Page 1003 – RTO Insider

December 22, 2020January 15, 2025

SPP Out to Improve Competitive Tx Selection

Following the awarding of its second competitive project in four years, SPP has begun gathering stakeholder feedback as staff works to again improve its project selection processes under FERC Order 1000.

“We’re trying to mirror this process similar to what we did in 2016,” General Counsel Paul Suskie said during a webinar with stakeholders Friday.

Now, as in 2016, staff will gather member suggestions to improve its Order 1000 processes and other written comments, with a Dec. 29 deadline. The Markets and Operations Policy and Strategic Plan committees will coordinate the information before the January governance meetings, with a task force likely to be formed to present final recommendations to the Board of Directors.

SPP created a similar task force to improve its competitive transmission practices after its first Order 1000 project was canceled because of falling load projections. The task force’s chief recommendation was to allow re-study requests before issuing a notification to construct (NTC), which would have identified the change in load sooner. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

“We knew we had to re-study, but [following the Tariff] we had to wait until the NTC was filed,” said Ben Bright, SPP manager of regulatory processes. He said the task force helped implement about half the 56 suggested stakeholder changes before it was disbanded in 2018.

The Sooner-Wekiwa project, running west of Tulsa | SPP

The board in October approved an industry expert panel’s (IEP) recommendation to grant SPP’s second competitive project, the 75-mile, 345-kV Sooner-Wekiwa project in Oklahoma to Transource Missouri, the panel’s “designated transmission owner. (See Transource Tapped for SPP’s 2nd Competitive Tx Project.)

SPP selects a five-person IEP, based on its expertise in engineering design, project management construction, operations, rate analysis and finance, to evaluate project proposals in those categories. Developer proposals submitted as detailed project proposals under SPP’s transmission owner selection process qualify for incentive points during the scoring.

Five entities — Transource, Xcel Energy Southwest Transmission (the Sooner project’s alternate builder), Liberty Utilities, LS Power-Southwest Transmission, and City Utilities of Springfield (Mo.) — have already submitted 18 proposals and staff added 13 more.

LS Power’s Pat Hayes suggested that the process of granting incentive points is “broken,” given the staff burden to evaluate proposals that number in the hundreds. He called for Tariff revisions requiring the IEP to justify its recommendation according to the projects’ efficacy and costs.

“The goal of the TSOP should be to deliver more efficient and cost-effective projects,” he said. “If it’s causing excessive costs and inefficiencies on SPP staff in the initial stage, we need to do something different. We think the easiest alternative is to scrap the incentive points altogether. There has to be some way to reduce the number of solutions and ideas.”

Bright said that after discussions with engineering support staff, SPP would “probably” recommend the removal of incentive points.

“If there’s a way to improve and provide value, we certainly want to have those conversations,” he said.

Bright said staff is also interested in revising the templates used in project submissions. He said the granular nature of confidential information resulted in a lack of transparency.

“The public version of the reports showed there wasn’t much there [behind the redactions],” he said. “It would be nice to differentiate publicly one proposal from another.”

LS Power and Xcel Energy both proposed changes to the intricate scoring matrix, which resulted in Transource winning the Sooner bid despite turning in the three most expensive proposals. They called for RFP respondents to be provided with details on how the IEP will evaluate and score their submissions.

Other suggested improvements included adding a resiliency metric and offering unsuccessful bidders an opportunity to meet with staff and review the strengths and weaknesses of their proposals.

Affected Systems Issues

Staff also visited with the Seams Steering Committee (SSC) and the Generation Interconnection Users Forum during their meetings last week to gather feedback on SPP’s affected system studies.

Staffer Jon Langford told the SSC that SPP is experiencing a “couple of core issues” in the affected system studies it uses to determine the effects of non-jurisdictional and neighboring interconnection requests on its transmission system. He said neighboring entities, transmission owners and customers have expressed concerns over the RTO’s interconnection queue priorities and the transmission services it studies.

Affected system studies are currently performed when needed and separately from SPP’s GI requests. They account for interconnection requests on neighboring grids, including MISO, Associated Electric Cooperative Inc. (AECI), Minnkota Power Cooperative and Northwestern Energy.

Langford said neighboring transmission providers and planning coordinators typically agree on a defined queue priority in their joint agreements. As an example, he said SPP’s priority practices with AECI are not documented.

“The big questions are those affecting our ability to respond to affected system study requests in a timely manner,” said SPP’s David Kelley, director of seams and Tariff services. “That’s creating disputes and consternation, if you will, from customers on both sides of the equation.”

