FERC on Tuesday found that Idaho Power had satisfied the commission’s standards for market-based rate authority and terminated a Section 206 proceeding it had ordered last September to find out if the utility was exercising market power in its balancing authority area (ER10-2126).
The proceeding was meant to determine if Idaho Power could continue charging market-based rates in its BAA.
The company’s market-power analysis, initially submitted in June 2019, had passed the pivotal supplier and wholesale market share screens in the Avista, Bonneville Power Administration, Nevada Power, NorthWestern Corp., PacifiCorp-East and PacifiCorp-West BAAs and in CAISO’s Energy Imbalance Market. But it failed the wholesale market share indicative screen in one season in its own BAA.
Based on the results, FERC ordered Idaho Power to show cause within 60 days why the commission should not revoke the company’s market-based rate authority in its BAA.
Lower Salmon Dam | Idaho Power
Responding in November, Idaho Power said its updated market power analysis, which included a delivered price test (DPT), rebutted the presumption of horizontal market power in its BAA.
“As the commission has previously explained, the DPT analysis identifies potential suppliers based on market prices, input costs and transmission availability and calculates each supplier’s economic capacity and available economic capacity for each season/load level,” FERC said. “The results of the DPT are used for pivotal supplier, market share and market concentration analyses.”
The DPT calculates market concentration using the Hirschman-Herfindahl Index (HHI). “An HHI of less than 2,500 in the relevant market for all season/load levels, in combination with a demonstration that the applicants are not pivotal and do not possess more than a 20% market share in any of the season/load levels, would constitute a showing of a lack of horizontal market power, absent compelling contrary evidence from interveners,” FERC explained.
Under the available economic capacity measure, which factors the utility’s own load into the calculation, Idaho Power’s HHI score was less than 2,500 in all 10 season/load levels. But under the economic capacity measure, its HHI exceeded 2,500 in all 10 season/load levels and “thus Idaho Power fails the market concentration test in every season/load level,” FERC said.
However, FERC noted its prior rulings had found that “failure of either the economic capacity or available economic capacity analyses does not result in an automatic failure of the test as a whole. The commission weighs the results of the economic capacity and the available economic capacity analyses and considers the arguments of the parties.”
“As the commission explained in Order No. 697: ‘[I]n markets where utilities retain significant native load obligations, an analysis of available economic capacity may more accurately assess an individual seller’s competitiveness, as well as the overall competitiveness of a market, because available economic capacity recognizes the native load obligations of the sellers,” FERC wrote. “On the other hand, in markets where the sellers have been predominantly relieved of their native load obligations, an analysis of economic capacity may more accurately reflect market conditions and a seller’s relative size in the market.’”
Given Idaho Power’s native load obligations, FERC found the available economic capacity measure — under which its HHI score was consistently less than 2,500 — more accurately reflected conditions in Idaho Power’s BAA.
“Based on the above discussion, there is no further need for the Section 206 proceeding instituted in Docket No. EL19-87-000,” FERC said. “Accordingly, we will terminate this Section 206 proceeding.”
The company formerly known as Vistra Energy — Vistra Corp. as of July 2 — boosted its second-quarter cash flow by 30% over 2019 and told financial analysts Aug. 5 that the best may be yet to come.
Vistra delivered earnings before interest, taxes, depreciation and amortization of (EBITDA) of $929 million, based on net income of $164 million. The company had an EBITDA of $717 million and net income of $354 million during last year’s second quarter.
Vistra uses adjusted EBITDA as a measure of performance, saying it improves visibility to both net income prepared in accordance with GAAP and adjusted EBITDA.
Luminant’s Odessa-Ector gas plant stands ready for possible scarcity pricing later this summer. | Luminant
CEO Curt Morgan reminded analysts during a conference call that “much of the Texas summer shows its teeth in August and September.” He noted that while Vistra’s generating subsidiary, Luminant, has not yet been able to take advantage of scarcity prices in the ERCOT market, last August saw 72 15-minute intervals over $1,000/MWh and 12 intervals reaching the $9,000/MWh cap.
“All it takes is one week of hot temperatures and either low wind output or an unplanned outage for scarcity pricing to materialize,” Morgan said.
At the same time, he warned investors about EPA’s recent regulatory revisions for utilities’ disposal of coal ash. (See “EPA Changes Closure Requirements in Coal Ash Rule,” Federal News.)
“Our evaluation suggests there are several coal plants, especially in PJM, that are under pressure due to this rulemaking,” Morgan said.
Vistra’s share price lost 50 cents during the day, closing at $18.26 on the New York Stock Exchange.
A new study finds that Bureau of Ocean Energy Management (BOEM) offshore wind area lease auctions over the next two-and-a-half years could initially pump $1.7 billion into the U.S. Treasury while potentially creating 80,000 jobs and $166 billion in capital investment through 2035.
“We’re talking about five lease areas, offshore New York, North Carolina, South Carolina, California and Maine, and these areas could unlock tremendous energy and economic potential,” Erik Milito, president of the National Ocean Industries Association (NOIA), said at a press conference Tuesday.
The report shows OSW development supporting approximately 80,000 jobs annually from 2025 to 2035. | Wood Mackenzie
NOIA commissioned the study by research group Wood Mackenzie with three other groups: the American Wind Energy Association (AWEA), the New York Offshore Wind Alliance (NYOWA) and the Special Initiative on Offshore Wind (SIOW) at the University of Delaware.
