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.)
FERC last week refused to budge on its decision to revoke the license of a small hydropower plant in Michigan over the owner’s longstanding noncompliance with safety measures.
The commission on Jan. 17 denied rehearing on Boyce Hydro possibly restarting operations at the 4.8-MW Edenville Dam, which was ordered closed in October over insufficient spillway capacity. (See FERC Upholds Michigan Dam Closure over Safety Fears.)
Edenville Dam spillway
“In multiple orders, the commission has set forth a history, going back to 2004, of Boyce Hydro’s failure to comply with its license for the Edenville project, the commission’s regulations and commission orders. Of particular concern has been the project’s inability to pass the probable maximum flood due to inadequate spillway capacity,” FERC repeated in its latest order on the issue (P-10808-064).
Boyce and the Sanford Lake Association sought rehearing of FERC’s decision to revoke the license, arguing the commission didn’t consider how the revocation could negatively affect a potential transfer of the license. Acquiring a new license, the two said, is an expensive, uncertain and drawn-out process. In addition to the Sanford Lake Association, the Wixom Lake Association and the Saginaw Chippewa Tribe have expressed interest in taking over ownership of the dam.
Boyce said that a new license to replace the 20-year-old license “would require environmental, recreational and other study information required in contemporary licenses.” It pointed out that obtaining a new license could be further complicated by the dam’s inadequate spillway capacity and the fact that the water quality on the original license had been waived.
But FERC wasn’t swayed: “It is not in the public interest for the commission to delay action addressing a licensee’s long history of noncompliance with dam safety regulations out of concern that such action may affect the possibility (based mostly on speculation) that some third party might accept transfer of the license and promptly bring the project into compliance.”
FERC said the process of acquiring a new hydroelectric license can be expedited with certain procedural requirements waived. The commission also said the lake associations’ meetings over the dam are too preliminary in nature to persuade it to change the license revocation into a license suspension, as requested by the Sanford association. The meetings, FERC said, “do not provide any certainty as when the Edenville project’s public safety and environmental deficiencies would be remedied.”
The commission reiterated that Boyce has been on notice that its noncompliance could lead to license revocation since “at least June 2017” and that the company and interested buyers have had “ample opportunity to investigate the option of license transfer.” It added that it received no indication that a third party was ready to assume the project. Further, Boyce never provided the commission with a timetable for increasing spillway capacity when “continuing required work would have been wise,” FERC said.
Boyce and the Sanford Lake Association also argued that the license revocation could negatively impact public safety because, absent income from electricity generation, the spillways won’t be repaired or upgraded. FERC said dam safety enforcement will fall to the Michigan Department of Environmental Quality, which can instigate civil action.
The commission also rebuffed the argument that its order would disrupt a state-mandated lake level, saying nothing in its license revocation is stopping Boyce or a third party from operating the project as a non-generating facility to maintain water levels.
“For over 14 years, the commission has gone to great lengths to compel compliance with the license requirements, and Boyce Hydro has delayed, disregarded its responsibility and claimed that it was not financially capable of meeting such requirements. Meanwhile, Boyce Hydro continued to benefit from the revenues generated by the project,” FERC said. “There is no evidence that allowing Boyce Hydro to maintain its project license will result in a different outcome or that the longstanding compliance issues will be remedied.”
Finally, the commission noted that Boyce failed to put money into escrow to fund necessary spillway improvements, as it promised in 2008. The company also never followed up on a promise to provide FERC with a list of its financial assets.
“A licensee’s lack of financial capacity does not excuse years of noncompliance with important license conditions,” FERC said.
SACRAMENTO, Calif. — CAISO market participants and companies that do business with Pacific Gas and Electric could end up paying a hefty price for the giant utility’s financial collapse.
Other CAISO members are worried that PG&E, which plans to file for bankruptcy on Jan. 29, could default on its payments to the ISO and the Western Energy Imbalance Market, leaving other members to foot the bill.
PG&E’s financial collapse is being managed from its headquarters at 77 Beale St. in San Francisco.
PG&E’s troubles also have fueled talk of a wide-ranging ripple effect, particularly regarding the renewable power generators from which the utility has contracted to buy billions of dollars worth of electricity.
CAISO has tried to relieve members’ concerns about a potential default, saying PG&E has enough collateral to cover its debts and future payments.
“The California ISO has received inquiries relating to the financial status of Pacific Gas and Electric Co. in light of recent media reports,” it said in a Jan. 11 market notice. “The ISO wants to assure market participants that PG&E has posted collateral with the ISO to cover its outstanding and upcoming obligations.”
