SPP staff last week said they considered several seams-related projects with MISO in their 2020 Integrated Transmission Planning (ITP) assessment but eventually declined to pursue them over differing methodologies in calculating benefits and costs.
“Rest assured we’re going to continue to look at these areas in the future,” Kirk Hall told the Seams Steering Committee during its Oct. 7 meeting, referring to three 345-kV projects along the Nebraska-Iowa border.
“MISO and SPP staff continue to work on understanding the cost differences,” Hall said. “Hopefully, we’ll come back with something that is agreeable to all parties.”
Hall shared a near-final version of the ITP assessment with the SSC. Staff identified 54 projects in the final portfolio, which includes 92 miles of 345-kV transmission lines and 141 miles of rebuilt high-voltage infrastructure. It estimated $532 million of engineering and construction costs but projected a 4.0-5.2-to-1 benefit-to-cost ratio.
The 2020 ITP takes a 10-year look at system reliability and economic needs. Staff spent more than two years evaluating more than 2,200 solutions, and said the projects will solve 163 system needs, help levelized market prices, improve congestion hedging and facilitate access to low-cost energy.
The ITP assessment will be taken to SPP stakeholders and the Board of Directors later this month for their approval.
Neil Robertson, SPP’s interregional relations senior engineer, said the grid operator remains “committed to coordinating” with MISO. The RTOs once again failed to agree on an interregional project during their fourth coordinated system plan (CSP) study but have since agreed to combine forces on a year-long transmission study to identify “comprehensive, cost-effective and efficient upgrades.” (See MISO, SPP to Conduct Targeted Transmission Study.)
“SPP will … work with MISO and determine how we would rectify costs differences if we decided to factor in whether a project can be recommended or not,” Robertson said.
He said SPP and MISO analyzed 10 needs in their CSP, but no solutions met “fundamental requirements.”
Robertson also discussed the final report of SPP’s joint CSP with Associated Electric Cooperative Inc. The entities will combine forces on what would be the RTO’s first competitive project under FERC Order 1000. (See FERC Approves SPP-AECI Competitive Project.)
M2M Settlements Again Favor SPP
Market-to-market (M2M) settlements once again flowed in SPP’s favor during August, staff told the committee, resulting in a $1.1 million accrual for the grid operator. Temporary and permanent flowgates were binding for 725 hours during the month.
SPP’s market-to-market settlements with MISO are approaching $95 million. | SPP
SPP has now accrued $93.82 million in M2M settlements since it began the process with MISO in March 2015.
August marked the 10th time in 11 months, and the 49th time in 66 months, that settlements have ended up in SPP’s favor.
NERC is seeking comments through 8 p.m. Nov. 20 on proposed changes to SERC Reliability Corporation’s Regional Reliability Standards Development Procedure (RSDP), stemming from recent changes to the regional entity’s executive structure.
Each RE files an RSDP with NERC to “define the steps in that region’s process for developing, reaffirming and withdrawing its regional reliability standards” and to ensure that regional standards align with continent-wide standards approved by FERC and its Canadian and Mexican counterparts. RSDPs must be reviewed and submitted to NERC every five years — or earlier if the RE’s board feels revisions might be needed.
SERC headquarters in Charlotte, N.C. | SERC
SERC’s current RSDP was approved by the RE’s Board of Directors in October 2017 during its five-year review and accepted by NERC the following year. This revision, which comes about two years before the regularly scheduled review, is a relatively minor update intended to bring the RSDP in line with SERC’s updated executive structure as described in the RE’s revised bylaws approved by FERC in July. (See FERC Approves SERC’s Bylaw Changes.)
Changes to be implemented under the new bylaws include changing the Board Compliance Committee into a Board Risk Committee, transforming SERC’s Board of Directors into a hybrid board comprising both sector representatives and independent directors and eliminating the use of alternates and proxies for directors and independent directors. The updated RSDP reflects these changes by removing references to Board representatives and alternates and replacing references to the SERC Executive Committee with SERC Board of Directors.
In addition, the new document replaces references to the former executive committees of SERC’s technical committees to reflect their unification into a single Operations Planning and Security Executive Committee, and revises abbreviations throughout the RSDP to ensure internal consistency. The updates are planned to take effect Jan. 1, 2021, along with the new bylaws.
Openness, Balance Among Commenting Criteria
Industry stakeholders are being asked to comment on whether SERC’s updates meet NERC’s requirements for all regional RSDPs. Those requirements include the following:
Openness — The RSDP must allow any person or entity that is “directly and materially affected by the reliability of the bulk power system within the regional entity” to participate in the reliability standard approval process.
Inclusivity — Any person or entity with a direct and material interest must be permitted to express and justify an opinion, have that position considered and appeal through an established process in the case of an adverse decision.