“From the NOIA perspective … there is a very strong synergy between offshore oil and gas and offshore wind … and the same shipbuilders, heavy lift vessel operators, steel fabricators and other companies who built the Gulf of Mexico oil and gas business stand ready to lend their expertise to the American offshore wind industry,” Milito said.
Feng Zhang, managing consultant for Wood Mackenzie’s power and renewables division, said the study mainly looked at areas from the New York Bight and south, plus California, but that interest was also “very high” in possible call areas in the Gulf of Maine.
“From the study, we found that if the relevant policy can be put in place, if BOEM and other industry parties can act very quickly, then potentially 2 million acres of federal waters in those areas can go to auction as soon as 2021 and 2022,” Zhang said.
Jump Starter
Additionally, the findings indicate that new offshore wind leases could be a short-term way to jump-start recovery from the economic slowdown caused by the coronavirus pandemic, Zhang noted.
The study found that investment in the country’s offshore wind industry will total $17 billion by 2025, $108 billion by 2030 and $166 billion by 2035.
“From 2022 to 2035, capital investment of $42 billion will go to turbine manufacturers and the supply chain, $107 billion will go to the construction industry and $8 billion will go to the transportation industry and ports. Annual capital investment for operations and maintenance activities will increase to $2.4 billion in 2035,” the study said.
Long-term, new OSW projects will provide 28 GW of new clean energy resources to power 20 million households and support 20,500 jobs annually for decades beyond 2035, the study found.
The other study sponsors issued statements lauding the economic and environmental benefits of OSW development.
“States along the eastern and western seashores have a massive domestic clean energy resource and many states have set ambitious offshore wind goals to reap the economic and environmental benefits that offshore wind offers but cannot achieve those goals with existing leases,” said NYOWA Director Joe Martens. “It’s time for the federal government to act with the same urgency as the states.”
“We’re on the cusp of a rare opportunity, but the U.S. remains far behind other countries in harnessing offshore wind technology,” said Laura Morton, AWEA senior director of offshore wind. “It’s time for us to unleash this abundant domestic energy source that will deliver tens of thousands of new jobs, revitalize coastal ports and expand manufacturing opportunities to reap major economic and environmental benefits.”
“Offshore wind development can be a major part of the solution to our country’s most pressing energy needs and our country’s most immediate economic woes,” said Nancy Sopko, executive director of SIOW. “Unleashing the potential of offshore wind power through immediate and consistent auctioning of new lease areas can help the United States rebound from the greatest economic downturn in our nation’s history.”
Exelon CEO Chris Crane on Tuesday apologized for subsidiary Commonwealth Edison’s involvement in a bribery scandal and said he may be forced to shut down the company’s Illinois nuclear plants without favorable state legislation.
In July, ComEd agreed to a $200 million fine with the Illinois U.S attorney’s office to settle allegations it bribed the state House of Representatives’ speaker in return for legislation that increased the company’s earnings and bailed out its money-losing nuclear plants. Under the Deferred Prosecution Agreement, the bribery charge will be deferred for three years and then dismissed, as long as ComEd continues to cooperate with “ongoing investigations of individuals or other entities.” (See ComEd to Pay $200 Million in Bribery Scheme.)
“We’ve taken robust actions to identify and address deficiencies, including enhancing our compliance governance, to prevent this conduct,” Crane said during a conference call with financial analysts. “We apologize for the past conduct, which did not live up to our values. These new policies will ensure it won’t happen again.
“We’re extremely disappointed with the seriousness of the past misconduct,” he said, listlessly reading his prepared comments. “We know many stakeholders understandably feel the same disappointment. We will take every possible step to earn back the confidence and trust we have lost. This will not happen overnight, and it will be a formidable task, but we’re resolved to get there.”
Crane said Chicago-based Exelon must restore the trust that “has been eroded” while, at the same time, working through legislative strategy in Illinois to help its nuclear plants earn capacity market revenue.
“It’s very critical for us to get it done,” he said, noting his “analytic folks” have a “strong sense” that Exelon’s nuclear units will not clear the next PJM Base Residual Auction.
“Some are uneconomic at this point right now, and some may become more uneconomic,” Crane said. “If we can’t find a path to profitability, we’re going to have to shut them down. We will not run plants and lose free cash flow or earnings on assets that are not supporting themselves. … We will not let the balance sheet [be] further [deteriorated] by non-profitable assets.”
Exelon has lost 14.7% of its stock value since the year began.
The company reported a “strong quarter” with earnings of $521 million ($0.53/share). A year ago, the company had earnings of $484 million ($0.50/share).
Exelon’s operating earnings of $0.55/share beat analysts’ expectations of $0.42/share, as gathered by Zacks Investment Research. The stock price gained 76 cents on the NASDAQ, closing at $38.75.
MISO’s participation model for electric storage resources needs a final edit before FERC declares the grid operator fully compliant with Order 841, the commission said this week.
FERC on Monday ordered MISO to remove or defend its requirement that distribution utilities and load-serving entities report real-time grid injections and withdrawals. FERC said MISO couldn’t impose reporting obligations on distribution utilities or LSEs because those companies aren’t party to its new pro forma storage participation agreement. FERC said MISO might require data reporting from companies that might not have “any relationship” with the grid operator (ER19-465).
