SPP last week announced the promotions of three longtime executives to senior vice president positions, though their areas of responsibilities will not change.
Barbara Sugg (information technology and chief security officer), Bruce Rew (operations) and Lanny Nickell (engineering) were all vice presidents over their departments.
Each of the new senior vice presidents has at least 20 years of experience with SPP. Rew joined in 1990 and was one of the organization’s original 14 employees, while Sugg and Nickell came on board in 1997.
CEO Nick Brown announced the promotions Thursday during SPP’s customary staff meeting following the Board of Directors meeting. Brown revealed his own retirement plans, effective April 2020, during the board meeting. (See related story, SPP’s Brown to Retire as CEO in 2020.)
“Each of these individuals has proven many times over that they possess the technical expertise, business acumen and leadership qualities that SPP needs to best serve our customers,” he said in a statement.
“Being promoted to senior vice president recognizes the importance of and dependency on IT and cybersecurity at SPP,” said Sugg, who oversees IT and telecommunications services to its members and establishes IT strategy and policies.
Rew has held several engineering and management roles at SPP, including serving as vice president of engineering. He is leading SPP’s Western expansion — which includes contract services for reliability coordination and an energy imbalance market — and is responsible for the grid operator’s market operations.
“This promotion is a recognition of the outstanding team of professionals I get the honor of leading on a daily basis,” he said. “I look forward to continued success in managing the operational opportunities ahead for SPP.”
Like Rew, Nickell has been vice president of both engineering and operations. He is responsible for transmission planning, tracking projects costs and statuses, and administering long-term transmission service and generator interconnection processes.
“SPP and the power grid face a future full of tremendous opportunities and rapid change,” he said. “It will be increasingly important for us to anticipate the exciting changes facing our industry and do so in a way that provides increased value for our members and their customers.”
ISO-NE COO Vamsi Chadalavada told the New England Power Pool Participants Committee that average day-ahead cleared physical energy during peak hours for July was 99.8% of forecasted load, up from 99.1% during June. “As far as I can recall, that’s about the highest that we’ve seen over the past few years,” he said. [Editor’s Note: Chadalavada approved his comments for publication after the PC meeting.]
The RTO prefers to fill its projected load through day-ahead awards because they maximize flexibility and minimize costs. Once the day-ahead market closes, the RTO’s choices are reduced because long-lead-time generators may not be available, resulting in greater reliance on more expensive, fast-start generators.
Daily net commitment period compensation (NCPC) payments for July were $2.7 million, up $1 million from June. Chadalavada said the payments were mostly the result of high loads in the Southeast Massachusetts/Rhode Island area and transmission outages on two 345-kV lines in Southern Maine.
Wind production – July 20 to 21, 2019 | NEPOOL
Chadalavada said the SEMA/RI commitments are the result of a lack of a large generator in the load zone following the retirement of the Pilgrim nuclear plant.
“The need for second contingency protection in SEMA/RI is higher at loads greater than 20,000 MW,” he said.
Chadalavada also discussed the July 20-21 heat wave, which resulted in peak loads of more than 24,100 MW for the hour ending 18:00 on both days. The peak for the month, however, came July 30, when load hit 24,300 MW at HE 18:00.
Chadalavada said actual conditions on July 20 were close to the weather forecasts from the day before, but the weather forecasts the RTO relies on overestimated July 21 dewpoints by 3 to 4 degrees, representing 800 to 1,000 MW of load.
About 2,000 MW of generation self-scheduled on July 20 and 400 MW on July 21 to perform “Claim Capability Audits.” There also were some hours of negative prices in Northern Maine driven by New Brunswick imports and wind generation.
That, combined with deviations from day-ahead interchange and wind production schedules, resulted in LMPs ranging from $20 to $60/MWh.
On July 20, there were “substantial amounts of energy in real time that were not part of the day-ahead clear. So, the combination of all of these factors led to lower LMPs than maybe one would expect for a hot weekend,” he said.
Chadalavada also reminded stakeholders of a public meeting Sept. 12 in Boston on Regional System Plan 19. Stakeholder comments on the plan will be reviewed by the Planning Advisory Committee on Thursday.
Sunday, July 21, 2019, forecast vs. actual load | NEPOOL
PC OKs Revisions to Import Capacity Rules
The PC on Friday approved changes to the requirements for submitting external transactions for capacity imports, a move that ISO-NE said will streamline the procedure and align it with its Pay-for-Performance program.
The committee approved without opposition revisions to Market Rule 1, Manual M-11 (Market Operations) and Operating Procedure 9 (Scheduling and Dispatch of External Transactions), as recommended by the Markets Committee at its July 8-10 meeting. (See NEPOOL Markets Committee Briefs: July 8-10, 2019.)
The committee also approved revisions to OP-5 (Resource Maintenance and Outage Scheduling) over the objections of numerous generators, including Calpine, Dynegy and FirstLight Power. The changes, which were recommended by the Reliability Committee at its July 16-17 meeting, cleared the PC with 71.6% support. (See NEPOOL RC/TC Briefs: July 16-17, 2019.)
The changes to MR 1 and OP-9 were prompted by a new Enhanced Energy Scheduling (EES) software platform scheduled for implementation by October. They also include clean-ups to remove outdated provisions relating to coordinated transaction scheduling (CTS) and dynamic scheduling.
The RTO identified four primary changes:
Day-ahead and real-time energy offers will no longer have to be submitted with the same transaction;
A day-ahead transaction will not be required when the interface’s import transfer capability is zero;
Real-time transactions will no longer be required for capacity that wheels through NYISO to a CTS interface; and
All capacity imports backed by an external resource will have the same requirements pertaining to resource outages (i.e., to notify ISO-NE of outages and comply with the requirements of the native control area).
