operations planning and budget cycle.
“We’ll make an assessment in October this year about what further steps might need to be addressed,” Altenbaumer said.
The task force is scheduled to hold its first meeting on Jan. 30, following the board’s regular quarterly meeting. Altenbaumer said the meetings will be “quasi closed,” with each SPP member entitled to have one representative attend.
Outside groups will be invited to present best practices and their own successful experience within other organizations, Altenbaumer said. He said the group will identify ways to better communicate the task force’s efforts and will work to “keep the RSC up to speed.”
The task force will report to the board and also includes CEO Nick Brown and Directors Bruce Scherr and Julian Brix; Markets and Operations Policy Committee Chair Holly Carias, with NextEra Energy Resources; Wise; retired Director Harry Skilton; and member representatives Darrin Ives (Evergy), Jerry Peace (OGE Energy) and Jim Jacoby (American Electric Power).
SPP staff will continue to work with members as it struggles to provide a solid foundation for validating accurate network integration transmission service (NITS) data.
COO Carl Monroe reviewed staff’s 2018 efforts in surveying customers’ understanding of their responsibility to report NITS load. He said grandfathered agreements and behind-the-meter generation have hindered integrating the reported data.
Transmission customers are legally responsible for reporting their load, Monroe said, but this information may also be provided by meter agents. He said a single NITS contract can involve multiple pricing zones, with each zone comprising multiple delivery points, and that a single transmission zone can have multiple settlement locations.
Asked by Altenbaumer how close SPP is to where it should be in reporting the data on a 1-to-10 scale, Monroe said, “Eight or 9. I’m not sure it’s a 10, but that’s a Carl Monroe sense.”
While the work is not yet complete, Monroe said he is ready to facilitate a discussion with interested stakeholders to draft a revision request for mapping NITS data.
The D.C. Circuit Court of Appeals on Friday denied a petition by North Carolina to overturn several FERC decisions that kept the state from acquiring the system of dams on the Yadkin River (17-1243).
The state has been seeking the four dams collectively known as Yadkin Hydroelectric Project No. 2197 since 2009, when previous owner Alcoa announced it would close and dismantle the Badin Works aluminum smelting plant. The Yadkin Project had powered the plant, which at its peak employed about 1,000 workers, for almost half a century.
The High Rock dam, one of four that make up the Yadkin Project in North Carolina
Alcoa started curtailing production and laying off workers in 2002 amid a downturn in the aluminum market. By the time it applied for relicensing in 2006, Alcoa was only using 3 to 5 MW of the 210.5-MW project to power the plant.
In approving Alcoa’s application in 2016, FERC denied North Carolina’s proposal that the U.S. government acquire the project and transfer it to the state, saying the company had failed to maintain the jobs at Badin Works, which had been cited as a benefit in the project’s original 1958 license (P-2197).
“The state’s proposal — albeit creative — lacked any basis in the law,” D.C. Circuit Judge David B. Sentelle wrote in agreement with FERC.
The Federal Power Act allows FERC to recommend that the federal government take over, maintain and operate hydroelectric facilities after a license expires. “North Carolina does not and cannot identify a single case, statute or regulation to provide authority” for the federal government to transfer a seized project to a state government, Sentelle said. The judge noted that the state could have filed its own application for the project with FERC, negotiated a sale or initiated a condemnation proceeding of the project.
“Thriftiness and political pressure do not create a legal basis for federal recapture when its sole purpose is transferring the hydropower project to a state,” Sentelle said. “Indeed, none exists.”
North Carolina also challenged FERC’s approval of Cube Yadkin Generation’s $243 million purchase of the Yadkin Project in 2017, a challenge the commission also denied. The state alleged that Alcoa misled the state and other potential applicants for the project into thinking the company intended to continue operating Badin Works.
“Alcoa disclosed the curtailment of industrial production at Badin Works every step of the way, from its initial filing of intent to relicense, through its various correspondences with FERC, to the license application itself,” Sentelle said. “The loss of jobs from the closure of Badin Works is a dark and menacing cloud that hangs over the state of North Carolina. However, Alcoa did not conceal this impending squall and, thus, FERC did not err by denying North Carolina’s request to reopen licensing.”
The state attorney general’s office could not be reached for comment Monday because of the Martin Luther King Jr. Day holiday.
Though it is no longer the owner of the Yadkin Project, Alcoa still owns the land bordering the river, though it agreed to sell it as part of FERC’s approval of its relicense application. Local conservation group Three Rivers Land Trust is raising money to purchase an initial 2,310 acres of land by September so it will be granted an additional two years to purchase the remaining 2,390 acres.