“This reporting requirement is also unnecessary because MISO proposes to require the electric storage resource to report the same information,” the commission said.
FERC said it otherwise approved of MISO’s plan to make market participants responsible for meter installation, ownership, meter-data quality and “periodic testing of metering and related equipment.” The commission also found no problem with MISO’s requirement that storage owners report hourly real-time injections and withdrawal volumes at commercial pricing nodes or to estimate hourly injections and withdrawals if the energy storage resources don’t have a meter at a node.
| Connexus Energy
FERC in November found that MISO’s model largely complied with Order 841 but lacked detail about metering and accounting practices for distribution-connected and behind-the-meter ESRs. (See Storage Plans Clear FERC with Conditions.)
FERC’s latest order, however, rejected a group of Midwestern transmission-dependent utilities’ ask that MISO’s new pro forma agreement not be applicable to ESRs with on-site generation.
“Order No. 841 defines an ‘electric storage resource’ as a resource that can receive energy from the grid and store it for later injection back onto the grid. This definition does not specifically include or exclude, or otherwise discuss, electric storage resources that have on-site generation,” FERC said.
The commission also declined the Midwestern group’s request that it order MISO to make storage resources pay the Multi-Value Project (MVP) transmission charge. The charge funds the grid operator’s 2011 MVP transmission expansion portfolio and is allocated on a load-ratio basis to wholesale energy purchases. FERC agreed with MISO that storage resources should be exempted from the charge “because they do not consume energy as an end-use.”
“Even if the Tariff language and rate structure that existed prior to Order No. 841 allowed the assessment of the MVP charge to [ESRs] based on their monthly net actual energy withdrawals in a manner analogous to load, [ESRs] would still largely avoid the MVP charge because their withdrawals from charging would be mostly offset or netted by their discharging injections,” the commission wrote.
Finally, FERC accepted MISO’s explanation that ESRs should be excluded from qualifying as fast-start resources. The ISO said storage resources, as “offline energy-limited resources,” would “depress prices because they may be less feasible and less available due to state-of-charge management by the market participant.”
MISO has until mid-2022 to implement its ESR participation plan, as it will first have to build a new market platform.
FERC on Monday accepted most provisions in NYISO’s second attempt to comply with Order 841, which requires RTOs and ISOs to remove market barriers for energy storage resources (ESRs).
The decision specifically accepted proposed Tariff revisions to subject ESRs to transmission charges, effective no later than Sept. 30, but ordered the ISO within 90 days to clarify its proposed exemptions to such charges (ER19-467). The commission faulted the initial compliance filing for failing to apply those charges to ESRs when they are charging in the wholesale market for later retail sale but not providing services to the grid.
The commission also deemed NYISO’s Jan. 21 request for rehearing to be denied by operation of law.
Issued in 2018, Order 841 requires market participation rules to recognize the unique physical and operational characteristics of storage resources. The commission last December partially accepted NYISO’s compliance filing but faulted the ISO for lack of details on its metering methodology and accounting practices for ESRs located behind a customer meter. (See FERC Partially Accepts NYISO Storage Compliance.)
In its second compliance filing in February, the ISO proposed not to assess transmission charges to ESRs when the resource receives a real-time operating reserves schedule; receives a real-time regulation service schedule; is operating and is a qualified supplier of voltage support service; or is dispatched as out-of-merit to meet New York Control Area (NYCA) or local system reliability.
FERC accepted those provisions, but required NYISO to provide clarifications, saying that because these services are typically scheduled on top of a resource’s base energy schedule, it is unclear what portion of a resource’s megawatt withdrawals the ISO proposes to exempt from transmission charges, in particular of withdrawals during an interval when the resource is self-scheduled at a fixed megawatt quantity.
Pumped up
In its request for rehearing, NYISO argued that its proposed approach to not assess transmission charges aligns with its existing rate structure for transmission charges assessed to resources in the NYCA that withdraw energy at a node for later injection into the grid.
Specifically, NYISO said for more than 20 years it has applied a separate rate structure for transmission charges applicable to the 1,134-MW Blenheim-Gilboa Hydroelectric Power Station in the Catskills, a pumped storage facility owned by the New York Power Authority. The ISO argued that the station is located at a single generator bus that pays the nodal locational based marginal price (LBMP) to withdraw energy as a “negative injection” for later injection back into the grid.
NYISO wants to exempt resources like NYPA’s 1,134 MW Blenheim–Gilboa Hydroelectric Power Station in the Catskill Mountains from Order 841 transmission charges.
NYISO sought to apply the same separate rate structure to all nodal ESRs in in its jurisdiction and said that under Order 841, when such resources are marginal in the ISO’s dispatch of energy, loads in the NYCA would effectively be paying the related charges twice — once as part of the energy component of LBMP and again when NYISO and the relevant New York transmission owner assess charges to the loads.
But the commission said it was not persuaded by NYISO’s request for rehearing and continued to find the ISO has not demonstrated, as required in Order 841-A, that its proposal not to apply transmission charges to all ESRs is reasonable given how it assesses transmission charges to wholesale load under its existing rate structure.