But one market participant, a major player in the West, told RTO Insider it could end up paying hundreds of thousands of dollars a month to the ISO if PG&E defaults. The representative spoke only on the condition of the utility’s anonymity.
In response to an inquiry from RTO Insider, the ISO said it couldn’t reveal the amount or type of PG&E’s collateral, calling the information confidential. CAISO officials declined an interview request. “We have shared all we can on this subject,” an ISO spokeswoman wrote in an email.
PG&E did not respond to a request for comment.
Scott Miller, executive director of the Western Power Trading Forum (WPTF), said he thought there was little chance PG&E would default on its CAISO payments.
“When it comes to CAISO charges, you’ve got to be concerned,” Miller said. “But because it’s necessary for the grid to operate, and PG&E wants to emerge from bankruptcy as a going concern … I suspect that would be the last thing they wouldn’t pay.
“Defaulting on the CAISO charges could cause all sorts of financial shortfalls in CAISO, and that has reliability implications,” he added. “I just don’t think PG&E would not pay its CAISO charges.”
Scott Miller, executive director of the Western Power Trading Forum, says PG&E is unlikely to default on its CAISO obligations. | WPTF
Miller served until 2017 as a senior market adviser in FERC’s Office of Energy Policy and Innovation where he worked on RTO credit reforms. He said RTOs and ISOs have assumed roles as financial clearinghouses, for which they’re not ideally suited.
It could cast some doubt on whether CAISO can adequately assess PG&E’s creditworthiness, he said.
PJM has been scrambling to strengthen its credit policies following the collapse of GreenHat Energy, whose default is expected to cost members more than $100 million.
“This is an area that’s problematic for RTOs,” Miller said. “They’re extending credit and taking risk. That’s not in their traditional wheelhouse. They’re not in as strong a position as a clearinghouse normally is for assessing credit risk.”
Ripple Effect
PG&E, California’s largest utility, has seen its fortunes fall since the catastrophic wildfires of 2017 and 2018, for which it has received much of the blame. That blame was based on state investigations in some cases, and circumstantial evidence mixed with public distrust in others.
The utility’s stock price plummeted from more than $70/share prior to the 2017 fires in Northern California’s prized wine country to slightly more than $6/share following November’s Camp Fire, the deadliest in state history. The roughly 90% collapse in PG&E’s stock price represented a $33 billion loss in market value.
The utility announced Jan. 14 it would file for bankruptcy by the end of the month because it was facing at least $30 billion in wildfire liability. At least 750 lawsuits have been filed against it on behalf of nearly 5,600 plaintiffs, it said. (See PG&E Files Bankruptcy, as CEO Steps Down.)
On Wednesday, S&P Global Ratings further downgraded PG&E’s credit rating from CC to D status, the lowest grade used by the major ratings firms. The downgrade was based on PG&E missing a $21.6 million interest payment on $800 million in senior notes.
“We do not expect the company to make this payment during the [30-day] grace period given the company’s announcement that it expects to file for bankruptcy protection and commence a reorganization under Chapter 11 of the U.S. Bankruptcy Code,” S&P said in a news release.
The fallout from PG&E’s bankruptcy announcement is already beginning to hit its renewable suppliers.
“PG&E is the biggest utility in the biggest market in the West. It’s not just the RTO activities that people are concerned about,” Miller said. “It’s the bilateral contracts they’ve got for resource adequacy — renewable contracts, storage contracts, things like that.”
One generator, the 550-MW Topaz Solar Farm owned by Berkshire Hathaway Energy, recently had its credit rating downgraded to junk status — the same as PG&E’s — because it had signed an exclusive 25-year power purchase agreement with the utility, and analysts said it might not get paid. (See PG&E’s Credit Woes Spread, Worrying CAISO Members.) Also downgraded was NextEra Energy’s 250-MW Genesis concentrating solar thermal plant, built in 2007. PG&E is its sole purchaser.
PG&E reported to FERC in its 2017 Form 1 filing that it had signed about $40 billion in PPAs covering 2019 to 2043, including agreements to buy approximately $34.5 billion in renewable energy such as wind and solar.
In 2017, PG&E generated about 53% of its 61,397 GWh in bundled retail sales according to a security filing, with purchases making up the remainder. PPAs represented $42 billion of the company’s $78.8 billion in contractual commitments as of the end of 2017.