FERC last week authorized both ITC Midwest and American Transmission Co. to recover all of their “prudently incurred costs” if the Cardinal-Hickory Creek project is abandoned or canceled for reasons beyond their control (ER19-355, ER19-360). Both companies filed for the rate incentive in November.
“We agree that the project faces certain regulatory, environmental and siting risks that are beyond the control of management and which could lead to abandonment of the project,” FERC said.
Cardinal-Hickory Creek line route | ATC
The commission said the $500 million project meets the criteria for the abandoned plant incentive because it had been found to enhance reliability and reduce congestion through MISO’s annual Transmission Expansion Plan.
One of MISO’s 2011 multi-value projects, the 345-kV line will consist of 102 to 120 miles of transmission from southern Wisconsin to eastern Iowa with multiple substation updates. The project is intended to transport wind power and lessen the burden on existing 345-kV and 138-kV lines in the area.
Construction of the line is currently in a holding pattern because of the ongoing partial federal government shutdown. The Wisconsin State Journal reported that six public meetings Jan. 22-29 regarding the line’s environmental impact have been canceled. The U.S. Department of Agriculture’s Rural Utility Service had been conducting an environmental review of the line before the shutdown. The meetings cannot be rescheduled until the government reopens.
Stakeholders Approve Streamlined Generator Interconnection Process
NEW ORLEANS — SPP stakeholders last week unanimously approved changes to the RTO’s generator interconnection process to simplify what had become a burdensome process involving the submission of repetitive data.
The Market and Operations Policy Committee approved a revision request (RR335) that adopts a three-stage study process: thermal and voltage analysis, stability analysis, and facilities study. The RR also changes the amount and timing of security deposits, publishes study models earlier in the process, and allows penalty-free withdrawals when costs increase above certain thresholds.
The task force said the new process will be easier for SPP to administer and for users to understand and navigate, with most upgrades being identified in the first stage. That would allow transmission customers to make an informed decision before committing to a lengthy and costly stability analysis.
The group said reducing the number of withdrawal requests late in the process would reduce restudies and uncertainty. Customers will be able to withdraw after the second of three decision points without incurring financial penalties when assigned upgrade costs increase by at least 35% and $15,000/MW between study stages.
The measure was brought forward by the Regional Tariff Working Group (RTWG), which took up the issue following last year’s dissolution of the Generator Interconnection Improvement Task Force (GIITF). The GIITF was created in 2016 to identify improvements in SPP’s transmission study process, which had become clogged with more than 62 GW of interconnection requests. (See SPP Generator Interconnection Group Wraps up Work.)
Proposed GI study process (3-stage) | SPP
20-Year RR Tabled
The committee tabled a second RR (RR334) that would add the 20-year Integrated Transmission Planning (ITP) economic-only assessment as an eligible study in determining whether projects are eligible to become competitive upgrades.
SPP has not previously issued notifications to construct (NTCs) based on long-range studies, although it is not precluded. Evergy opposed the RR within the RTWG, saying the 20-year assessment is intended to be indicative and that no NTCs should be issued without additional analysis in the annual ITP study. To do so would mean SPP was issuing an NTC for a project without studying its reliability impact on the system, Evergy said.
The MOPC asked staff to return the RR when its language is clarified to make it clear the 20-year-assessment would not result in NTCs being issued without additional study to evaluate its reliability impact and the year the project is needed.
HITT Educates MOPC on its Progress, Learnings
The Holistic Integrated Tariff Team (HITT) conducted an education session before the MOPC meeting formally began, briefing stakeholders on its work and issuing a last request for additional information. The team has been meeting since April on a plethora of presentations and proposals.
SPP General Counsel Paul Suskie, who serves as the HITT’s staff secretary, told the committee that a final report will be issued to the Board of Directors in April. The report will include details on which stakeholder groups will be tasked with working out the specifics in the Tariff language, policies, implementation and timelines.
“It’s become obvious to HITT members that technology is rapidly changing and rapidly impacting our industry,” Suskie said. “We always talk about turning the aircraft carrier in this industry. Technology is changing how rapidly the aircraft carrier is turning.”
Nebraska Public Power District’s Tom Kent, who chairs the HITT, said the group has narrowed its high-level policy recommendations to four subjects:
Aligning SPP’s transmission planning processes and stakeholders’ resource adequacy needs with the Integrated Marketplace and Tariff requirements;
Reviewing of existing transmission cost allocation methodologies;
Holistically understanding of the Integrated Marketplace and essential reliability services in the face of the changing generation mix and new technologies; and
Facilitating load-growth opportunities in the footprint.