“As a general matter, NYISO assesses transmission charges to all wholesale load, and it only declines to assess transmission charges to the withdrawals by one specific pumped storage facility when that facility is participating under the energy limited resource (ELR) model,” the commission said. “Thus, NYISO’s proposal not to apply transmission charges to any energy storage resource is not consistent with or reasonable given its existing rate structure, as contemplated by Order No. 841-A.”
The commission also said that NYISO’s double payment argument “is, in essence, a late-filed request for rehearing of Order No. 841 and is statutorily barred. Notwithstanding this procedural flaw, NYISO’s argument is also unpersuasive on the merits.”
Two different transactions occur, the commission said: “One that entails the electric storage resource purchasing charging energy at wholesale from the RTO/ISO market, and another that entails wholesale load purchasing energy from the electric storage resource via the RTO/ISO energy market. As such, we find that it is reasonable to apply transmission charges to both the electric storage resource and the loads associated with those separate transactions and for load to ultimately pay the two transmission charges.”
NYISO also argued that FERC’s rejection of its proposal was inconsistent with the commission’s acceptance of a CAISO proposal to exempt all ESRs from transmission charges when charging, consistent with CAISO’s existing rate structure.
Not so, said the commission.
“Unlike CAISO’s non-generator resource model, which was designed for electric storage resources, NYISO’s ELR model is designed for and primarily used by generators. Indeed, NYISO withdrew its ELR model from consideration for compliance with Order No. 841 because, according to NYISO, the ELR model could not accommodate withdrawals from ESRs.”
NYISO’s treatment of one pumped storage facility under the ELR model is thus a limited exception and not representative of how the ISO assesses transmission charges to wholesale load under its existing rate structure, the commission said.
Evergy has decided to stay single after dalliances with several potential acquisition partners, according to a published report.
Quoting “people familiar with the matter,” Bloomberg said Tuesday that the Kansas City-based company has decided to remain independent. Evergy has decided it can create more value for shareholders through a new operating plan, which had been in development while the company explored a possible sale, the report said.
The plan’s details are expected to be shared with financial analysts Wednesday when Evergy holds its quarterly earnings call before the market opens.
Evergy’s subsidiaries in Kansas, Missouri. | Evergy
Evergy’s share price plunged 13.4% after the Bloomberg story broke, from $62.81 to $55.40. It was trading at $55.79 as the market neared its close.
Evergy has been under pressure from activist investor Elliott Management, which took a $760 million stake in the company and has pushed it to shake up its management team. Evergy said in March that it had reached an agreement with Elliott to establish a new strategic review committee to explore ways to improve shareholder value. (See NextEra Said to be Eyeing Evergy as Acquisition Target.)
Ameren, American Electric Power, CMS Energy and NextEra Energy are among those linked to Evergy as potential buyers.
Evergy, an SPP member, was created in 2018 through a merger between Kansas City Power and Light and Westar Energy. It serves 1.6 million customers in Kansas and Missouri.
The Massachusetts Department of Energy Resources (DOER) said last week it will not require the state’s electric distribution companies to solicit proposals for a coordinated independent transmission network for the 1,600 MW of offshore wind energy already procured, but recommended bundling transmission in its next OSW solicitation.
“Following a thorough investigation, DOER finds that the costs and risks of a solicitation for independent offshore wind energy transmission outweigh the potential benefits that could be captured by 1,600 MW of transmission capacity,” Commissioner Patrick Woodcock said in a letter to the legislature’s Joint Committee on Telecommunications, Utilities and Energy. DOER said it feared the solicitation could delay upcoming OSW generation procurements and complicate contracting and permitting issues.
The purple line marks the cables and pipelines geographic analysis area for the Vineyard Wind project. | BOEM
Instead, the agency is recommending a bundled solicitation of 1,600 MW of generation and transmission, which it said could reduce cabling and use onshore interconnection points efficiently. The state — which has selected Mayflower Wind and Vineyard Wind 1 to build the first 1,600 MW of offshore wind in federal leasing areas south of Martha’s Vineyard — initially planned two additional 800-MW procurements.
DOER said that a larger solicitation for bids up to the full 1,600 MW currently authorized would allow developers greater flexibility in project design. First, a larger solicitation would allow developers the option of using HVDC cables, which can transmit up to 1,400 MW on a single cable versus 400 MW for HVAC cables, for offshore wind, the agency said. Second, a larger solicitation would allow developers the option to interconnect onshore at the maximum capacity allowed by ISO-NE (1,200-MW single contingency limit), which could help ensure that the limited number of onshore interconnection points in Massachusetts is used to maximum potential.
“In sum, a larger solicitation would give developers maximum flexibility to use transmission infrastructure efficiently, thereby helping ensure … bids that minimize the environmental and socioeconomic impacts of siting offshore wind structures in the ocean and on land and achieve many of the potential benefits of the independent transmission solicitation without the added costs and risks,” DOER said.
DOER also said it would consider joining with neighboring states on a backbone transmission plan.
A network transmission “initiative could be achieved more effectively at a larger scale of offshore wind build-out and with regional coordination among New England states … than through a single state procurement with limited size,” Woodcock said.
Comments in Favor
Recreation and tourism geographic analysis area for the Vineyard Wind project | BOEM
Massachusetts hosted a technical conference in March to explore whether it should solicit proposals for a transmission network for offshore wind generation. (See Mass. DOER Explores Transmission for OSW.) The planning choice was between generators developing the transmission — the generator lead line, or radial system — and independent transmission construction and ownership, or a network system.