Balance — Regional RSDPs must have a balance of interest and not be dominated by any two interest categories. No single interest category can be allowed to defeat a matter.
Due process — Standards development processes must provide reasonable notice and opportunity for public comment, including, at minimum, public notice of the intent to develop a standard, a comment period on the proposed standard, due consideration of comments and the opportunity for stakeholder ballots.
Transparency — All actions and materials relating to standards development must be transparent, and members of the public must be notified and allowed to attend all standards development meetings.
Following the comment period, SERC will submit the revised RSDP for approval by NERC’s Board of Trustees, most likely at its meeting in February 2021. Earlier this year, the Board accepted the Northeast Power Coordinating Council’s revisions to its own regional standard processes manual, aimed at clarifying outdated language and establishing closer alignment with NERC’s standard development process. (See “Budget, ROP, Standards Actions,” NERC Board of Trustees/MRC Briefs: Aug. 20, 2020.)
The Alliance for Clean Energy New York (ACE NY) on Tuesday drew 162 people to a virtual meeting to hear solar developers, industry experts and a NYISO official discuss projects that pair solar energy with energy storage.
Bill Acker, NY-BEST | ACE NY
Timing is crucial, and pairing energy storage with renewables allows the energy to move out of congested pockets, said Bill Acker, executive director of the New York Battery and Energy Storage Technology Consortium (NY-BEST).
“Instead of moving the energy at rush hour, you move the energy off of rush hour and you have what some people call virtual transmission,” Acker said. “Even beyond congestion, you have the situation when you get to very high renewables on the grid, where you literally have over-generation; even if you had the transmission, you wouldn’t be able to use the energy. Again, shifting the time allows you to use the energy.”
Because renewable energy projects paired with storage are proving popular with developers, NYISO in July decided to speed up its hybrid modeling capability, aiming to complete the enhancement in 2021. (See “Exciting Times,” Overheard at NY-BEST’s 10th Annual Meeting.)
Following is some of what we heard at the meeting.
Solar and Wind Benefit
“Storage is increasingly an area of focus for us; it is going to be paired with solar in all forms,” said David Gahl, senior director of state affairs in the Northeast for Solar Energy Industries Association.
In 2019, storage was paired with 5% of solar, “but we’re expecting that number to increase dramatically by 2025. In the distributed space, 25% of all behind-the-meter solar will be paired with storage,” Gahl said.
The growth is being driven in part by the eligibility of hybrids for the investment tax credit and by state goals, Gahl said. “In the utility-scale space … solar is increasingly paired with storage resources, with over 8 GW of commissioned projects that include storage right now. That represents nearly one in five of the contracted projects out there,” he said.
Clockwise from top left: Michael DeSocio, NYISO; Pete Fuller, Autumn Lane Energy Consulting; Anne Reynolds, ACE NY; Bill Acker, NY-BEST; and John Brodbeck, EDP Renewables. | ACE NY
New York’s solar-plus-storage market is being driven by the Climate Leadership and Community Protection Act, which set targets of getting 70% of the state’s electricity from renewables, and deploying 3 GW of energy storage and 6 GW of distributed solar, by 2030. The Public Service Commission laid out the state’s storage deployment policy in a December 2018 order, since updated (18-E-0130).
The New York State Energy Research and Development Authority is working to meet the goals via three pathways: state-subsidized incentives, contracts with the state’s investor-owned utilities and pairing a renewable energy certificate bid with storage, Gahl said. (See NY Utilities, Developers Tweak Storage Procurement Terms.)
In addition to providing the opportunity for more ancillary services, storage makes use of the spilled or “clipped” energy, adds duration and allows discharge at times better suited for the grid or the economics of the unit, said John Brodbeck, senior manager of transmission at EDP Renewables North America. With approximately 700 MW operating in New York, it is the largest owner of wind generation in the state.
“As a wind generator, we’ve been able to reg down for a while. To be able to reg up would be a good thing,” said Brodbeck, referring to ancillary services that help maintain the grid’s frequency. “There’s plenty of problems though … interconnection issues, modeling issues, how does it operate within the market and metering issues.”
NYISO was “pretty swift” to act on paired storage, and the stakeholder discussions quickly came to the concept of co-located storage resources (CSR), which is the simplest form of a hybrid unit: essentially two separate units at the same site, he said.
“You can get some ancillary services from the storage side, and the intermittent [resource] can charge the storage resource, and those are good things,” Brodbeck said. “The whole AC-coupled, DC-coupled issue seems to have been resolved nicely in NYISO,” with the ISO allowing both AC and DC coupling configurations between intermittent and storage resources. “The current state of the rules for CSR is it does allow a single interconnection request, so we don’t need to have multiple interconnection requests in the queue or in the class year, and the injection can be sized to less than the total electrical capability of the unit, which allows some additional flexibility.” (See Hybrid Resource Developers Ask for Uniform Rules.)