Once in bankruptcy, PG&E could attempt to cancel or renegotiate these contracts. Analysts say generators with above-market contracts signed years ago will be most vulnerable to having their prices reduced.
Credit Suisse analysts estimate that PG&E could save $2.2 billion a year by renegotiating its renewable contracts to current market prices, The New York Times reported. The analysts said PG&E is paying Consolidated Edison solar plants an average of $197/MWh, almost eight times the $25 to $30/MWh new solar plants are charging.
Jan Smutny-Jones, CEO of the Independent Energy Producers Association, said in an interview that his organization will push PG&E to honor its commitments to generators.
IEP sent a letter to California’s political leaders Jan. 15 urging them “to seek immediate assurance from PG&E that its energy-supplier contracts will be affirmed and that generation interconnection deposits supporting new renewable energy projects will be protected and used to develop the transmission upgrades necessary to interconnect those projects.”
Evaluating Exposure
While CAISO has said little publicly about the potential effects of PG&E’s meltdown, conversations are going on behind the scenes as market participants try to sort out their exposure.
The market participant that spoke to RTO Insider on background, for example, said it had been struggling to determine how much collateral PG&E had posted with CAISO and whether other participants would be obligated to pay its share and for how long.
Another concern is the tens of millions of dollars in grid management charges (GMCs) that PG&E pays to CAISO each year, for which other members also could find themselves on the hook. In 2017, PG&E paid $51 million to CAISO in GMCs. Those grid fees fund the ISO’s fixed revenue requirement and any default must be covered by other participants.
Fallout from a PG&E default could spread to the Western EIM as well. Because the EIM falls under CAISO’s Tariff, EIM members have an obligation to cover defaults, similar to other CAISO members, in proportion to their market activity. Their voluntary day-to-day participation in the EIM, however, could allow them to reduce transactions to minimize exposure, and even ultimately withdraw from the market.
CAISO members whose assets are controlled by the ISO have no such recourse. They must cover a defaulter’s payments under the ISO’s tariff provisions once the defaulter has exhausted its collateral or “financial security.”
The ISO’s tariff provisions on creditworthiness require participants without unsecured credit to post collateral in the form of “an irrevocable and unconditional letter of credit issued by a bank or financial institution,” a prepayment to the ISO or a combination of the two. It remains unknown what kind of security PG&E posted.
CAISO requires financial security sufficient to cover a participant’s “estimated aggregate liability,” which represents all unpaid obligations plus five trading days, providing the ISO a cushion before the participant responds to a call for additional collateral within the required two business days. Posted collateral must be sufficient to cover other liabilities as well, such as a congestion revenue rights portfolio that has gone into the red.
In a situation where a market participant defaults on its payments to the ISO and has no collateral left, section 11:29:17 of the CAISO Tariff lays out a process by which the ISO can spread the costs to other members proportionally based on their market activity. Section 29.11 of the Tariff stipulates that those provisions also apply to EIM members.
Another potential consequence of PG&E’s bankruptcy: CAISO’s own financial position could be adversely affected.
In awarding the ISO an A+ credit rating in 2016, Fitch Ratings said one of the key factors it considered was the “solid credit profiles of California’s three largest investor-owned utilities.”
That was before S&P and Moody’s Investors Service stripped PG&E of its investment-grade credit status, downgrading it to “junk” because of its dire financial outlook from the fires and the fact that California politicians weren’t riding to its rescue, as some had expected.
S&P still gave CAISO an A+ credit rating as of Thursday. CAISO’s current annual debt service costs of $16.9 million are well below the 2006 peak of $80 million, and the 2009 construction of the ISO’s Folsom headquarters accounts for most of its $181 million (as of 2017) in long-term debt.
‘Out the Window’
State Assemblyman Chris Holden, chairman of the Utilities and Energy Committee, who co-authored last year’s Senate Bill 901 to aid PG&E, said he wasn’t inclined to do more right away.
SB 901 contained provisions allowing the state’s IOUs to issue long-term bonds, with approval of the California Public Utilities Commission, to cover costs of the 2017 fires. Holden had said he intended to offer legislation to make the bill’s provisions applicable to the Camp Fire and other 2018 fires. A PG&E bankruptcy wouldn’t be good for the state or its ratepayers, he said.
Holden recently backed away from that effort, telling the San Francisco Chronicle, “Our purpose was to keep PG&E from going into bankruptcy, but that’s out the window now. Now the courts are getting out in front.”