A stakeholder panel on transmission planning and resource adequacy noted “traditional” planning processes have focused on the reliable delivery of firm capacity resources, while energy markets, public policy initiatives and other incentives have led to the increased development of
Supply Adequacy Working Group Chair Brad Hans of the Municipal Energy Agency of Nebraska said his group is working to ensure SPP maintains the “right type of resources.”
“How much variable energy resources do you allow in the footprint?” he asked. “The way we should look at it is, ‘How much dispatchable resources do you need to keep at all times from a reliability perspective?’”
Arkansas Public Service Commission staffer Cindy Ireland summarized a review of SPP’s cost allocation methodologies by saying, “At the end of the day, load is going to pay.” A member of the Cost Allocation Working Group, Ireland said the group is discussing which is the appropriate load to pay.
The market panel said SPP is considering a ramping product, but as staff’s Gary Cate said, pointing to MISO’s and CAISO’s products and ISO-NE’s exploration of the same, “We’re not breaking new ground with a ramp product.”
1A Task Force’s Fee Schedules OK’d
The MOPC approved four Schedule 1A rate schedules, an effort to recover SPP’s costs from the users of its services.
Members backed a recommendation from the Schedule 1A Task Force, commissioned last July, for:
Planning, scheduling and dispatch;
Transmission congestion rights administration;
Market clearing; and
Markets facilitation.
Evergy’s John Olsen said the group will now draft Tariff language and a white paper, which will be sent through the RTWG. He said the Tariff language would come back to the MOPC in April or July.
Olsen said the group spent much of its time discussing energy billing determinants and debated virtual transactions. He said one concern for the task force is avoiding the creation of discriminatory treatment.
The group has yet to include energy transactions in the rate design.
The measure was opposed by Oklahoma Gas & Electric Services and BP Wind Energy North America. ITC Holdings and Tenaska Power Services abstained.
Proposed new rate structure | SPP
MWG Withdraws 2 Revision Requests
The MOPC approved the Market Working Group’s recommendations to withdraw an RR related to the timing of real-time balancing market submittals. RR329 would have modified the market user interface (MUI) to allow market participants to “systematically” submit certain offer parameters on a continual basis. As designed, the MUI locks out users less than 30 minutes before each operating hour.
SPP’s Market Monitoring Unit said it could not support the RR because it doesn’t include language requiring generators’ parameters be based on physical limitations. The Monitor said it believes that physical parameters included in a resource offer should be based on “true, accurate and verifiable physical capabilities or limitations of the resource.”
The MWG said it was also withdrawing RR337, which calls for the MMU to file an annual review of frequently constrained areas (FCAs). FERC’s acceptance in December of SPP’s revised plan for a timely update of FCAs eliminated the requirement for an annual update. (See “FERC Approves SPP’s Streamlined FCA Process,” SPP FERC Briefs: FCAs, NPPD Complaint, Refunds.)
Staff Reports: MISO Event, Western RC Services
Staff told stakeholders that a FERC inquiry into last year’s emergency event with MISO is expected to be completed by early in the second quarter.
In January, severe cold weather and generation shortfalls in MISO South led MISO to exceed its regional dispatch limit on transfers between its northern and southern footprints across SPP’s system. MISO made emergency energy purchases from Southern Co. before operations returned to normal.
The two RTOs have been working since then to improve coordination across their seam.
Operations Vice President Bruce Rew told stakeholders that SPP’s effort to provide reliability coordination services in the Western Interconnection remains on track to be certified in August. He said the RTO has added about half of the necessary staff and expanded some of its models to incorporate Western entities.
SPP has signed RC contracts with about 12% of Western Interconnection load. It is scheduled to go live with its RC services Dec. 3.
Staff reported that the 2019 ITP process is off to a slow start with a couple of slipped milestones but said that won’t affect the downstream schedule. The study’s economic model and its balancing authority reliability power-flow models are scheduled to be completed in November.
The detailed project proposal window opened Jan. 8 and will close Feb. 6.
At the same time, the 2020 ITP process has just begun. Director of Transmission Planning Antoine Lucas requested stakeholder engagement, saying staff would soon be soliciting information for load and generation profiles.