The DOER letter noted significant stakeholder support for a networked or backbone-independent transmission approach at a larger capacity.
Included in a second round of stakeholder comments published April 22, State Rep. Patricia Haddad, speaker pro tempore of the Massachusetts House of Representatives, said in a letter to DOER that “we have been successful with the two recent offshore wind bids with generator lead lines. I feel the next procurement should include crucial shared transmission opportunities.”
The Responsible Offshore Development Association (RODA), a fishing industry group, submitted a letter urging independent transmission development if it would mean using less cable and having fewer environmental impacts.
Upping the Target
Meanwhile, the Massachusetts House amended its climate change bill Friday to increase the amount of offshore wind energy the state and utilities must contract from 3,200 MW to 3,600 MW. It also would cut the time between procurements from 24 months to 18 months.
Earlier last week, the Senate amended its economic development bill to mandate procurement of an additional 2,800 MW of OSW by 2035, which would raise total authorization to 6 GW.
The two houses will have to reconcile their differences in conference committee.
SPP‘s Board of Directors last week approved a staff recommendation that resolves six months of uncertainty over the weighting of futures in the 2021 transmission planning assessment.
Staff said a 50/50 weighting of the two futures in the 2021 Integrating Transmission Planning (ITP) study would acknowledge the lack of consensus over each future’s relative probability. They also suggested that any project that could not be justified under a 60/40 weighting be highlighted for further consideration.
The Markets and Operations Policy Committee earlier in July rejected the 50/50 weighting and two other suggestions during its third fruitless attempt to approve an issue that left stakeholders flummoxed. (See “Members Unable to Agree on Weighting Futures in 2021 Tx Plan,” SPP MOPC Briefs: July 15-16, 2020.)
The Economic Studies Working Group (ESWG) in January recommended a 60/40 split between Future 1 and Future 2, respectively. The “business-as-usual” Future 1 reflects current trends, while the “emerging technologies” Future 2 case assumes that distributed generation, demand response, energy efficiency and energy storage will have a major effect on load and energy growth rates.
The Members Committee approved the recommendation 13-5, with a mix of transmission owners and users in opposition.
Stakeholders have struggled over Future 1’s assumption of 32 GW of installed wind capacity in 10 years and where the primarily renewable resources would be sited. SPP has said it will have 27 GW of wind capacity by the end of this year.
Oklahoma Gas & Electric’s Greg McAuley, one of five members to oppose the motion, advocated for a 70/30 weighting of the futures that leans more toward uncertainty.
“If you assume solar begins to expand at the same rate wind has over the last 10 years, is it reasonable to assume that expansion will take place in similar locations or be closer to load?” he asked. “These assumptions about resources, without associated firm transmission, kind of leaves us exposed. We will have built transmission to accommodate resources no longer available to the market.
“If you put transmission in the ground, we’re committed to it. Our customers will be paying for those facilities for a long time,” McAuley said.
Board Chair Larry Altenbaumer | SPP
SPP Vice President of Engineering Antoine Lucas pointed out that either weighting would not have affected the last three ITPs’ project portfolios.
“The best way to address this is to focus more on the sensitivity analysis of individual projects and the assumptions that drive the benefits for those projects,” he said. “If [a project] says more wind [will result], we believe we should run sensitivities around it and test the assumptions. We already do that, whether it’s the amount of wind or fuel prices.”
“What staff has proposed is to basically provide all of us with a bit of a safety net,” said Board Chair Larry Altenbaumer during the July 28 web meeting. “If there is something that is justified in the 50/50 weighting, but not in the 60/40, that allows us to dig into more detail to understand the ramifications, [then] this has taken us a step in the right direction, while recognizing there are more steps we need to take.”
Agreement on Competitive Project’s Path Forward
Stakeholders were able to reach an agreement over the suspension of a competitive project that SPP agrees would provide numerous benefits to the eastern edge of its footprint, where congestion remains a problem.
Several members wanted to lift the suspension and issue a request for proposals. However, staff cautioned the move would open a seven-day window during which they would have to issue the RFP. The RTO would also be within an 18-month window to issue funds for the project.
The 345-kV Wolf Creek-Blackberry project in Kansas and Missouri with Associated Electric Cooperative Inc. (AECI) was approved by the board last year and was included in the 2020SPP Transmission Expansion Plan passed in January. Part of the 105-mile project, projected to cost $152 million, would be on the AECI transmission system and constructed by the cooperative. SPP cannot allocate funds to AECI without FERC approval.
The board in April suspended the project, pending negotiations with AECI and FERC’s approval of a cost-and-use agreement. Staff said AECI has reached a verbal agreement but has not yet provided SPP a signed document. (See “Directors Suspend Competitive Upgrade,” SPP Board/Members Committee Briefs: April 28, 2020.)
General Counsel Paul Suskie said several risks preclude lifting the suspension. “First, whether or not we can reach a timely agreement with AECI,” though he admitted an agreement is expected within days.
Other risks include FERC’s perspective after a pre-filing meeting with commission staff and potential protests that could delay a final order, Suskie said.
“Once an agreement is signed and filed at FERC, we’re in a much better position when we see whether any protests are filed,” he continued. “The risks are further minimized as we move further out on the timeline.”