“With 700 MW of wind, our plan is that at some point in the future, we’d be adding storage to most of those sites,” Brodbeck said. “Many renewable sites, especially solar sites, are going to be wanting storage either as part of the original design or added on later. … I think you’ll see storage being added to a large number of units. Our concerns are about having to go back and getting it resized for interconnection, making sure that interconnection plan can be done expeditiously to get online quickly.”
A More Complicated Grid
Pete Fuller, Autumn Lane Energy | ACE NY
The evolving grid is going to be much more complicated than the old one-way power flows of the past, said Pete Fuller, principal of Autumn Lane Energy Consulting.
“You’ve got rooftop solar, vehicle-to-grid applications, microgrids, solar, wind, storage, hybrids — you’ve got a lot more things going on out on the grid that are separate and distinct from those big central power plants,” Fuller said. “As I think about hybrids, the real goal here is to create something through co-located or otherwise aggregated resources that somehow is greater than the sum of the parts. It creates additional value, certainly for the developer owner, because that’s what generates the investment and the interest, but also creates additional value for the grid.”
Michael DeSocio, NYISO | ACE NY
Michael DeSocio, director of market design at NYISO, said that “the energy storage rules that went commercial at the end of August are technology-agnostic.”
The ISO’s new rules focused on storage technologies that are dispatchable, which varies depending on the capabilities of the technology. For example, “if compressed air can inject and withdraw without needing to change state — in other words go offline for a little bit to change the state of its compressors to do that — it could be an ESR [energy storage resource],” DeSocio said.
The model does not exist in the market today for compressed air that needs to go offline between injection and withdrawals, he said.
“It’s something that we’ve thought about building as part of the ESR model but ultimately put aside given that we don’t have any projects in the queue for any of those technologies,” DeSocio said. “We do have a model for limited energy storage resources that’s been around since 2009, which allows flywheels and smaller batteries to provide regulation service. … When we talk about hybrid resources and the co-located model, we’re focused on energy storage that is dispatchable and can provide energy as well as resources that are dispatchable.”
A report on the causes of California’s August blackouts details for the first time the role that convergence bidding played in masking tight supply and contends that constrained transmission prevented much needed imports from reaching the state.
The 107-page report to Gov. Gavin Newsom by CAISO, the California Public Utilities Commission and the state Energy Commission blames previously discussed causes, including extreme heat induced by climate change and inadequate resource planning. And it expands on the allegation, mentioned in passing at recent CAISO meetings, that load-serving entities failed to anticipate their needs when scheduling in the day-ahead market.
“We have identified several factors that, in combination, led to the need for the CAISO to direct utilities in the CAISO footprint to trigger rotating outages,” the organizations wrote. “There was no single root cause of the outages, but rather, a series of factors that all contributed to the emergency.”
The rolling blackouts were the first to sweep the state since the energy crisis of 2000-2001. Over two days, about 812,600 households — representing about 2.4 million people — lost power.
Outmoded RA Planning
In an expected finding, CAISO said the state was unprepared to meet the extreme Western heat wave of Aug. 14-19 and that resource planning now must assume there will be similar events caused by climate change.
During the mid-August “heat storm,” California experienced four out of the five hottest August days since the ISO and the CEC began tracking such data in 1985, the report said. The organizations use an average daily temperature composite to predict electricity consumption across the CAISO region.
“Current resource adequacy planning standards are based on a one-in-two peak weather demand plus a 15% [planning reserve margin] to account for changing conditions,” the report said.
The 2020 heat storm was a one-in-35-year event, the California Energy Commission said. | CEC
But the August heat wave was a one-in-35-year event “not anticipated in the planning and resource procurement time frame, which is necessarily an iterative, multiyear process.” The state needs more supply resources, including battery storage for wind and solar, and must use new planning criteria for long-term projections, it said.
The rolling blackouts were made worse by transmission constraints and other causes, but “it is unlikely that current RA planning levels would have avoided rotating outages” under the same conditions, even without those contributing factors, it said.
Constrained Supply
Import bids in the day-ahead market were 40 to 50% (2,600 to 3,400 MW) higher during the August energy emergency than typical RA requirements from imports in August, but the output couldn’t get where it need to go, the organizations said.
“Despite this robust level of import bids, transmission constraints ultimately limited the amount of physical transfer capability into the CAISO footprint,” the report said.
A major transmission line in the Pacific Northwest upstream from CAISO was on forced outage because of weather conditions, and the California Oregon Intertie (COI) was derated, the report said.
“The derate reduced the CAISO’s transfer capability by approximately 650 MW and caused congestion on usual import transmission paths across both COI and Nevada-Oregon Border,” it said. “In other words, more imports were available than could be physically delivered, and the total import level was less than the amount the CAISO typically receives.”