MOPC Adapts to Leadership, Other Changes
The Jan. 15 MOPC meeting was the first in 18 years without SPP COO Carl Monroe serving as staff secretary. He was replaced by Lanny Nickell, SPP’s vice president of engineering.
“I guess we finally got it right enough, so we can let him step aside,” cracked board Chair Larry Altenbaumer.
The meeting was also the first that stakeholders could access over the Internet.
Staff and members also recognized outgoing MOPC Chair Paul Malone for his “passionate, devoted and conscientious service.” Malone is retiring from NPPD in February.
Among the several changes facing the committee is the newly delegated authority to approve Tariff- or criteria-related changes without sending them on to the board for final approval. Stakeholders can still appeal a MOPC decision to the board but must do so within a week of the decision.
The committee passed two such changes:
Its unanimous endorsement of the 2019 SPP Transmission Expansion Plan (STEP), which lists all transmission projects needed over a 20-year planning horizon. The plan consists of 568 upgrades totaling $5.2 billion and documents the completion of $779 million worth of upgrades and the issuance of 23 NTCs last year.
Its approval of East River Electric Power Cooperative’s sponsored upgrades of a new 115-kV line and a 115/69-kV transformer near Aberdeen, S.D. The project will be a creditable upgrade eligible for incremental long-term congestion rights or cost recovery through Attachment Z2.
Staff Withdraws 4 Mountain West Tariff Changes
The MOPC’s consent agenda included the withdrawal of four RRs related to SPP’s proposed integration of the Mountain West Transmission Group: MWG RR281, MWG RR282, MWG RR284 and MWG RR286.
The RRs were approved by the MWG in April 2018 but were rendered moot by the halt of integration efforts last year.
The 2020 ITP assessment scope’s approval was pulled from the consent agenda because of concerns over its age-based retirement of certain generating units. It was approved separately despite opposition from Southwestern Public Service and Xcel Energy Southwest Transmission.
The consent agenda’s unanimous approval also resulted in a charter revision for the Model Development Working Group, expanding its voting membership to “up to” 24, and in the Event Analysis Working Group’s (EAWG) dissolution. Created in 2017 to review major bulk electric system events, the EAWG was never called into action. Its responsibilities will now be picked up by other working groups.
Approved RRs included:
BPWG RR331: Clarifies and reorganizes interchange tagging business practices for denial of schedules and emergency tags.
MWG RR326: Updates expired language (replacing “bill statements” with “settlement determinant report”) and removes a redundant requirement to create documentation for a miscellaneous charge already included in the asset owner determinant report.
MWG RR341: Aligns the Integrated Marketplace protocols and Tariff to comply with FERC Order 745 by modifying how the net benefits test is calculated.
MWG RR342: Modifies attributes, definitions and names of determinants, and restructures a calculation to be consistent with existing calculations. The changes are necessary to implement automated contingency reserve deployment tests.
RTWG RR330: Changes non-firm daily service submissions to no later than 10 a.m. CT and closes the daily non-firm submission window when the non-firm hourly submission window opens, matching the release of unscheduled firm transmission service to the non-firm market.
TWG RR237: Removes duplicative or unnecessary language in the SPP criteria to make it consistent with NERC Standard TPL-001-4’s requirements and account for the differences between NERC’s requirements and SPP’s Tariff.
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
1. PJM Manuals (9:15-9:35)
Members will be asked to endorse the following manual changes:
C. Manual 14B: Regional Transmission Planning Process: Minor changes to ensure consistent terminology; revision to Section 1A on critical energy infrastructure information (CEII); Attachment C revisions concerning changes to load deliverability procedures; and updated generator and long-term deliverability procedures.
Transmission owners will compete with load interests and merchant transmission operators for stakeholder endorsement of proposed manual revisions to address end-of-life facilities in the PJM planning process.
American Municipal Power’s proposed changes to Manual 14B: Regional Transmission Planning Process, which were seconded by Old Dominion Electric Cooperative at the July 27, 2018, MRC meeting, will be considered the main motion. PJM’s proposed revisions, which were moved by FirstEnergy and seconded by Public Service Electric and Gas at the Dec. 20, 2018, MRC meeting, will be the first alternate motion. (See PJM MRC Briefs: Dec. 20, 2018.)
AMP would add language in section 1.5.4 to require sufficient information for stakeholders to replicate TOs’ results on the need for proposed supplemental projects. It also would strike the word “useful” in references to “end of useful life.”
PJM said its proposal provides additional transparency to the Regional Transmission Expansion Plan process and incorporates most of the AMP/ODEC-proposed changes along with input from TOs.