Altenbaumer suggested members wait until the agreement is executed and filed with FERC “as soon as possible.” That would open a 20-day period for any protests, during which time SPP staff could prepare the RFP.
“One thing I’m concerned about is if challenges are made to that filing, and not knowing what those objections are or FERC’s action on that filing, and how they could undercut the AECI agreement,” Altenbaumer said. “We will then have been out there with an RFP that would not be a viable RFP.”
By late August, he said, “we’ll know … more information than where we are with the FERC filing.”
“We can work with you on trying to find a path forward,” said Evergy’s Denise Buffington, who helped pen a letter from four member utilities asking that the suspension be lifted. “Keep in mind this project is likely to be delayed even if the RFP is issued by Oct. 1. We are looking for an outside date of Oct. 1, and the path you have outlined will accommodate that.”
Evergy was joined by American Electric Power, Liberty Utilities and City Utilities of Springfield (CUS) in asking the directors to issue the RFP no later than Oct. 1. The signatories said the suspension’s initial rationale was that the cost of the AECI Blackberry termination point was unknown and noted that “these costs are now known, negotiations are complete, and the [agreement] … is about to be filed.
“Because of the critical importance of the proposed line and the benefits provided to SPP customers, the board should not further delay the RFP process,” the companies wrote.
“We own the Wolf Creek substation. It will take a minimum of four years to get work done inside the substation. The longer the delay on the NTC, the less likely we will get that in time,” Buffington said during the discussion. “We’re also worried there will be protest … we think the FERC proceeding should run in parallel with the RFP. All the information needed to issue the RFP is available to SPP today.
“As the letter points out, there are a bunch of reliability issues at stake,” she said. “This project was very, very close to being a reliability project. If it gets restudied, it could be a reliability project.”
Board OKs 4 HITT Recommendations
The board and members approved four recommendations stemming from last year’s Holistic Integrated Tariff Team report, bringing the total of completed recommendations to eight out of 21.
The board sided with MOPC and the ESWG’s recommendation to keep the ITP’s benefit/cost ratio for economic projects at 1.0, rather than increase it to a range between 1.05 and 1.25. Members approved the recommendation by a 15-5 vote.
Golden Spread Electric Cooperative’s Mike Wise, one of those opposed to the 1.0 B/C ratio, said transmission buildouts are “problematic” going forward when looking at benefits and costs.
“The costs are well-known ahead of time. The real issue here is [that] the benefits are estimated and not well-known,” he said. “[The benefits] are engineering estimates 40 years into the future. It’s really difficult to grasp the benefits that come from this.”
Wise found support from McAuley and Oklahoma Municipal Power Authority’s (OMPA) David Osburn.
“This is yet another example of where we are, as Mike would put it, doing this as usual, when business is anything but usual,” McAuley said. “At what point do we stop building transmission, so our transmission rates stop going up?”
“I want to stress the point [Mike] made is very valid,” Osburn said. “We make these decisions and invest in 40-year assets. We’re spending consumers’ money here, and I think they would like to see a benefit-to-cost ratio much greater than one, and one that doesn’t take 40 years to get there.”
While Dogwood Energy’s Rob Janssen and NextEra Energy Resources’ Holly Carias supported the motion, they agreed the motion warrants further analysis.
“Greg made a good point about looking out at the future and looking at economic projects more broadly,” Janssen said.
“I can’t disagree with Mike Wise and Greg that we’re in a different scenario,” Carias said. “We need to reconsider benefits.”
The board also signed off on the Cost Allocation Working Group’s white paper that evaluated SPP’s cost allocations for transmission projects between 100 and 300 kV that are primarily used to move power out of the local transmission pricing zones.
The Members Committee approved the motion to accept the white paper by an 11-5 vote. CUS, OG&E Transmission, OMPA, Public Service Co. of Oklahoma and Xcel Energy’s Southwestern Public Service Co. (SPS) opposed the motion.
The Regional State Committee earlier voted to endorse the white paper by a 6-5 margin.
SPS President David Hudson asked that the minutes reflect that the white paper “is a controversial issue.”
Kansas’ Sunflower Electric Power is among those that stand to benefit from the paper’s recommendation to establish a “narrow” cost-allocation review that regionally distributes the revenue requirements for the lower voltage levels. Sunflower CEO Stuart Lowry said that while the review would grant waivers from the methodology, “by no means is that a guarantee a waiver will be granted.”
“We would have to make that case before MOPC and the Board of Directors,” he said. “Bear in mind that action today does not mean byway cost-allocation relief will be granted to Sunflower or anyone else.”
Members unanimously approved two other HITT items, a staff report on essential reliability services (ERS) and other reliability services (ORS) and a revision request (MWGRR402) that improves the Integrated Marketplace by using near real-time economic dispatch to evaluate intraday reliability unit commitment for committing fast-start resources near real time.
The ERS/ORS report evaluated the region’s reliability challenges with a changing resource mix by conducting three separate engineering studies on reactive supply, primary frequency response and flexible capacity supply. The Market Working Group will now be asked to work on an ERS/ORS compensation mechanism.
Gaw’s Voice Becoming More Prominent
Advanced Power Alliance’s Steve Gaw, a ubiquitous presence at SPP meetings for more than 17 years, took some good-natured ribbing when his name mistakenly appeared on a Members Committee list as the board meeting began.