The RTO said the revisions to OP-5 are conforming changes to align with the revised market rule language for capacity imports. They will require market participants to notify the RTO if there is a reduction in capability that impacts the capacity supply obligation of the import resource(s).
Brett Kruse, vice president of governmental and regulatory affairs for Calpine, reiterated his previous opposition.
“We do not believe that external capacity should be counted as capacity unless it’s a specific generator with some form of firm point-to-point transmission or some other firm transmission product to ensure deliverability,” Kruse said in a statement he approved for publication after the PC meeting. “So even though that’s been longstanding [policy] — we allow that kind of stuff in New England — we’ll always vote against that.”
Consent Agenda
The committee also approved several measures on its consent agenda during its meeting, which lasted less than an hour.
Revisions to MR 1 and Tariff section 1.2.2 requiring solar resources to provide meteorological and operational data to support forecasting. It also consolidates in MR 1 the wind data forecasting requirements, which will be moved from Tariff Schedule 22.
Revisions to OP-8 to delete obsolete NERC provisions and align the procedure with Northeast Power Coordinating Council Directory No. 5.
Revisions to OP-13 and Appendix B to simplify references and make minor clarifications to terminology regarding under-frequency load shedding (UFLS) islands. Also clarifies compensatory load shed requirements and incorporates references to NERC’s regional reliability standard for under-frequency set points.
Revisions to OP-16 Appendix K regarding monthly ISO-NE updates and quarterly transmission planner updates to the short-circuit base cases. Reorganizes the document regarding generators and transmission owners.
Revisions to OP-2 Appendix C regarding the provision of contact information in requests for electronic copies of the equipment maintenance request form.
Revisions to OP-24 reflecting the change in Appendix C. The original diagram of relay outage locations was replaced with a list of transmission facilities for which TOs are reporting protection settings, characteristics, failures or degradation.
Revisions to OP-12 and Appendix D to clarify local control center actions for providing voltage schedules to generators.
Revisions to section I.2.2 of the Tariff to incorporate definitions for interconnection reliability operating limit (IROL) and system operating limit (SOL).
DES MOINES, Iowa — SPP CEO Nick Brown last week told the Board of Directors and Members Committee that a recent FERC-NERC report on a 2018 cold-weather event confirmed the RTO’s position on MISO’s use of its system.
“I’m very appreciative of FERC and NERC inserting themselves in what was initially described as a contractual dispute,” Brown said during the July 30 meeting. “Significant clarification was needed, and we got that.”
MISO uses a tie line in the Missouri Bootheel to link its Central and South regions. Under terms of a 2015 settlement with SPP, MISO is free to transfer up to 1 GW without compensating SPP and other parties, but it cannot exceed 2.5 GW or 3 GW, depending on the power flows’ direction.
On Jan. 17, 2018, unusually cold weather led to numerous outages and derates in the South. Entergy alone lost 11.6 GW of capacity, leading MISO to declare a maximum generation alert for the region. During the event, MISO exceeded its 3-GW north-to-south limit by 1.3 GW.
“It was one of the most significant operating events I’ve seen in my career,” Brown said.
SPP General Counsel Paul Suskie said that with the large number of contingencies on the regional grid, the report uses the term “N-many,” something the RTO’s veterans had never seen before.
FERC last September opened an inquiry, just the third it’s ever conducted. It released a copy of the report, done in partnership with NERC, on July 18. (See FERC Orders Cold Weather Reliability Standard.)
The report corroborates SPP’s position that any energy above the 1-GW transfer limit should be non-firm and as-available, staff said. They said the report noted MISO incurred risk in assuming it could transfer more than 1 GW across the seam.
| SPP
In the report, FERC staff recommended NERC develop a standard on generation weatherization, the second time it has made that suggestion.
That work has begun, Brown said, and SPP has been asked to sponsor the effort. “We readily accept that opportunity,” he said.
The report included 13 recommendations for SPP, MISO and the other parties to the RTOs’ agreement (Associated Electric Cooperative Inc., Southern Co., Tennessee Valley Authority, LG&E and KU Energy, PowerSouth Energy Cooperative, and NRG Energy). Nine apply to SPP. The RTO has addressed four of them: perform periodic impact studies, analyze real-time voltage stability, conduct capacity and energy emergency drills, and consider deliverability to avoid stranded reserves. (See related story, “MISO Says Winter Standards Reasonable,” MISO Reliability Subcommittee Briefs: Aug. 1, 2019.)
Directors Lower Exit Fee to $100K
The board approved a Corporate Governance Committee (CGC) recommendation to lower SPP’s exit membership fee to $100,000, a 67% reduction from the current level. Load-serving entities would also be subject to an additional fee based on their net energy-for-load share of the RTO’s financial obligations and future interest.
FERC in April found the fee’s provisions to be unjust and reasonable and a barrier to market participation by non-transmission owners. The commission directed the RTO to eliminate the fee for members who are not TOs or LSEs. (See FERC Tells SPP to End Exit Fee for Non-TOs.)
The change still leaves SPP as the only grid operator with an exit fee not based on charging exiting members to cover their open market positions.
“SPP is still unique in having an exit fee. In my mind, the problem with the exit fee is it’s divorced from the costs driven by membership,” said Enel Green Power’s Betsy Beck, referring to meeting costs and staff time.
Beck said market costs should be borne by all market participants and not just members. “I certainly agree membership is important, but as the market evolves, there need to be pathways for others interested in being engaged,” she said.
“Where SPP is different [is that] membership matters,” Suskie responded. “When you’re a member, you truly have influence over what comes before the board.”