The committee agreed to revisit the subject at its meeting Jan. 7. Staff hope to have a recommendation to bring before MOPC later in January.

SPP Faced with 3 Planning Studies

Any work on coordinated system studies with MISO and AECI will have to wait, staff told the SSC on Wednesday, as SPP is working on three different transmission planning assessments.

SPP’s planning staff is busy with three different transmission studies. | SPP

“Obviously, there’s a very full workload amongst all of the planning staff. It’s going to be crucial we don’t duplicate work,” SPP’s Neil Robertson said.

Staff are well into work on the 2021 and 2022 studies and the 20-year assessment. The long-term assessment is scheduled to be completed in 2022.

December 22, 2020

CAISO Board Fields RA Measures, Big and Small

CAISO’s Board of Governors voted Thursday to keep a small, older natural gas plant operating to maintain reliability and received a briefing on initiatives to revamp the ISO’s resource adequacy construct.

Both were part of CAISO’s push to prevent energy emergencies next summer like those that struck the state in August and September.

In an unusual request, management asked the board to approve a reliability-must-run (RMR) designation for two units at the Midway Sunset Cogeneration facility, a 250-MW plant built in the late 1980s in a Kern County oilfield.

The units were scheduled to retire at the end of this year. A third unit was already mothballed, but CAISO said the two remaining units may be necessary to help keep the lights on in the world’s fifth largest economy.

The plant can contribute to meeting demand in summer heat waves in the net-peak hours, when California’s solar resources ramp down but demand remains high in the evening. Rolling blackouts in mid-August and close calls over Labor Day weekend occurred during net-peak times. (See CAISO CEO Defends Blackouts Response.)

CAISO Resource Adequacy — The Midway Sunset Cogeneration plant sits in a Kern County oilfield.

“The Midway Sunset Cogen is required for the ISO to meet the 2021 systemwide reliability needs due to capacity insufficiency at the net-peak hour during the months July-September 2021,” Neil Millar, vice president of infrastructure and operations planning, wrote in a memo to the board. “Accordingly, the ISO cannot allow the resource to retire or mothball because, absent these units, it faces an inability to meet reliability criteria during these months.”

Stakeholders, including Pacific Gas and Electric, protested the lack of process in the decision and the rush to designate the plant as an RMR resource. Board Chair Angelina Galiteva acknowledged their concerns but said “reliability trumps” all other considerations with just days before the plant’s scheduled shutdown.

Stakeholder Initiatives

On a larger scale, CAISO is prioritizing stakeholder initiatives to promote resource adequacy in 2021 and 2022.

“This is important to ensure we are ready for next summer’s heat events,” Anna McKenna, interim head of market policy and performance, told the board.

Changes in the annual update to the ISO’s three-year policy initiatives roadmap focus on the urgent need to “comprehensively reform resource adequacy requirements” in connection with the shift from fossil fuels to renewables and tightening supply across the West.

They include a redesign of the ISO’s resource adequacy construct, Greg Cook, executive director of market and infrastructure policy, said in his presentation.

The efforts will try to ensure there is sufficient supply to serve net-peak load in heat waves and provide an adequate planning reserve margin, which CAISO wants the California Public Utilities Commission to increase from 15% to 20%.

A new workshop will try to make sure exports do not occur during times of tight supply, as occurred during the August blackouts. And the ISO is seeking to bring new storage resources online by the summer and ensure that imports are backed by specific out-of-state resources.

Many of the issues addressed in CAISO’s slate of initiatives were identified in a preliminary root-cause analysis of the summer blackouts sent to Gov. Gavin Newsom in October. (See CAISO Says Constrained Tx Contributed to Blackouts.)

December 22, 2020January 15, 2025

Study Proposes New Capacity Treatment for Oregon

Oregon should recognize the capacity contributions of all resources including variable renewables, according to a new report commissioned by the state Public Utilities Commission.

The report from consulting firm Energy and Environmental Economics (E3) counsels the PUC to adopt a plan based on methods already familiar to market participants in Eastern RTOs. These include use of demand curves to adjust capacity prices and measuring the marginal capacity contributions from renewable resources based on effective load-carrying capability (ELCC).

The E3 report seeks to answer a key question the PUC posed in April 2019 when it initiated an investigation (UM 2011) into a “comprehensive approach” to recognizing the capacity contributions of the various resources in utility integrated resource plans (IRPs): How should capacity be valued?