“Steve Gaw … that’s a strange name,” Altenbaumer said, taking a jibe at SPP’s newest member representative. “I’m not sure why he’s on the list, but we’ll let it go this time.”
A former chair of the Missouri Public Service Commission, Gaw was among the founding members of SPP’s Regional State Committee in 2003. He has since frequently voiced the wind industry’s concerns in stakeholder meetings, taking advantage of SPP’s practice of allowing non-members to add their input during discussions.
When Gaw commented during the ITP futures weighting discussion, he first asked whether he could be heard.
“I hear you fine. I’ve never had a problem hearing you, Steve,” Altenbaumer responded.
The APA, an industry trade association supporting renewable generation and energy storage in SPP and ERCOT, recently joined the RTO as its first alternative power/public interest member. As a member, the organization now has a vote and can officially join stakeholder groups. (See “Advance Power Alliance Now an SPP Member,” SPP Briefs: Week of July 20, 2020.)
SPP said a clerical error resulted in Gaw’s name being included among the Members Committee’s list of 21 names. The Corporate Governance Committee must first nominate Gaw as representing the alternative power/public interest sector and the nomination be approved before he can cast a vote.
“I can only speak, “Gaw said later, noting he was invited to the board and committee’s executive session.
No Virtual Roll Call
With more than 250 persons calling in to the webcast, SPP’s Dustin Smith, who facilitated the meeting, declined to take attendance through a roll call.
“That’s virtually impossible to do virtually,” he said.
Consent Agenda Passes
The board’s consent agenda included approval of:
The Finance Committee’s 2021 operating plan, which includes developing a strategic plan for the next five years, implementing the HITT recommendations and completing generator-interconnection study requests from 2019 and before.
MOPC’s approval of RR404, which further defines the resource adequacy requirements for demand response programs and behind-the-meter generation, and its recommendation for a $20.7 million cost reduction to Basin Electric Power Cooperative’s Multi-Kummer Ridge-Roundup project in North Dakota.
A waiver of financial obligations under the membership agreement to East Texas Electric Cooperative for its transfer of transmission facilities and load from MISO to SPP and from SPP to ERCOT. The cooperative transferred facilities and load from MISO last year and is scheduled to transfer facilities and load to ERCOT between October and January. ETEC requested the waiver because it will wind up transferring more load into SPP than out, which would have triggered a partial termination.
Staff’s recommendation for out-of-cycle re-evaluations for notifications to construct an Evergy Metro 161-kV project in the Kansas City area and an OG&E 138-kV project.
Appointment of Omaha Public Power District’s Joe Lang to an open transmission owner’s seat on the Human Resources Committee. He replaces Nebraska Public Power District’s Tom Kent, who in March was promoted to CEO.
CAISO’s proposal to develop new capacity products through its day-ahead market enhancements (DAME) initiative could radically transform California’s resource adequacy landscape while not yielding expected benefits, a key skeptic of the plan said last week.
“I agree that in the vast majority of situations having a market price is an extremely valuable thing [and] I’m not trying to come down on either side of this one right now. I’m just saying it’s a philosophical change in the way these [RA resources] are being paid that we should think about,” Mike Castelhano, an analyst with the California Public Utilities Commission, said during discussion of the proposed capacity products at a CAISO Market Surveillance Committee (MSC) meeting Thursday.
The ISO launched the DAME effort earlier this year to expand its day-ahead market with two new nodal product offerings that would significantly alter market operations:
a reliability capacity (RC) “up/down” product to help the ISO match its net load forecast (the load forecast minus the variable energy resource forecast) with sufficient non-VER supply for one-hour intervals; and
an imbalance reserves (IR) product procured for 15-minute intervals “to provide flexible capacity to accommodate the increasing uncertainty and variability of real-time net load.”
Both products would be offered on a nodal basis, an approach CAISO thinks will best guarantee those supplies will be available when and where they’re needed to ensure flexibility on a grid increasingly dependent on VERs. The DAME straw proposal envisions co-optimizing procurement of both new products — along with day-ahead energy and ancillary services — to improve scheduling efficiency.
Graph illustrates price differences for the same intervals among CAISO’s day-ahead (blue), hour-ahead (orange), 15-minute (green) and 5-minute markets (purple). The ISO’s DAME initiative is particularly aimed at closing the discrepancies between day-ahead and 15-minute prices. | CAISO
That new process would replace the existing residual unit commitment (RUC) process for ensuring resource sufficiency, in which the day-ahead market procures the incremental capacity needed to meet reliability requirements after the ISO has run its co-optimized integrated forward market (IFR) for day-ahead energy and ancillary services. The incremental capacity obtained through RUC represents the delta between what the IFR has cleared from economic bids and “the amount needed for reliability based on the net demand forecast and potential uncertainty,” the ISO notes in the straw proposal.
“The disadvantage of this sequential RUC process is that the capacity it procures is not co-optimized with the resource commitment and energy schedules produced by the integrated forward market,” CAISO said in explaining the move to the new model.
‘Vanilla’ RUC vs. Spot Market
While CAISO has counterposed two methods for compensating suppliers of the two new products, it clearly favors one option over the other.