When asked by Beck whether FERC would accept the $100,000 fee, Suskie noted that the commission approved its $300,000 fee in 2006.
“I’m sure your organization and others will protest,” he said.
The board also approved a recommendation that eliminates the exit fee as part of a compliance filing and language defining LSEs and non-LSEs. Staff proposed combining existing language in different Tariff sections to define LSEs as any member that satisfies either definition.
SPP has requested a rehearing of FERC’s decision but was granted a compliance extension to Aug. 1.
“By making this filing, we’re not challenging the ruling,” Suskie said. “We still have an obligation.”
Staff met the deadline by making the new exit fee (ER19-2523), compliance (ER19-2522) and LSE-definition (ER19-2524) filings.
Altenbaumer Delivers VATF, SPC Updates
Board Chair Larry Altenbaumer told the board and members they will likely see final recommendations from his Value and Affordability Task Force (VATF) during the October cycle of meetings.
He said the task force is paying special attention to “SPP’s overall performance in providing value” and that it intends to bring everything together by October. “We’re trying to get some consensus,” said Altenbaumer, who chairs the group.
To that end, the VATF has been divided into three sub-teams that are meeting separately from the full group:
Budget, led by Evergy’s Darrin Ives, focusing on budget, staffing and IT costs;
Process, led by NextEra Energy Resources’ Holly Carias, engaged in project approval and prioritization processes; and
Mission/Strategy/V, led by Golden Spread Electric Cooperative’s Mike Wise, concentrating on organizational group efficiencies and defining, measuring and communicating affordability.
The group, which was formed in January, is finalizing its definitions of affordability and value, determining the criteria for evaluating the sub-teams’ action plans, and updating communication plans on SPP’s value.
Altenbaumer also updated the board and members on the Strategic Planning Committee, which he also chairs. As part of its effort to develop a strategic vision, he said, the committee has used stakeholder feedback to draft a list of strategic initiatives that SPP should “actively pursue.”
Expanding the RTO’s footprint and implementing the Holistic Integrated Tariff Team’s (HITT) and the VATF’s recommendations top the list. Other proposed initiatives include adding services within SPP, focusing on cybersecurity and addressing energy storage technologies, integrating the rush of renewable energy and exporting renewables.
“At present, SPP doesn’t have a normal vision,” Altenbaumer said. “This is something we’d like a new consideration for the organization.”
Under its current timeline, the SPC will deliver its strategic plan to the board in July 2021.
SPP to ‘Beef Up’ Engineering Staff
CEO Brown said during his regular president’s report that SPP has decided to “beef up” its engineering analysis staff to address the backlogged generation interconnection queue, “one of the highest areas of discontent of our members and customers.”
“We have begun receiving numerous letters from congressmen and governors, begging us to do more and commit more resources,” Brown said.
He said recent changes to SPP’s interconnection process — a new three-phase study process and changes to eligibility for financial security refunds — have given the RTO pause to “look very hard at our resources.” (See FERC OKs New SPP Interconnection Process.)
“In this particular situation, the cost to the customer in the GI queue will go down, the administrative fee paid by members will go down [and] the administrative overhead will be spread over a larger group,” Brown said.
A side benefit will be increased customer engagement, Brown said, pointing to recent turnover in the engineering group. “They would rather do the technical work they were trained to do than manage the GI queue,” he said.
Brown also said the CGC he chairs will meet Aug. 22 to consider nominations for seven expiring seats on the SPC and Members, Finance and Human Resources committees. He said the incumbents had said they “desire to continue to serve” but welcomed additional nominations.
Basin’s Christensen Joins SPC
The consent agenda was passed without dissent. It will result in:
The approval of Basin Electric Power Cooperative’s Tom Christensen for the open TO position on the SPC. Christensen replaces Basin’s Mike Risan, who has retired.
The 2020 operating plan, which details SPP’s planned work for the upcoming calendar year after being vetted and approved by the Finance Committee and SPC. Next year’s plan focuses on providing market and reliability services in the Western Interconnection, implementing the HITT’s recommendations and developing a proactive response to known and emerging cyber threats.
Lowering a previously approved Missouri project’s costs from $40.4 million to $31.6 million. Evergy’s Kansas City Power & Light, KCP&L-Greater Missouri Operations and Westar Energy companies are responsible for the 345-kV voltage conversion project.
CARMEL, Ind. — At first blush, MISO agrees with FERC’s recent recommendation that NERC develop cold weather reliability standards — but it is still reviewing the commission’s report and the possible implications.
“We do consider it a fair report, with reasonable recommendations,” MISO Reliability Subcommittee liaison Mike McMullen told stakeholders at last week’s RSC meeting.
“It’s relatively new out there, so MISO is still evaluating,” he added.
Among other recommendations, FERC called for new studies that emulate a realistically stressed grid, better communication on the effects of ambient temperature on generation and transmission lines, improved freeze protection measures on generation, and clearer emergency protocols around MISO’s regional dispatch transfer limit between its Midwest and South regions. (See FERC Orders Cold Weather Reliability Standard.)
The commission issued the recommendations after investigating an atypical cold snap in MISO South on Jan. 17, 2018, that led to higher-than-expected demand and caused MISO and SPP to seek voluntary load reductions, nearly forcing load shedding. (See related story, “RTO Applauds FERC, NERC Report on Cold Weather Event,” SPP Board of Directors/MC Briefs: July 30, 2019.)
MISO to Share Cyberattack Data with Feds
MISO is now operating under new rules that will allow it to share nonpublic data with the federal government if it finds itself or its members under a cyberattack.