Under-scheduling
CAISO said LSE scheduling coordinators “collectively under-scheduled their demand for energy by 3,386 MW and 3,434 MW below the actual peak demand for Aug. 14 and 15, respectively.”
During the net peak — the hours after solar goes offline but demand remains high on hot days — LSEs under-scheduled demand by 1,792 MW for Aug. 14 and 3,219 MW for Aug. 15, the ISO reported. The blackouts on those days occurred in the net-peak hours.
“The under-scheduling of load by scheduling coordinators had the detrimental effect of not setting up the energy market appropriately to reflect the actual need on the system and subsequently signaling that more exports were ultimately supportable from internal resources,” the report said.
CAISO said its own peak forecasts were 825 MW below actual demand for Aug. 14 and 559 MW above actual demand for Aug. 15. Its forecasts for the net demand peak times were 511 MW and 632 MW above actual demand.
Constrained transmission into California exacerbated energy shortfalls during the rolling blackouts of Aug. 14-15, CAISO said.
But during the mid-August events, “it was difficult to pinpoint these contributing causes because processes that normally help set up the market masked the under-scheduling,” the report said.
One of the processes was convergence bidding, a financial hedge that some observers believed could have been used to game the market.
“As the name suggests, convergence bidding is intended to allow bidders to converge or moderate prices between the day-ahead and real-time markets,” the report said. “Under normal conditions, when there is sufficient supply, convergence bidding plays an important role in aligning loads and resources for the next day. However, during Aug. 14 and 15, under-scheduling of load and convergence bidding clearing net supply signaled that more exports were supportable.”
“Once this interplay was identified on Aug. 16 after observing the results for trade day Aug. 17, convergence bidding was temporarily suspended for Aug. 18 trade date through the Aug. 21 trade date,” it said.
During those days, when conditions remained much the same as Aug. 14-15, further blackouts were averted.
RUC Flaw
The report also delved into complications stemming from a flaw in CAISO’s residual unit commitment (RUC) process. The ISO runs the RUC after the day-ahead Integrated Forward Market (IFM) process to avoid real-time supply shortages in rare cases when LSEs under-schedule demand.
The report notes that inputs into the RUC process differ from the outputs of the IFM in three ways:
Load cleared in the IFM is replaced by CAISO’s own day-ahead forecast, which does not include exports.
Wind and solar schedules cleared in the IFM are replaced by CASO’s wind and solar forecasts.
Virtual supply and demand that cleared in the IFM’s convergence bidding market are removed.
The RUC itself consists of two passes: a scheduling run intended to address any unresolved market constraints based on “an intricate but prescribed set of relative priorities” for relaxing the constraint or curtailing schedules; and a pricing run to produce prices that align with both the $1,000/MWh bid cap and the scheduling run.
To ensure that schedules produced by the IFM are physically feasible, the RUC process enforces a power balance constraint to ensure that forecast load can be met in real time.
In 2014, CAISO implemented the Pricing Inconsistency Market Enhancement (PIME) to address inconsistencies between schedules and prices. PIME redirected both the IFM and the RUC to use pricing run results as the source of both prices and schedules.
“Through these RUC constraints, the CAISO determines what portion of the day-ahead schedules are physically feasible and which portion that market participants should tag when the E-Tag is submitted in the day-ahead,” the report said.
After the Aug. 14 and 15 blackout events, CAISO determined that rather than reducing the volume of infeasible exports scheduled in the IFM, the RUC pricing run instead relaxed the power balance constraint, compromising the ISO’s ability to meet actual load. But the ISO found that the RUC’s scheduling run (no longer used to set final schedules) would have relaxed the IFM’s scheduled exports before relaxing the power balance constraint.
As a result, CAISO said it stopped using the PIME functionality in its RUC process beginning Sept. 5, allowing it to use scheduling run results for RUC schedules rather than pricing run results.
FERC on Wednesday approved a cost-and-usage agreement between SPP and Associated Electric Cooperative Inc. (AECI) that could result in the RTO’s first competitive project under Order 1000 (ER20-2707, ER20-2708).
SPP’s Wolf Creek-Blackberry project (dotted line), connecting to the AECI system | SPP
The letter order accepted the terms and conditions governing the construction, ownership, operation and cost for the installation of 345-kV terminal equipment at AECI’s existing Blackberry substation, the endpoint for SPP’s 109-mile, 345-kV Wolf Creek-Blackberry transmission project. It also accepts Tariff revisions to include the substation’s construction costs in each SPP transmission owner’s respective annual transmission revenue requirement.
“We were glad to see that outcome,” Neil Robertson, SPP’s interregional relations senior engineer, said in breaking the news Wednesday morning to the Seams Steering Committee.