“The capacity provided by a resource to the electric system plays a central role in determining that resource’s overall value and therefore informs fair compensation to that resource,” the PUC wrote then. The growing penetration of variable energy resources “requires an examination at how capacity from various resources should be valued.”

The PUC said its existing programs have dealt with capacity valuation on a “piecemeal” basis, using different methodologies to account for capacity from utility-scale generation, distributed resources, energy efficiency, storage and demand response. At the same time, variable resources were short-changed by receiving “little to no credit” for their contributions to peak needs.

“A holistic investigation into these issues related to capacity could lead to a harmonization of some of these disparate approaches,” the PUC said.

The regulator pointed out that capacity valuation can play a role in the implementation of time-of-use rates or in evaluating programs such as demand response that can avoid or postpone investments in new resources.

“Other program benefit evaluations where capacity value needs to be considered include transportation, electrification and energy storage,” the PUC said.

Marching Down the Decarbonization Curve

“I think we’ve all seen across the West what can happen when capacity planning doesn’t quite go to plan,” E3 Director Zachary Ming said during a PUC-hosted video call Thursday to explain the capacity valuation report. “I’m really happy to be part of this proceeding that’s happening in Oregon to try to make sure the state gets ahead — and stays ahead — of the curve on this capacity issue that’s becoming more and more important with every year as we march down the decarbonization curve.”

Ming offered a primer on concepts that might be unfamiliar to Westerners not steeped in the organized capacity markets prevailing in the East.

The study’s authors asked two questions in their effort to identify a capacity compensation scheme: How much capacity in megawatts can any one resource provide? And for any megawatt of capacity, what is the value of that capacity to the system?

“Once you answer those questions, then you can set a dollar value,” Ming said. Any compensation framework should “appropriately measure” the quantity and value of the capacity a resource is providing, he said.

Ming said ELCC is the “gold standard” for measuring a resource’s contribution to maintaining the one-day-in-10-years loss of load probability (LOLP) principle typically recognized as the basis for gauging system reliability. ELCC allows for a comparison between different types of resources and measures the “perfect capacity” from each that would provide equivalent system reliability. For example, based on operating characteristics, a 100 MW solar plant and 50 MW gas-fired plant would each be capable of providing 50 MW of capacity.

Measuring the ELCC of a resource such as solar can become particularly tricky, Ming said. Under the concept of “antagonistic pairings,” resources with similar limitations reduce each other’s ability to provide capacity, something that occurs when more solar plants are added to an already solar-heavy system. In contrast, the “synergistic” pairing of resources with different characteristics, such as solar and storage, improve each other’s ability to provide capacity.

Regulators might have reasons for applying ELCC in different ways, Ming said. To assess overall system reliability, a “portfolio ELCC” approach can be used to capture the combined capabilities of all resources on the system. A “last-in ELCC” approach can capture the marginal ELCC of the next unit of a variable or energy-limited resource, an important tool when trying to understand how a newly procured resource will contribute to system capacity needs.

The industry widely uses simplified “approximation metrics” to reduce the complexity of estimating ELCC, Ming said. Among the most common is use of hourly LOLP to gauge ELCC. Historically, LOLP hours have been almost “exactly correlated” with peak load hours, he said.

“Resource availability wasn’t really an issue [in the past]. All resources — you could turn them on and off; you could run them for as long as you wanted. The only issue of not being able to meet load is if load got too high, which happened in peak hours or during extreme weather years,” Ming said.

Increased adoption of renewables, especially solar, means that LOLP has shifted into the evening hours when load is actually falling but the volume of energy produced is also declining with the setting sun.

“In today’s system, you see this most notably in California, although Oregon is headed in this direction, the loss of load probability hours have shifted [to] both later in the day and later in the summer,” Ming said.

He said the monetary value of capacity should be rooted in the principle of avoided cost. “A resource should be provided no more compensation than the least-cost resource that can be procured by the utility that provides equivalent reliability.”

To keep costs in check, the report proposes that Oregon policymakers adjust capacity prices based on a sloped demand curve “similar” to those used in organized capacity markets. That would enable the regulator to increase the value of capacity as the system moves from periods of resource sufficiency to deficiency. During times of sufficiency, the capacity value might reflect only operations and maintenance costs. In periods of deficiency, the value might rise to the net resource cost (similar to net cost of new entry), which reflects the total cost of building, integrating and operating a resource minus the revenue it earns from energy and ancillary services.