The RTO last year proposed to share more information on significant cyberattacks with the Department of Homeland Security and other federal governmental agencies when it deems it appropriate. (See MISO Tariff Changes Target Cybersecurity Data Sharing.) FERC approved the new data-sharing strategy in June, despite Exelon’s contention that MISO should specify the types of attacks and narrow the federal agencies receiving reports (ER19-875).
MISO Director of Incident Response and Systems Recovery David Rosenthal said in spring that the RTO anticipates using the information-sharing protocol “rarely, if ever.”
Executive Director of Controls and Engagement Joe Polen told the RSC on Thursday that MISO will only share data on a limited basis and that only its corporate information security officer or cyber director can make the determination.
“We don’t share that information unless we absolutely have to,” Polen explained. “MISO hopes to never need to use the additional data-sharing practices.”
Polen also said MISO can terminate the agreement with Homeland Security at any time.
Northern Indiana Public Service Co.’s Bill SeDoris asked whether members will be notified if MISO shares their information.
“If we do have an event where we have to share information, we will contact the members and let them know what was shared,” Polen responded.
However, MISO legal staff at the meeting said there may be some instances where DHS may want the RTO to delay notifying members for a reasonable period while it investigates and addresses a cyber threat.
MISO Reworking Outage Penalty Conditions
MISO is putting a finer point on the penalty exemption policy under its stricter generation outage scheduling rules.
In June, MISO pitched a plan to exempt resources from accreditation penalties if the length of a submitted outage remained within 10% of the originally scheduled outage window, providing wiggle room to either reduce or lengthen outages. (See “Outage Exemption Talk Ongoing,” Stakeholders: MISO System Fix Too Late for Summer.)
MISO will now allow outage reductions of up to 20% of the original window without triggering a full revaluation of the outage’s impact on expected capacity margins. Those seeking to increase the length will be required to submit an entirely new outage request.
The penalty exemption rules are part of a new policy requiring generators to schedule planned outages 120 days in advance in order to be categorically exempt from possible accreditation penalties; the new process was approved by FERC in late March (ER19-915).
Shift operator Trevor Hines said more members have been in contact with MISO to discuss the nuances of their planned outages since the outage rules were enacted.
“We have been receiving more calls and communications, and we recommend those continue as you approach situations that you need help with. … Those calls have gone very well the last few months,” Hines said.
2 Emergency Warnings in June
June was mostly cooler than usual for MISO, although the South region experienced tight operating conditions and near-emergency calls twice during the month.
Average load for the month was 77.8 GW, lower than the 84.5-GW average a year earlier. The 107.8-GW monthly peak set on June 27 also fell far short of last June’s 121.6-GW peak. During a July Informational Forum, Rob Benbow said average temperatures for the month were lower than normal and 8 degrees lower than in June 2018. Lower loads and fuel prices brought average prices down to $23.07/MWh, 27% year-over-year decrease.
MISO said its reliability, markets and operational functions performed well over the month.
However, MISO issued a maximum generation warning for South on June 3 when load and forced outages crept upward and transmission outages stranded some generation. South was also the subject of a separate maximum generation alert on June 20, again prompted by forced generation outages and transmission outages from storms the night before.
“We were able to manage our way through those conditions,” Benbow said.
MISO has issued real-time generation notifications three months in a row, including a May maximum generation emergency declaration, a June maximum generation warning and conservative operations instructions during a mid-July heatwave.
During the RSC meeting, WPPI Energy economist Valy Goepfrich asked MISO to begin distinguishing in its reports the locations of its maximum generation notifications, based on the Midwest, South or footprint-wide regions.
Telephones and Hot Topics
MISO may change its control room phone system and is asking members for their recommendations and experiences with their own systems. The RTO is circulating a nine-question survey to members to collect information on other phone plan options.
Finally, MISO’s upcoming Hot Topic discussion during September Board Week in St. Paul, Minn., will focus on transformative changes taking place in the energy industry and how the RTO could ease the transition for its member companies. Members are expected to bring their ideas on what future services they may require of MISO during the Sept. 18 conversation.
Director of Market Strategy and Design Scott Wright said he believes the talk will in part center on the trends MISO laid out in its first Forward Report issued earlier this year. (See New MISO Report Starting Point for Major Grid Change.) He said he expects to hear conversation on the need for improved ramp capability, increasing two-way power flows on distribution — and possibly transmission — systems, and how MISO can best manage transactions between the wholesale and retail level.
In a decision that could boost small solar development in California, a federal appeals court last week struck down a state program that sets the terms by which investor-owned utilities must contract with alternative energy suppliers.
The decision by the 9th U.S. Circuit Court of Appeals found California’s Renewable Market Adjusting Tariff (ReMAT) program violates the Public Utility Regulatory Policies Act by capping the volume of energy that utilities must purchase from qualifying facilities and setting contracts at a market-based rate rather than one based on a utility’s avoided cost. The ruling affirmed a district court opinion.
“The district court observed that ‘despite the complex regulatory and factual background’ in this case, ‘the key legal issues turned out to be straightforward.’ We agree,” Judge M. Margaret McKeown wrote in the appellate panel’s opinion.
The case arose when Winding Creek Solar, a QF seeking to develop a 1-MW solar facility in Lodi, Calif., contested the ReMAT program, which the California Public Utilities Commission implemented in 2013 to set a market-based rate for energy generated by QFs.
After Winding Creek unsuccessfully challenged ReMAT at FERC, it filed suit in the U.S District Court for the Northern District of California, which issued a summary judgment in favor of the company but declined to grant its preferred remedy of receiving the initial $89.23/MWh contract price offered under ReMAT at the program’s inception. The QF then appealed that decision to the 9th Circuit for further review.