LS Power has proposed a friendly amendment to either proposal that would limit the ability of supplemental projects — which are developed by TOs based on their own criteria — to supplant competitively bid projects accepted by PJM to address regional reliability violations or other criteria.
The main motion will be voted first. If it fails, the alternate motion will be brought to a vote.
3. Energy Price Formation (10:30-11:30)
Members will be asked to endorse one of four packages of energy market rule changes from the Energy Price Formation Senior Task Force (EPFSTF). The Board of Managers told members last month that it will make a unilateral filing with FERC if members do not reach consensus on a package by Jan. 31.
The rule changes will affect shortage pricing; reserve products; synchronized reserves; secondary reserves; and the alignment of the day-ahead and real-time reserve markets.
PJM’s proposal would replace the current stepped operating reserve demand curve (ORDC) with a sloped curve; the first horizontal segment would represent the minimum reserve requirement, with the downward sloping curve based on the probability of reserves falling below the minimum reserve requirement (PBMRR) in real time based on uncertainties.
The D.C. Office of the People’s Counsel proposed a similar ORDC, except that the downward sloping curve would take into account the regulation requirement.
The Independent Market Monitor’s proposal would leave the ORDC unchanged and reduce the current two-step penalty factor ($850 and $300) with a single penalty factor equaling the safety net energy offer cap of $1,000/MWh. If PJM approves a cost-based offer above that price, the penalty factor could increase in $250/MWh increments to a maximum of $2,000/MWh.
The PJM proposal would increase the price for the initial horizontal segment of the curve to $2,000/MWh and replace the second step of the curve with a downward sloping segment valued at $2,000 times the PBMRR.
Calpine supports the PJM proposal except that it would eliminate PJM’s proposed transitional mechanism to the energy and ancillary services (E&AS) revenue offset. PJM proposed the transition to reflect expected changes in revenues in the determination of the net cost of new entry. (See Monitor Sees Problems with PJM Reserve Pricing Plan.)
Votes at the EPFSTF meeting Wednesday will determine the breadth of support for the proposals and how they will be considered at the MRC.
4. Incremental Capacity Transfer Rights Clarifications (11:30-11:45)
Members will be asked to endorse revisions to section 234.2 of the Tariff to require new service customers to request incremental capacity transfer rights (ICTRs) calculations during the facilities study phase. Customers can include up to three locational deliverability areas in the request.
Section 234.2 requires PJM to determine in the system impact study the increase in capacity emergency transfer limit resulting from an interconnection, merchant transmission facility or customer-funded upgrade.
The change is in response to a FERC order that found PJM had not been following section 234 for assigning ICTRs. PJM had clarified the procedure in Manual 14E, but FERC said it must also be added to the Tariff (EL18-183).
The MRC and MC will also be asked to endorse the changes on their first read so they can be filed with FERC by Jan. 31.
Members Committee
Consent Agenda (1:20-1:25)
Members will be asked to approve a revised definition of “on-site generators” in the market participation rules in the Tariff and Operating Agreement. The changes will affect distributed energy resources located behind a customer’s meter participating as demand response to reduce load and as generation to inject power.
The committee will be asked to approve a new mark-to-auction component for financial transmission rights credit requirements, a change prompted by the GreenHat Energy default.
Although a decline in market value can indicate increasing FTR risk, current rules do not provide for a collateral call when an FTR portfolio’s value is deteriorating.
Proposal G-1 would consider the difference between the FTR purchase price and most recent market price. It was endorsed by the MRC by acclamation, with one objection, in December. (See “FTR Collateral,” PJM Market Implementation Committee Briefs: Dec. 12, 2018.)
2. Energy Price Formation (1:40-2:40)
The committee will be asked to approve revisions to the energy and ancillary market rules to improve price formation. (See MRC item 3 above.)
3. Incremental Capacity Transfer Rights Clarifications (2:40-3:00)
Members will be asked to endorse revisions to section 234.2 of the Tariff to require new service customers to request ICTR calculations during the facilities study phase. (See MRC item 4 above.)
4. Opportunity Cost Calculator (3:00-3:30)
The committee will be asked to endorse revisions to Manual 15: Cost Development Guidelines governing generators’ use of the Monitor’s calculator as an alternative method of calculating energy market opportunity costs.
Members also will be asked to approve related revisions to Schedule 2 of the OA. (See “Opportunity Cost Calculator Vote Deferred,” PJM MRC/MC Briefs: Oct. 25, 2018.)