Different Strokes

Acknowledging the difficulty of creating a single capacity compensation framework for all resource types, E3 instead recommended two broad approaches.

Dispatchable resources such as gas-fired plants would earn payments based on a fixed annual value determined by its MW capacity credit multiplied by the $/MW-year value of the capacity. Resources paid under this “fixed payment” scheme would be subject to penalties for lack of performance during critical periods.

A “pay-as-you-go” scheme would compensate variable renewables based on performance during peak demand or capacity scarcity hours. The plan could be structured to either pay resources dynamically during only periods of system stress, or it could “send a consistent pre-determined price signal for all hours that have a higher” LOLP, E3 said. The plan would avoid subjecting variable resources to an “undue performance requirement,” Ming noted.

Because of their dispatchability, storage resources would fall under the fixed payment scheme, with compensation based on the product of the “last-in” ELCC and the monetary value of capacity.

“Performance would be measured by having the utility send a signal to the storage resource based on its capabilities. If it responds, it won’t be assessed penalties,” Ming said. Using pay-as-you-go to compensate storage could be “potentially discriminatory” because it could require the resource to cycle every day to receive payment. It also avoids compensating a storage resource when it’s not actually needed for capacity.

Like storage, demand response resources would receive fixed annual payments. Because DR has more limitations than storage, performance requirements would be based on a resource’s “inherent capabilities, identical to what is used in its ELCC calculation.”

For hybrid resources, E3 proposed a “bifurcated” scheme in which the renewable portion of the resource would be compensated under pay-as-you-go while the storage portion receives a fixed payment. “We do not think that a fixed payment only is appropriate for hybrids for the same reason it’s not for renewables,” Ming said.

‘Deliberately Provocative’

Fred Heutte, senior policy associate with the Northwest Energy Coalition, asked what E3 meant by “dispatchable” resources. Heutte noted that E3 had performed a study for Tampa Electric showing that solar can be dispatchable in providing incremental and decremental energy, providing load-following capability.

“It’s not something commonly done right now, but it’s certainly possible. Is that what you mean by dispatchable or is there something else?” Heutte asked.

“I think for the purposes of providing non-capacity services to the system, dispatching solar can be useful, like providing ancillary services,” Ming responded. “From a capacity perspective, I don’t know that I’d consider solar dispatchable, but it’s a term of art; there’s a gray line, of course.”

Dispatchability is really a function of how a capacity resource responds within its compensation framework, Ming continued. Solar will provide as much energy as it can when it’s producing to meet capacity needs.

“Storage is going to provide energy when [the grid operator] sends a signal to dispatch, and to that extent the compensation framework impacts how storage is dispatched. The compensation framework does not impact how solar is dispatched,” Ming said.

Representing the Oregon Solar Energy Industries Association, Patrick McGuire asked how E3 saw the “last-in” ELCC being updated over time. “If it’s put into a contract, does it have to be leveled?”

“We would expect both the last-in ELCC and the table of loss of load probability hours is going to be different in each future year, and they’re going to be changing as the resource mix and the loads on the system change,” Ming said. “In particular, we would expect the last-in ELCC of solar to decline over time.”

Commissioner Letha Tawney asked whether the PUC should be concerned about whether LOLP data is sufficiently accounting for climate change.

“The West-wide heat storm this August was relatively unusual in the historical data, but over the multi-decadal timeframe of these contracts, [it] may not be such an outlier,” Tawney said.

“The answer to that question is quite simply an emphatic ‘yes,’” Ming said. “You do need to account for a changing climate. That is easier said than done. There are firms and researchers that are looking at how to do that. I would say the standard practice in the industry probably doesn’t do as good of a job accounting for climate as it should.”

Heutte posed a “deliberately provocative” question about the risks of introducing concepts from organized markets into Oregon’s IRP process, such as net cost of new entry (CONE) and sloped demand curves. He said for the past two decades he’s read prominent economists who claim capacity markets are the way forward for the electricity sector, but that recent talk from states such as Illinois, Maryland and New Jersey about pulling out of PJM’s capacity construct calls into question the concepts underpinning those markets.

“I’m wondering what can we learn from that. … How can we be assured going forward that those kinds of design elements will actually produce the kind of results we’re looking for?

Ming said E3 explicitly avoided using the term net CONE and instead used net resource cost, which is fundamental to ratemaking.

“Trying to isolate the portion of the resource that’s attributable to capacity and attributable to energy is something that’s done in ratemaking in every regulated jurisdiction across the country,” Ming said.