‘Essentially an Auction’
The legal questions over ReMAT came down to its design, which was intended to bring an element of competition to QF contracting while providing suppliers with access to a market.
Under the program, QFs in a given utility service territory are placed into a queue on a first-come, first-served basis. Every two months, in what the court described as “essentially an auction,” the utility offers to contract with QFs at the front of the queue at a predefined price. QFs are free to accept or reject the contract, and those choosing the latter can hold their place in the queue until the next round of offerings two months later.
The CPUC caps the volume of energy the state’s three large investor-owned utilities must buy through the program at 750 MW, which is divided among the IOUs based on their share of peak load. Each utility is additionally allowed to subtract from its share any energy that it purchases under other CPUC programs.
The Winding Creek facility would be sited in the territory of Pacific Gas and Electric, which is obligated to purchase about 150 MW of energy under ReMAT, divided equally among “baseload,” “non-peaking as-available” and “peaking as-available” generation. Winding Creek falls under the last category.
The court pointed out that PG&E is obligated to purchase no more than 5 MW of energy from each category over a two-month period, allowing it to halt contract offers after reaching the caps.
The ReMAT program also functions as a kind of dynamic price-setter for QF contracts. While the CPUC initially set a QF contract price of $89.23/MWh for peaking as-available generation, ReMAT prices can adjust every two months based on the willingness of QFs to accept contracts at the price offered during the previous bidding interval. If QFs collectively offer less than 1 MW of energy during a two-month period (and there are at least five unaffiliated QFs in the queue), the price rises for the next interval; if QFs supply more than 5 MW, the price declines. In cases when QFs supply 1 to 5 MW, the price remains unchanged. Prices adjust based on a formula provided by the CPUC.
When Winding Creek was accepted into the ReMAT program in 2013, it was not placed near the top of the queue and did not receive the initial $89.23/MWh price. By the time it received an offer in March 2014, the contract price had fallen to $77.23/MWh, which the developer rejected because it could not operate the facility at that price.
Two Wrongs
The 9th Circuit first took issue with ReMAT’s cap on the amount of energy utilities must purchase from QFs, calling it impermissible because it violates PURPA’s “must-take” provision.
“As a result [of the cap], a utility could purchase less energy than a QF makes available, an outcome forbidden by PURPA,” the court found.
The court further determined that ReMAT’s pricing scheme “runs afoul” of PURPA’s requirement that utilities contract with QFs at their avoided cost rate (ACR). While acknowledging that state agencies have flexibility in calculating that rate, the court said “the ReMAT price, which is arbitrarily adjusted every two months according to the QFs’ willingness to supply energy at the predefined price, strays too far afield from a utility’s but-for costs to satisfy PURPA.”
The court went on to reject the CPUC’s argument that its other PURPA program, known as the “Standard Contract,” provides QFs a sufficient alternative to ReMAT. While that program offers an ACR based on a six-variable formula, the court found that three of the six “are impossible to determine at the time of contracting.”
“The Standard Contract violates PURPA because it fails to give QFs the option to calculate avoided cost at the time of contracting,” the court said.
The court pointed out that PURPA mandates that QFs be given a choice of calculating the avoided cost at either the time of contracting or time of delivery.
“The bottom line is that two wrongs don’t make a right. Because neither option offered by the CPUC is PURPA- compliant, California’s regulatory scheme is pre-empted by federal law.”
But the appellate court also did not provide full satisfaction to Winding Creek, agreeing with the lower court’s decision that it would not be offering “equitable relief” by granting the QF a contract at ReMAT’s initial $89.23/MWh price.
“Indeed, it would be inappropriate to order a non-party to contract with Winding Creek under a modified version of the very program the court had just determined to be pre-empted by federal regulation,” the court found. “It is not the court’s job to fashion a new contract to Winding Creek’s liking.”
MISO is nearing its goal of an October FERC filing to solidify its first, limited set of storage-as-transmission assets (SATA) rules.
“There’s a number of complicated issues, and we can’t make promises … but I think we’re making good progress,” MISO Director of Planning Jeff Webb said of the filing target during an update at a Reliability Subcommittee meeting Thursday.
Webb said MISO staff are currently drawing up Business Practices Manuals to pair with its Tariff filing so the rules can be implemented soon after approval.
The RTO is also promising another, more comprehensive set of SATA rules in the future that would allow for concurrent use of resources as both transmission and generation.
Energy storage in Minnesota | Connexus Energy
One Wisconsin battery project is so far striving for SATA treatment in MISO’s 2019 Transmission Expansion Plan (MTEP 19). (See MTEP 19 Could Yield First MISO SATA Project.)
Webb said owners of storage projects selected in the MTEP will enter into transmission owner agreements and become registered TOs, if they aren’t already.
MISO is holding firm that it’s not yet ready for storage that can simultaneously provide transmission services and offer into the energy market.
“It’s rather more complicated when it’s earning two revenue streams,” Webb said.
But Webb also called MISO’s filing a “placeholder” for a more exhaustive approach that allows electric storage to function as both transmission and energy. For now, though, the aim is to “keep it simple,” prohibiting SATA from participating in markets, thus drawing a line between how storage is treated under FERC Order 841 and how it will be considered as transmission in the MTEP study process.
“We’re trying to get to a place where, yes, you may have a battery in MTEP … and be able to also earn market revenues,” Webb told stakeholders. “We fully expect that will be the end result.”
AES battery storage | AES
WEC Energy Group’s Chris Plante asked how MISO will account for the limited, three to four hours of discharge that batteries can provide in reliability planning.
Webb said the duration of storage discharge will be a key consideration in the transmission planning process.
“If we don’t have the confidence that a storage device can ride through a peak load period, we just wouldn’t pick it,” Webb explained.