Under the “vanilla RUC model” (as ISO Market Design Policy Specialist James Friedrich put it), resources that have been awarded contracts under the CPUC’s RA program could offer into the market at zero price and forego being paid market clearing prices for RC and IR. In that scenario, CAISO would assume the prices of RA contracts — which subject holders to a must-offer obligation (MOO) in the ISO market — “would, in part, reflect owner expectations about magnitudes and frequency of short-run costs incurred to provide RC/IR.”
According to the ISO, the RUC model approach to compensating the new capacity products would be the least disruptive to California’s current RA system because it wouldn’t require renegotiation of existing RA contracts, changes in CPUC rules around cost recovery for RA assets or revisions to CAISO’s MOO Tariff provisions. It would also avoid the need to mitigate market power for RC/IR offers.
Those advantages notwithstanding, CAISO — and the MSC — are advocating implementing a “spot market model” as much as possible to compensate providers of the new capacity products, with the hope that short-term market offers will more precisely reflect variable costs for making capacity available, including natural gas costs and the opportunity costs of not bidding into the real-time market. That arrangement would provide suppliers a stronger incentive to make resources available, according to the MSC.
Use of that model would also eliminate the must-offer obligation for contracted RA resources, which should reduce the number of zero-price offers and increase clearing prices (while also increasing the risk of double-payment before RA contracts can be renegotiated, CAISO acknowledged). That would have the upshot of opening up California’s capacity market to non-thermal resources, helping the state achieve its ambitious carbon reduction goals, one MSC member noted.
“One of the characteristics of the current design is that … demand response can’t compete to provide RUC capacity because thermal RA units are free,” said the MSC’s Scott Harvey. “And they’re not really free, but it gets rolled into the RA price, so you don’t see a separate price signal for [whether] demand response [could] provide this RUC capacity, which is really back-up capacity that we don’t need but we want to have in reserve in case we do need it. And that’s probably an ideal role for demand response … so that’s another long-run goal that could be achieved if we make this change.”
MSC member Jim Bushnell said a long-term focus of the committee is providing “short-run marginal incentives to reward units that provide truly valuable reliability capacity” and incentivizing resource availability.
“The problem with RA has been that we don’t know a year in advance and a month in advance exactly when and what types of units provide what type of value. That’s constantly changing, so the importance for short-run incentives is large here,” he said.
CPUC Concerns
CPUC’s Castelhano said he understood Harvey’s concerns about DR being unable to function as RA capacity in the CAISO market. But Castelhano noted that the RA zero-bid requirement is a CPUC capacity designation rule and not “really a RUC rule.” He cautioned CAISO against making changes that could alter the zero-bid practice in the wholesale market or pushing to revise market rules in a way that would allow DR to function as RA in California.
“The rules for RA and DR are not as well-developed, and that’s a process that’s ongoing, and I think we have to recognize that’s not something that should change at the CAISO necessarily,” Castelhano said.
“I wasn’t arguing for a change in the rules regarding DR that is RA capacity,” Harvey said, clarifying that his focus is on enabling DR — “whether or not it’s RA capacity” — to compete to provide RUC. “That’s the CAISO issue.”
Castelhano also called out CAISO for not discussing how transformative the ISO’s changes could be for California RA, potentially transforming the program from a structure based on contracts to one reliant on a spot market.
“Sure, it gets the costs out of the RA contracts, potentially, but it also then pays a market mechanism-based price to everybody that clears in that market, whereas right now the RA costs are individual” and cost based, said Castelhano. A system based on a clearing price could allow some suppliers to earn inframarginal rents — where a supplier gets paid above its costs in an otherwise competitive market.
MSC Chair Ben Hobbs acknowledged that consumers could benefit if the utilities contracting for RA hold prices down because of monopsony market power and pass on those savings. But he said it is not clear that would happen because visibility into RA contract prices “is not exactly a strong point” in California’s market.
“RA contracts tend to be near some market-clearing level, but from an efficiency point of view, hearkening all the way back to the early days of the California market of pay-as-bid versus market-clearing price, folks who have been on the MSC have tended to favor [a] single market-clearing price for its transparency and incentives,” Hobbs said. “But you might have a point. If the utilities can price-discriminate on RA perhaps there will be less ability to do that in the future, which might conceivably increase what consumers pay and provide more of the inframarginal rents to resources.”
Castelhano also questioned CAISO’s presumption that the new capacity products would reduce some of the “guesswork” behind calculating the costs of RA contracts because income for RA resources would be based on actual short-run costs rather than on a longer-term estimation of those costs.
“My speculation is that it would go very much in the opposite direction because right now part of the RA contract depends on one variable stream of income from sales into the ISO market, and you’re going to create another possibly more variable stream of income,” he said.
Hobbs countered that the proposal’s provision allowing RA resources to buy out their must-offer obligation or bid costs in the ISO market would reduce the cost risks of having a fixed MOO negotiated far in advance of potential deliveries.
“I guess that needs some more analysis, but I don’t agree with what you’re saying there,” Hobbs said.
Castelhano concluded with “a really big concern” that CAISO is considering limiting the participation of energy storage resources in the imbalance reserve markets. He noted that the CPUC’s integrated resource planning process is assuming that storage resources will play a key role providing flexibility needed to integrate variable renewables.
“If [storage] resources are not able to participate in this imbalance reserve market, then I’m very concerned about that,” Castelhano said. “If we’re paying hourly dispatchable resources instead of the stuff that can move really fast, then that’s another concern.”