He said the reason states are looking to pull out of PJM is unrelated to the way the market sets net CONE or the demand curve.

“It’s related to the inability of renewables to bid into the capacity market. They’re forced to bid in prices that are higher than the clearing price and, ultimately, they don’t clear the market and they don’t get paid anything for capacity. So that minimum offer price rule implemented by FERC this year, that is what is driving the states to exit the capacity market,” he said.

December 22, 2020

Western RA Planning Must Change, WECC Says

Western utilities and their state regulators should increase their coordination and adopt dynamic planning reserve margins to help ensure the region’s grid is equipped with adequate resources as it takes on more variable generation, according to a new WECC report.

WECC Resource Adequacy — WECC’s report divided the Western Interconnection into five subregions based on load patterns and topology. | *WECC*

The recommendations come out of WECC’s first Western Assessment of Resource Adequacy Report, released last week. The report, the regional entity’s signature work for 2020, is the product of an internal effort to repurpose its mission by focusing on the growing challenges of resource adequacy in the Western Interconnection. (See WECC Seeks to ‘Invent’ Future with RA Forum.)

“We are really excited about this work,” Branden Sudduth, WECC vice president of reliability planning and performance analysis, said when staff provided a preview of the study at a meeting of the organization’s Board of Directors on Dec. 9.

The report is intended to supplement NERC’s 2020 Long-Term Reliability Assessment, published Dec. 15. (See NERC: Grid Operations ‘Fundamentally’ Changing.) Some Western stakeholders have complained that last year’s assessment failed to capture the risks that emerged this summer when a record-setting heat wave forced CAISO to initiate rolling blackouts for the first time in two decades while other balancing authorities prepared to take similar measures.

Both WECC and a joint root-cause analysis by California agencies have cited supply shortages as a key factor behind the energy emergencies, although WECC’s effort to address regional RA preceded the heat wave event. (See WECC Says Extreme Events Require Forecast, RA Changes.)

To account for the local and topological factors that contribute to interconnection-wide RA issues, the study divides the Western Interconnection into five subregions that align with the region’s three reserve sharing groups: CAISO, Southwest Reserve Sharing Group (SRSG) and Northwest Power Pool (NWPP).

Because of variations in peak seasons, the NWPP subregion is further divided into Northwest, Northeast and Central subsections. The report refers to CAISO as California-Mexico (CAMX) and the SRSG as the Desert Southwest (DSW).

Scenarios and Variations

WECC’s assessment applied two scenarios to each of the five subregions “to highlight a broad range of future resource possibilities, including known and expected resource retirements.” Scenario 1 assumes each subregion is required to meet its own demand, while Scenario 2 allows for imports.

The RE overlaid each scenario with three variations of resource availability. Variation 1 includes all resources currently in service and expected to run in future forecasts. Variation 2 includes existing resources and those under construction and expected to run in the forecast year (Tier 1 resources). Variation 3 includes existing and Tier 1 resources as well as those currently in licensing or siting phases but not yet under construction (Tier 2).

The reports points out that RA planning has typically relied on a “deterministic” — or static — approach that calculates needs by comparing the amount of available generation capacity, plus a planning reserve margin, to the highest demand of the year. If those resources cover the peak day, they are assumed to be sufficient for all other days of the year.

That planning approach is fraying at the edges with the increased adoption of variable renewables, prompting WECC to adopt a “probabilistic” approach that examines resource needs on an hourly basis over the next 10 years using supply and demand projections provided by Western balancing authorities. WECC ran the data through its Multi-Area Variable Resource Integration Convolution modeling tool, which matches generation to load for each hourly interval to determine if there is enough capacity to meet demand and to calculate a planning reserve margin.

“The model determines whether there are enough resources in the interconnection to meet expected demand while maintaining reserves to account for any variations from the expected forecasts or loss of generation. The results from this analysis are used to determine where resource shortfalls may occur in the system over any given study period,” the report said.

WECC’s analysis found that under Scenario 1, all subregions show some risk of loss of load, even with Tier 1 and 2 resources. All variations of that scenario contain hours with insufficient resources to serve load and maintain planning reserve margins.

The RE also found that most hours of unserved load can be solved under Scenario 2.

Still, the report notes that “under the most optimistic assumptions about future loads, resources and imports, there are still hours in which the interconnection does not meet” the one-day-in-10-years (ODITY) threshold for the 10 years studied. The DSW, NWPP Central and Southern California portion of CAMX were particularly vulnerable to loss of load, WECC found.