Customized Energy Solutions’ David Sapper said he still wasn’t convinced that a storage device managing transmission constraints won’t have impacts on the energy market.
“It is important to establish what it should and shouldn’t be used for,” Webb responded.
MISO will hold final stakeholder discussions on its SATA filing at Planning Advisory Committee meetings on Aug. 14 and Sept. 25.
Eversource Energy’s earnings fell sharply last quarter after the company was forced to write off $204 million from its investment in the failed Northern Pass transmission project — but its fortunes are looking more promising offshore.
The company last week reported second-quarter earnings of $31.5 million ($0.10/share), compared with $242.8 million ($0.76/share) in the same period a year ago.
“The Northern Pass impairment was a difficult step for us to take given the economic and environmental benefits the project could have brought to New England, but it does not take away from the fact that 2019 has been very positive for Eversource,” CEO Jim Judge said in a statement.
Excluding the impairment, Eversource earned $235.9 million ($0.74/share) in the quarter.
The company’s transmission segment, excluding the impairment, earned $117 million during the period, compared to $112.7 million a year earlier, while the distribution segment took in $105.4 million, up from $101.3 million.
Offshore Wind Looks Bright
New York last month awarded Eversource and its partner Ørsted an 880-MW contract for the offshore Sunrise Wind joint venture.
The company is targeting an in-service date of 2024 and signed a memorandum of understanding with Consolidated Edison and the New York Power Authority on the related transmission facilities, CFO Phil Lembo told analysts during a call Thursday.
The companies also jointly own the 130-MW South Fork project, 30 miles off Montauk, Long Island.
This map shows the lease areas of the two offshore wind projects awarded by New York on July 18: the 816-MW Empire Wind and 880-MW Sunrise Wind. | NYSERDA
In Rhode Island, state regulators in June approved a 400-MW contract for a portion of the companies’ offshore Revolution Wind project. Connecticut regulators had previously approved a separate 200-MW contract for the project and are reviewing a deal for another 104 MW, Lembo said.
He noted that Massachusetts issued its second offshore wind request for proposals of at least 400 MW in May.
“But as they did in the first RFP, they said bidders can also offer up to 800 MW or as little as 200 MW of offshore wind,” Lembo said, adding that Eversource and Ørsted are developing and refining appropriate bid strategies for both Massachusetts and Connecticut, which is seeking another 2,000 MW of OSW by 2030.
Massachusetts lawmakers passed a bill Wednesday that lifts the price cap on OSW solicitations for one year, which prior legislation had mandated must get progressively cheaper.
“For this upcoming solicitation, the cap in Massachusetts is removed, and I think that’s just recognition that there’s many things that they hadn’t thought of at the time when the cap was instituted, but they still are focused on cost going forward,” Lembo said.
State Updates
Lembo said the company is also focused on grid modernization in Connecticut, awaiting a decision by regulators on advanced metering infrastructure. The state’s legislature clarified existing statutes to explicitly allow regulated utilities to build and operate energy storage facilities that can be shown to benefit customers, he said.
Connecticut is also in the process of raising the number of commissioners on its Public Utilities Regulatory Authority from to five, Lembo noted.
“So right now, we believe [grid modernization] is certainly one of the issues that is on the front burner of the agenda at the PURA, but it’s hard to say precisely when we expect it … we do expect it to come out this year,” he said.
In Massachusetts, the company is on pace to complete a $45 million capital program to install more than 3,500 electric vehicle charging ports by the end of next year, Lembo said.
“We are poised to propose a similar electric vehicle charging program in Connecticut, pending guidance from regulators on a broader review of grid [modernization],” he said.
DES MOINES, Iowa — Following two days of spirited discussion, SPP’s Board of Directors on Tuesday approved a package of 21 recommendations intended to integrate the expansion of renewable energy, boost reliability, and improve transmission planning and the wholesale market.
The recommendations are the product of a final report by the Holistic Integrated Tariff Team (HITT), created last year by the board and Members Committee to review a whole host of the RTO’s models, processes and operations.
Some stakeholders pushed back against the HITT’s recommendation to decouple transmission pricing zones and create new deliverability subregions, suggesting further evaluation is needed. Others expressed their concern with the “all-or-nothing” approach to the recommendations’ approval, saying no one can predict their effect on a “holistic” basis.
Sensing a repeat of the discussion that took place the day before in the Regional State Committee (RSC), board Chair Larry Altenbaumer stepped in and urged the Members Committee to have faith in SPP’s stakeholder process.
“We have a stakeholder process that works,” he said. “Time after time, the stakeholder process … has delivered on results and done a good job of representing the interest of the stakeholders. It would be a disservice to the HITT team and its work to modify their recommendations.”
The 20-member committee supported the recommendations by a 17-2 vote, with Oklahoma Gas and Electric and City Utilities of Springfield (Mo.) opposing. Missouri’s Liberty Utilities abstained.
OG&E filed a seven-page letter with the board outlining its opposition to the HITT report (“misplaced” cost-allocation recommendations, “arbitrarily” shifting costs between zones and the “sheer number” of proposed changes). Greg McAuley said his company had concerns about the stakeholder process, given the potential increase in members without concerns for ratepayers, such as financial players and merchants.
McAuley echoed comments by SPP CEO Nick Brown, who said, “We’ve never seen the magnitude of change in our industry than we’ve seen over the last five years,” when he addressed the head table just before the vote.
“This puts all the ratepayers in this footprint in a vulnerable position, especially with the changes that are coming,” McAuley said. “Things are changing, Nick, more quickly than any of us can comprehend. If we move forward without caution in this, I think the consequences will be more significant than anything we’ve seen in the highway/byway [cost allocation] process.”