The Wolf Creek-Blackberry project is expected to cost $152 million. SPP members will fund the line according to load-ratio share. The RTO’s Board of Directors last month lifted a suspension on the project and authorized the Oversight Committee to create an industry expert panel (IEP) to evaluate responses to a request for proposals, which staff have since issued. (See “Board Lifts Suspension on Competitive Upgrade,” SPP Board of Directors/MC Briefs: Sept. 22, 2020.)
In its latest round of Critical Infrastructure Protection (CIP) audits, FERC noted registered entities have made significant progress in meeting or exceeding the reliability standards’ mandatory requirements.
However, the commission still noted several “potential compliance infractions” and other areas for improvement.
FERC’s “Lessons Learned from Commission-Led CIP Reliability Audits” report is based on audits carried out during the federal government’s 2020 fiscal year, which began on Oct. 1, 2019, and ended Sept. 30. The number of audits performed, which also involved staff from regional entities and NERC, was not disclosed in the report; the audited entities’ identities were also kept confidential.
FERC has been conducting CIP audits since FY 2016. Audit fieldwork includes data requests, webinars and teleconferences, and site visits to registered entities’ facilities. During site visits, audit staff interview utilities’ subject matter experts, along with employees and managers responsible for performing tasks within the audit scope; observe operating practices in real time; and examine entities’ “regulatory and corporate compliance culture.”
Recommendations up from Previous Report
This year’s report produced 12 lessons learned, intended to “help responsible entities improve their compliance with the CIP reliability standards and their overall cybersecurity posture.” The commission’s first report covered FY16 and FY17, and included 21 recommendations; the number of lessons learned dropped to 10 in the FY18 report and seven last year. (See FERC: Room for Improvement on CIP Compliance.)
Despite the rise in recommendations, FERC’s report emphasized that “most of the … processes and procedures adopted by the registered entities met the mandatory requirements” of the CIP standards. As a result, the lessons learned reflect “practices that could improve security but are not required by the [standards],” in addition to mandatory fixes to bring entities back in line with requirements.
The suggested improvements covered the following standards:
CIP-002-5.1a — Bulk electric system cyber system categorization
For CIP-002-5.1a, staff observed that some entities did not properly identify BES cyber assets; for example, in some cases, cyber assets such as switches and protocol converters were recorded as communication equipment. This is incorrect, as such equipment “may pose an impact … within 15 minutes of their misuse.”
Auditors also found some instances in which substation BES cyber systems that should have been considered medium-impact were instead recorded by utilities as low-impact because staff “did not properly consider” the effect that all the relevant equipment might have when operated collectively.
| FERC
Recommendations for CIP-004-6 include ensuring that electronic access to BES cyber system information is properly authorized and revoked, following auditors’ discoveries that several entities had not followed their procedures consistently. In some cases, access was granted verbally without filing the necessary documentation, while in others, the access of terminated employees was not deactivated by the end of the calendar day following their departure.
Improvements for physical security — covered by CIP-006-6 — include dedicated visitor logs at each physical access point, locking BES cyber systems’ server racks where possible and periodic inspections of physical security perimeters to ensure there are no unidentified physical access points. Consistent practices are also endorsed in the recommendations for CIP-007-6, which include periodic review of security patch management processes, as well as consolidating and centralizing password change procedures.
Under CIP-009-6, auditors noted that some entities “failed to update their backup and recover procedures in a timely manner,” for instance by failing to establish a new process following a critical event in violation of the standard’s requirement. Entities were also found to have neglected to “report any information to remediate and mitigate vulnerabilities identified in vulnerability assessments,” as mandated in CIP-010-2.
Finally, staff noted that several entities could not “demonstrate that they properly disposed of” substation devices removed from services as required by their asset reuse and disposal policies, and that others relied entirely on security controls provided by third-party vendors without verifying their sufficiency. Both issues could constitute a violation of information protection requirements in CIP-011-2.
In several places, staff also recommended that entities “consider the guidance” of the National Institute of Standards and Technology’s Security and Privacy Controls for Federal Information Systems and Organizations report. While implementing these recommendations would not contribute to compliance, they would enhance the culture of security among utility staff, they said.
Colorado cooperative Tri-State Generation and Transmission Association said Wednesday it will cut its rates by 8% by the end of 2023 and give members additional flexibility to provide their own power, addressing two of its members’ most frequent complaints.
CEO Duane Highley acknowledged during a press conference that members had asked for more leeway in self-supply options to increase their use of renewable energy, calling the actions a “green energy dividend.”
“It’s been lots of work, but the cooperatives have come together cooperatively to find ways to make this work for everyone,” Highley said, apparently unaware of his play on words. “We’ve all agreed this is a fair way to share costs.”