Springfield’s Jeff Knottek focused his comments on the HITT’s recommendation that SPP “should” separate its Schedule 9 and 11 transmission pricing zones, allowing the creation of larger Schedule 11 pricing zones and/or Schedule 9 sub-zones. The team noted the zones are largely based on legacy zones that predate SPP’s RTO status in 1994 or date to when transmission owners joined.
“We are a bit leery. I don’t see any words or discussion here of unintended consequences,” Knottek said. “I wish it would say ‘evaluate’ or ‘further study.’ [‘Should’ is] an action term that means go forward and do it.”
Holistic Integrated Tariff Team recommendations | SPP
Regulator Reluctance
Regulators made similar comments during Monday’s joint stakeholder meeting.
“My concern is overarching. Words matter,” said Oklahoma Corporation Commissioner Dana Murphy, who also filed a letter with the board urging caution. “When I looked at the executive summary, the language made this like, ‘Here’s the implementation plan. Here’s what we are going to do.’ I don’t think the report should tell the RSC to create this, do this. There are a lot of moving parts here.”
“When we try to approach issues at the commission level, we don’t try to throw too many fixes at something at one time, when one or two may fix it,” Texas Public Utility Commission Chair DeAnn Walker said. “I’d like to be able to move forward without throwing too much at this. You’re saying decouple and create. You’re telling the world what to do, and I don’t think that’s appropriate.”
Kansas Corporation Commissioner Shari Feist Albrecht, who served on the HITT, said there is some flexibility within the report.
“It seems like the report builds in the possibility that the RSC may actually reject the recommendation,” she said. “It builds in the uncertainty that exists within the RSC of approving or disapproving.”
Nebraska Public Power District’s Tom Kent, who chaired the HITT, said he was not surprised by the pushback.
“These comments are to be expected,” he said. “Any time an organization goes through change — and this represents the beginning of change — it’s a hard thing to do. Change management becomes critical.”
Saying the HITT effort was the “most significant event of my 37-year career,” Brown said he begged Altenbaumer for the privilege to motion for the recommendations’ approval.
“This is what was needed. We’ve played a game of whack-a-mole for eight years. We’ve seen an issue and tried to hit it with a single team,” he said. “Many of the attributes in our Tariff are relics from 1997. To maintain some of that thinking in today’s world is not a viable option at all.
“I sensed, as the report was coming to a head, a lot of discomfort with the pace of change,” he added. “My argument is that the pace of change is not going to ease up. If that makes you uncomfortable, my suggestion is you better get used to it.”
Kent and HITT Vice Chair Rob Janssen, of Dogwood Energy, reminded stakeholders that nine of the recommendations do urge further evaluation. However, 12 of its recommendations require action that will take place within SPP’s working groups.
“I feel like the product we provided to the board is a new platform for operations,” Janssen said. “The HITT team could have done more; it could have gone on longer. [We] saw 12 clear solutions we could come to consensus on. Some issues in the report are still fairly complex, with a lot of details to work out. I think the stakeholders are up to that challenge.”
Janssen said he and other team members have been meeting with SPP’s working groups over the past three months. “They are ready to get going,” he said. “They all want to know what the result of this meeting is so they can get going and start tackling the recommendations.”
‘Finest Hour’
The HITT team, which began meeting in April 2018, is composed of 15 directors, members and regulators. They met 17 times, reviewing SPP’s cost-allocation model, transmission planning processes, the Integrated Marketplace and real-time operations. (See SPP’s Tariff Team Begins Carving up the Elephant.)
The group divided its recommendations into four categories: reliability; marketplace enhancement; transmission planning and cost allocation; and strategic, the last of which included developing an energy storage white paper. Those recommendations have been parceled out to many of SPP’s stakeholder groups.
In praising the group’s work, Golden Spread Electric Cooperative’s Mike Wise pointed to SPP’s nearly $10 billion in transmission investment that have left consumers with “very high fixed costs … embedded in their rates” and a footprint that touches Canada and nearly Mexico.
“I’ve been involved with SPP for 23 years,” he said. “This really is SPP’s finest hour. I love what we have done.”
Timeline by date (proposed) | SPP
Kent, who likened the team’s work to eating an elephant (“one bite at a time”) was asked if the HITT had finished devouring the beast.
“There’s still a lot of work that has to happen in the stakeholder process to take these recommendations and turn them into implementable actions,” he said. “But we got enough bites to give good direction to the stakeholder groups to improve things to the benefit of the organization.”
The Markets and Operations Policy Committee is already working on creating a task force to address the HITT’s direction to develop a policy that “creates an appropriate balance” between the cost and value of SPP’s energy resources interconnection service (ERIS) and network resources interconnection service (NRIS) interconnection products, and generation with long-term firm service.
The task force would be composed of three or four representatives each from the Transmission and Supply Adequacy working groups, two members of the RSC’s Cost Allocation Working Group, and three or four independent power producers.
Of course, it could also potentially add yet another acronym to SPP’s lexicon: NED (NRIS, ERIS and Deliverability).
A new study has concluded that PJM’s proposed 10-hour rule for energy storage resources (ESRs) participating in the capacity market is “unnecessary and unduly restrictive.”
Astrapé Consulting released the analysis July 15 — funded by the Energy Storage Association and the Natural Resources Defense Council — that backs up claims from critics that PJM’s plan for integrating ESRs by mandating a 10-hour continuous runtime in order to collect their full share of capacity payments will inhibit participation and make the grid’s renewables expansion more difficult.