Highley was backed by two member representatives, Poudre Valley Rural Electric Association CEO Jeff Wadsworth and Southeast Colorado Power Association CEO Jack Johnston, and former Colorado Gov. Bill Ritter, director of the Center for the New Energy Economy.
Ritter lauded Tri-State for its Responsible Energy Plan, which the co-op unveiled in January with similar fanfare. The plan’s components include 50% renewable consumption by 2024, reduced emissions by closing coal plants in Colorado and New Mexico, and additional self-supply and local renewable energy flexibility for members. (See Tri-State to Retire 2 Coal Plants, Mine.)
“This was not an easy result to get to. None of this is easy,” Ritter said. “They’re living up to the commitments they made in the Responsible Energy Plan. We’re going to make a commitment to lower rates for the next few years. That is something I think we should all applaud.”
The announcement followed a meeting at which Tri-State’s Board of Directors approved the rate cut and the Contract Committee’s process to implement partial requirements contracts with its utility members.
“You typically don’t hear about electric utilities lowering rates, so we’re grateful to Tri State and board for this big lift,” Wadsworth said.
Tri-State’s members cover much of the Rocky Mountains. | Tri-State Generation and Transmission
Beginning with an “open season” nominating period in early 2021, utility members can transition to the new contracts by expressing their interest in shares of the 300-MW of system-wide self-supply capacity allocation. The open season capacity accounts for 10% of Tri-State’s system peak demand.
Members can self-supply up to 50% of their load requirements, subject to availability in the open season. This expands on the current 5% self-supply provision and a new community solar provision.
The 5% cap has frustrated Tri-State’s 42 utility members, some of whom are involved in regulatory litigation to leave the co-op. (See Tri-State, Delta Officially Part Ways.)
Tri-State has recently added three non-utility members, making it FERC-jurisdictional. The commission in March found Tri-State to be under its jurisdiction, a ruling it affirmed in August. (See FERC Affirms its Jurisdiction over Tri-State G&T.)
FERC Rejects Interconnection, GIA Procedures
As the press conference proceeded online, FERC issued an order rejecting Tri-State’s proposed Tariff revisions modifying its generator interconnection procedures and generator interconnection agreements (GIAs) without prejudice to a submitted revised proposal (ER20-2593).
Tri-State said it intends to refile a revised proposal.
FERC in March accepted Tri-State’s Tariff revisions establishing the jurisdictional rates and terms and conditions for transmission service over its Western Interconnection facilities, but set the matter for hearing and settlement judge procedures to determine their justness and reasonableness. (See “Ruling Permits Tri-State to Become FERC Jurisdictional,” SPP FERC Briefs: Week of March 16, 2020.)
Tri-State proposed to reform its interconnection queue by transitioning from the pro forma sequential first-come, first-served study approach to a first-ready, first-served cluster study. The cooperative said the change was consistent with or superior to its pro forma large and small generator interconnection procedures (LGIP/SGIP) and the large and small GIAs.
The revisions would have established an informational interconnection study process — to assist customers make business decisions about their generation facilities before entering the queue — and a definitive interconnection study process. Tri-State said interconnection customers must demonstrate site control and meet increasingly stringent readiness milestones as they advance through the interconnection phases.
FERC found that Tri-State did not demonstrate several revisions to be consistent with or superior to the pro forma LGIP: 1) its proposal to allocate network upgrade costs based on a distribution factor analysis; 2) the requirement for interconnection customers to select energy or network resource interconnection service (ERIS/NRIS) before beginning one of the study process’ phases; and 3) the requirement for interconnection customers entering a transitional process to demonstrate readiness within 10 days of the revised LGIP’s effective date.
FERC ruled Wednesday that New York’s Commercial System Distribution Load Relief Programs (CSRP) are not entitled to an exemption from NYISO’s buyer side mitigation (BSM) because they were designed in part to offset transmission investment (EL16-92-001, et al.).
The ruling by FERC Chair Neil Chatterjee and Commissioner James Danly, both Republicans, sparked a dissent from Democratic Commissioner Richard Glick, who said it was the latest example of the commission’s campaign against state clean energy efforts.
The dispute resulted from a paper hearing initiated by the commission in February, when it narrowed the resources exempt from NYISO’s BSM rules in southeastern New York. Granting a rehearing request by the Independent Power Producers of New York, that ruling partly reversed the commission’s 2017 decision granting a blanket exemption from the rules for special-case resources (SCRs), a type of demand response. (See FERC Narrows NYISO Mitigation Exemptions.)
The commission said the blanket exemption ignored the fact that certain payments made to SCRs outside NYISO’s capacity market could provide the resources with the ability to suppress capacity market prices below competitive levels.