“Storage is a key technology enabling a low-carbon grid,” Tom Rutigliano, a senior advocate with NRDC’s Sustainable FERC Project, said in a July 15 news release. “This study agrees with many others in showing that batteries are an effective replacement for power plants. It also underscores the importance of FERC’s commitment to ensuring that rules developed for older technologies do not become barriers to storage.”
| IPL
All six jurisdictional RTOs and ISOs are facing a December deadline for compliance with FERC Order 841, which requires them to revise their market participation models to allow storage resources 100 kW and larger to provide capacity, energy and ancillary services within their technical capability.
Earthjustice attorney Kim Smaczniak told RTO Insider in April that FERC’s request for more information on PJM’s storage rules — particularly whether a “capacity storage resource” is included in the definition of a “generation capacity resource” and whether one unit can serve as both — suggests the commission is “pushing back” on the 10-hour requirement. (See FERC Asks RTOs for More Details on Storage Rules.)
It’s not yet clear how or when FERC will rule on the compliance filing, but some critics suggest an approved 10-hour rule could spur additional legal challenges.
Rutigliano told RTO Insider he couldn’t comment on whether NRDC would be part of that battle but hoped the study results would encourage PJM to reconsider.
“We would certainly be open to PJM asking FERC to hold off for a few months so this could go back through the stakeholder process,” he said.
PJM’s 10-hour rule remains the highest requirement proposed among RTOs/ISOs (ER19-469). ISO-NE sought only a two-hour minimum, while NYISO proposed four. PJM says the runtime corresponds with existing reliability standards, noting that it must “remain impartial in administering the markets.”
“This requires a common set of standards that provide a level playing field for all resources to fairly compete,” PJM spokesperson Jeff Shields said.
‘Different Needs at Different Times’
Except, critics argue, the 10-hour rule is anything but impartial.
“The purpose of the capacity market is to ensure reliability, not subsidize generation,” Rutigliano said. “PJM’s claims that it needs to purchase baseload capacity to meet very rare peak loads defies engineering reality and wastes ratepayers’ money. If the capacity market is unable to recognize the reliability value of different technologies, that shows the need for market reform rather than providing any justification for discounting storage.”
Astrapé’s results show that energy storage deployments of up to 4,000 MW with just four hours of duration can provide full capacity value relative to a resource without time constraints. Similarly, ESR deployments up to 8,000 MW with six-hour runtimes can replace traditional generation sources megawatt-for-megawatt with no impacts on reliability, the study concluded.
“The grid has different needs at different times,” Rutigliano said. “PJM ignores that and says every plant needs to be a peaker.”
PJM, however, said the study rehashes old points and suggests the organization should create an “unduly discriminatory” standard that lowers the bar for some resources and not others. It further points out that its proposal is based on a FERC-approved capacity construct and would spur innovation, not stifle it.
“Having longer duration requirements could encourage developers to make longer-lasting batteries,” Shields said. “We saw the demand response industry find innovative ways to meet our standards and compete in the market, for instance.”
The study further suggests that a 10-hour requirement ignores the historical reality of PJM’s systemwide performance assessment periods. Since 2011, only one event lasted beyond six hours: a primary reserve warning Jan. 7, 2014, that was triggered by the polar vortex, lack of access to firm fuel and other forced outages that rendered 40 GW unavailable. Astrapé notes that these issues would not trigger battery outages and that “a system with more homogeneous resources is more susceptible to these coincident issues than one which contains more heterogeneous resources with different categories of constraints.”
“While caution is warranted in using historical data to justify duration requirements since the system will be evolving, the primary takeaway is that the duration of reliability concern does not necessarily match the shape of the load,” the study reads.
PJM noted that while Astrapé’s conclusions are potentially “worthy of future analysis,” they are “not based on an approach approved by the commission.”
DES MOINES, Iowa — With the U.S. Senate bolting from D.C. on Friday for a five-week recess, it’s becoming apparent that FERC will be operating with only three commissioners until at least well into September, according to a lawyer with the agency.
Patrick Clarey, a FERC attorney and liaison to SPP, told stakeholders Monday that a lack of paperwork from the White House suggests the commission may be at “three [commissioners] for a bit.”
FERC will soon find itself two short of a full panel when Commissioner Cheryl LaFleur, who has been on the commission for nine years, retires at the end of this month. (See FERC Heaps Praise on Departing LaFleur.) The fifth seat has been open since the death of Commissioner Kevin McIntyre in January.
The vacancies have drawn the attention of Sen. Joe Manchin (D-W.Va.), ranking member of the Energy and Natural Resources Committee. In a statement released by his press secretary Tuesday, Manchin urged the Trump administration to simultaneously nominate two individuals, one Republican and one Democrat, to fill the empty seats.
“FERC was established as a five-member commission and has historically operated above the political fray,” the statement read. “In today’s changing energy environment, it has never been more important to the security of our nation to maintain this precedent. I urge President Trump to nominate two individuals … so the Senate can consider and confirm them together in the bipartisan manner that has become the norm and restore a fully functioning commission.”
The White House has yet to submit a nominee replacing McIntyre. FERC can have no more than three commissioners from the same political party, with the president’s party holding the advantage. Traditionally, the Senate caucus for the party not holding the White House recommends its party’s nominations to the president, who usually complies.
The commission will continue to have a quorum with Chairman Neil Chatterjee and Commissioner Bernard McNamee, both Republicans, along with Democratic Commissioner Richard Glick.
Chatterjee has the most seniority, having been confirmed in August 2017. He became chairman last October, when McIntyre had to step down as his illness worsened. Glick was confirmed in November 2017 and McNamee last December.
FERC operated without a quorum for six months in 2017 before the confirmation of Chatterjee and Robert Powelson, who left the commission in August 2018.