The commission said that SCRs’ offer floors should include only the incremental costs of providing wholesale-level capacity services and that “payments from retail-level demand response programs designed to address distribution-level reliability needs” should be excluded from the calculation of SCRs’ offer floors.
The February order initiated a proceeding to evaluate retail-level DR programs individually to determine whether their payments should be excluded.
Wednesday’s ruling concluded that CSRP should be subject to BSM but that payments received under the Distribution Load Relief Programs (DLRP) qualify for exclusion from the calculation of offer floors.
FERC said New York’s Distribution Load Relief Programs (left) are exempt from buyer-side mitigation rules but that Commercial System Distribution Load Relief Programs (right) are not. | Con Edison
Under Con Edison’s DLRP, customers receive notification two hours before a DLRP event, which is called to address an isolated need. In contrast, the utility’s customers receive notification at least 21 hours before a CSRP event, which is called in response to system-wide peak demand.
“The record in this proceeding demonstrates that the purpose of the DLRPs under consideration is to maintain distribution-level reliability by reducing distribution system demands in response to contingencies and other emergencies,” the commission said.
“We find, however, that the CSRPs under consideration are not designed to address and do not address solely distribution-level reliability needs, and therefore payments received under those programs must be included in the calculation of SCR offer floors in NYISO. … Both Con Edison and Orange and Rockland state that the CSRPs under consideration provide network load relief to the system during peak hours to address system-wide needs under peak load operating conditions.”
The commission said its case-by-case review of DR programs ensures a balance between the need to protect NYISO’s capacity markets while avoiding inappropriate barriers to DR’s participation in the market.
Glick disagreed, saying the order “once again perverts buyer-side market power mitigation into a series of unnecessary and unreasoned obstacles to New York’s efforts to shape the resource mix.”
“Buyer-side market power rules — often referred to as minimum offer price rules or MOPRs — that were once intended only as a means of preventing the exercise of market power have evolved into a scheme for propping up prices, freezing in place the current resource mix, and blocking states’ exercise of their authority over resource decision making,” Glick wrote.
Glick said the majority made “arbitrary distinctions” between different types of retail-level demand response programs.
“The record before us suggests that both DLRPs and CSRPs are retail-level programs directed at distribution system issues. They do so by having retail customers curtail their consumption in order to reduce the stress on particular elements of the distribution system,” he said. “That solves a very different issue than NYISO’s SCR program, which addresses peak demand on and the reliability of the bulk power system by, among other things, calling on demand response to maintain adequate operating reserves. To see that, one need look no further than the fact that the dispatch of DLRPs and CSRPs rarely overlaps NYISO’s SCR dispatch.”
The 9th U.S. Circuit Court of Appeals on Wednesday vacated two FERC orders that last year threatened to force a jurisdictional standoff with the federal judge overseeing Pacific Gas and Electric’s bankruptcy. The court also vacated an order by the bankruptcy court but declined to resolve the issues at the heart of the dispute.
The conflict goes back to the onset of PG&E’s Chapter 11 proceeding, in January 2019, when FERC issued two declaratory orders saying it shared authority with the U.S. Bankruptcy Court over any of the $42 billion in power purchase agreements that PG&E might seek to modify in bankruptcy (EL19-35, EL19-36). (See FERC Claims Authority over PG&E Contracts in Bankruptcy.)
As part of its bankruptcy filing, PG&E had asked bankruptcy Judge Dennis Montali to issue an injunction confirming his court’s exclusive jurisdiction over the utility’s rights to alter or reject PPAs and other FERC-related agreements.
The issue arose after NextEra and Exelon petitioned FERC for declaratory orders against PG&E because of concern that PG&E would try to get out of high-cost contracts it had signed with owners of solar, wind and other renewable electricity sources.
FERC acknowledged that the law over conflicts between the Federal Power Act and the Bankruptcy Code was unclear. The commission staked out a compromise position asserting that the commission and courts held “concurrent jurisdiction” over PPAs in cases such as PG&E’s.
Montali initially took a cautious approach to the jurisdiction issue, asking FERC’s and PG&E’s attorneys to reconcile their differences over the matter. But once that effort failed, the judge issued a declaratory judgement stating that FERC had no authority over the contracts and that PG&E did not need commission approval to reject any of them. (See ‘FERC Must be Stopped,’ PG&E Bankruptcy JudgeSays.)
The dispute became a moot point in the Chapter 11 proceeding when PG&E chose to honor all PPAs with its suppliers.
Clearing the Path
The 9th Circuit’s ruling addressed two petitions: one from PG&E to review FERC’s declaratory orders and another from FERC to review Montali’s declaratory judgement.
“The orders all involved the same question: whether a Chapter 11 debtor can cease performing under its wholesale power contracts with the approval of the bankruptcy court, or whether FERC’s consent is also needed,” the three-judge panel wrote.
“We need not — and cannot — reach the merits of this dispute, because the cases became moot when the bankruptcy court confirmed a reorganization plan requiring PG&E to assume, rather than reject, the contracts at issue,” the court found.
The one remaining question: How to treat the “unreviewed” orders?
The judges moved to vacate all three, applying the rule set forth in Munsingwear v. United States, which holds that “[w]hen a case becomes moot on appeal, the ‘established practice’ is to reverse or vacate the decision below with a direction to dismiss.” That decision “clears the path” for any future relitigating of the issues, preserving the rights of all parties involved while prejudicing none of them “by a decision which … was only preliminary.”
The judges noted that all parties involved in PG&E v. FERC agreed the court should vacate the bankruptcy court’s declaratory judgement. However, FERC and the power suppliers protested giving similar treatment to the commission’s orders, asking that they remain in place.
“FERC and the intervenors point out that PG&E proposed assuming the power contracts in the reorganization plan ultimately confirmed by the bankruptcy court. They argue that PG&E’s involvement in this process renders vacatur inappropriate,” the judges noted.
But the court disagreed, saying the circumstances justified vacatur even though PG&E had a hand in mooting its own petition in the matter.
“Importantly, the company did not intend to circumvent our review of FERC’s orders. … Rather, PG&E twice moved for expedited consideration of these cases so that we could resolve them prior to resolution of the bankruptcy proceedings,” the 9th Circuit found. “The company also urged us to hear the cases over FERC’s related ripeness arguments.”
The court went on to point out that PG&E’s actions to moot Montali’s order were in part attributable to “coercion” by the state of California, which required the utility to reach a bankruptcy plan by June 20 in order to become eligible to draw on the state’s $21 billion wildfire liability fund.
The court also found that vacating FERC’s unreviewed orders would prevent the orders from having an adverse impact on PG&E or any other utility in the future.
“At the heart of these cases lies a dispute concerning FERC’s powers over contract performance, including a question of what constitutes a rate change under the filed-rate doctrine and Federal Power Act,” the court wrote. “These issues could well arise outside of bankruptcy. While the orders are declaratory, and we cannot say with certainty how they might affect PG&E or others, we think the better course is to eliminate that concern.”
The court held that its decision did not express any opinion on the merits of the dispute and should not harm FERC, “as it can easily re-assert its position in future proceedings.”
After years of using its own generator interconnection cost allocation method, American Transmission Co. will transition to MISO’s after FERC on Monday gave the company its approval.
ATC’s revision will apply to the 2020 cycle of generators interconnecting to its system, or any interconnection request submitted on or after April 29, 2019 (ER20-2619).
MISO currently allocates 90% of necessary transmission upgrades above 345 kV to the generator and 10% to load on a systemwide basis. Costs for upgrades rated below 345 kV are 100% assigned to the generator.
In 2006, MISO adopted a reimbursement approach where 50% of a generator’s network upgrade costs would be repaid to the interconnection customer through credits against transmission service charges, if the customer could prove its generator had been designated as a network resource or held at least a one-year contract to supply capacity or energy. That process was only in effect for three years.
| American Transmission Co.
ATC opted not to use the MISO approach. The transmission utility instead used a 100% reimbursement policy for interconnecting generators that could prove they were fulfilling network needs. ATC also never adopted MISO’s 10% postage-stamp allocation for network upgrades 345 kV and above, which replaced the 50% reimbursement procedure in MISO’s Tariff in 2009.
With the commission’s approval, ATC will use the 10% postage-stamp allocation provision and phase out its 100% reimbursement policy. The utility said most MISO transmission owners already use the RTO’s cost allocation approach and that the transition would bring more homogeneity with the RTO’s interconnection procedures. ATC also said its revaluation of cost allocation was prompted by FERC’s recent decision reinstating TOs’ option to self-fund network upgrades. (See FERC Upholds MISO Self-fund Order, Glick Dissents.)
Clean Grid Alliance, the American Wind Energy Association and the Solar Council argued against ATC’s proposal, contending the April 2019 effective date violates rules against retroactive ratemaking. They argued that interconnection customers have already entered the MISO queue’s 2020 cycle “with the reasonable expectation that the current cost allocation rules would apply.” The parties pointed out that 45 projects planning to interconnect to ATC entered the 2020 queue cycle and reminded FERC that it previously supported “stability and predictability” in grid operators’ queues.
But FERC said an interconnection customer’s generator interconnection agreement, signed upon completion of MISO interconnection queue studies, should be considered the Rubicon for projects in the queue. ATC’s proposal does not affect existing executed or unexecuted GIAs, the commission said, “because prospective generators in MISO’s 2020 queue cycle are not scheduled to execute GIAs until July 2022, nearly two years in the future.”