In what might be the most pressing finding, the analysis showed that even under the most optimistic assumptions under Variation 3 of Scenario 2, 2021 could see one to eight hours in which some subregions fail to meet the required planning reserve margins of the ODITY standard.

“The results worsen as the assumptions about resource construction and reliance on imports span to the more realistic, less optimistic end of the spectrum,” WECC said.

WECC also found that increased volumes of variable resources on the system compound the RA issues, making resource planning more challenging because more resources are not consistently available to meet demand. Additionally, demand is also becoming increasingly variable because of climate change, behind-the-meter generation and transportation electrification.

The report’s final finding: RA will suffer “significant degradation” if historical approaches to resource planning are left unchanged.

Getting There

WECC’s first recommendation is for resource planners and regulators to transition away from fixed planning reserve margins to dynamic margins aligned with hourly needs.

The second recommendation is for planning entities to not only consider how much additional capacity is needed to mitigate variability but also the expected availability of new resources. “Understanding the differences in resource type availability is crucial to performing resource adequacy studies,” WECC said.

The report’s final recommendation encourages balancing authorities to coordinate their planning activities each year to help prevent them from relying on the same resources. “This coordination will help subregions make assumptions about import availability in the context of the entire interconnection,” WECC said.

“I think we got the train on the track now and can understand how to manage this resource adequacy issue,” WECC Director Gary Leidich said during the Dec. 9 board meeting. “This information has to get in the hands of policymakers so they understand what’s going on.”

Director Richard Woodward said he liked the idea of a dynamic reserve margin but asked, “How do we get there?”

Matt Elkins, WECC manager of performance analysis, said he wants the RE to meet with planning entities to explain the range of resources they will need to meet reliability requirements. “We have to do it together.”

WECC’s Sudduth added that he was encouraged to see multiple states already working together to address RA issues.

Director James Avery said it will be necessary for every state in the West to count RA in the same way. “Otherwise, the work we do is going to be meaningless.”

WECC said it will release a more detailed analysis of subregional RA issues in the first quarter of 2021.

December 20, 2020

FERC OKs Ownership Change in IIF Subs

FERC last week authorized the installation of a new general partner and transfer of ownership interests in the privately held Infrastructure Investments Fund (IIF) that acquired El Paso Electric (EPE) earlier this year. (See IIF Closes El Paso Electric Purchase.)

The commission on Thursday accepted a request by IIF US Holding and IIF US Holding 2 (master partnerships operating under the IIF umbrella name) to transfer one individual’s 33.3% general partnership interest in the entities to Anne Cleary, another private individual (EC20-94).

In addition to EPE, IIF US Holding owns a string of public utilities authorized to sell wholesale electric energy, capacity and ancillary services at market-based rates.

The commission said it found no evidence that the transaction would have an adverse effect on horizontal competition, rates or federal or state regulation, nor would it produce vertical market power concerns or result in the cross-subsidization of a non-utility associate company by a utility company.

IIF said that save for EPE’s transmission facilities and the “limited and discrete interconnection facilities associated with individual generation facilities,” it doesn’t operate or control any transmission in the U.S. FERC said IIF’s generation will continue to operate under existing market-based rate tariffs or cost-based rate schedules.

Public Citizen protested the transfer, criticizing Cleary’s installation and noting that she was president of a power company (Mirant California) that declared bankruptcy and was charged with market manipulation and other illegal conduct during California’s electricity deregulation crisis in 2000-2001.

The consumer advocacy group argued that IIF failed to represent all of Cleary’s energy-related affiliations as a former advisor of project managing service company Taffrail Group, a former principal with Modern Grid Solutions, and her link to a member of PJM’s Board of Managers through her board position with the Bermuda-based Ascendant utility. The group also argued that Cleary already serves on the board of directors at IIF subsidiary Southwest Generation Operating Co.

Public Citizen said IIF is a “lightly regulated, off-the-books series of private equity shell companies.” It said the three owners don’t function as owners but as a board of directors that simply delegates the day-to-day management of IIF to J.P. Morgan. It also said it’s “unclear what role J.P. Morgan played” in selecting Cleary for the Southwest Generation board seat.

Infrastructure Investments Fund — Anne Cleary | *Modern Grid Solutions*

IIF said it is advised by J.P. Morgan and structured as a “limited partnership investment vehicle, the equity of which is held by passive limited partners.” The company disputed that J.P. Morgan directs IIF. It said its utilities handle their own “day-to-day management and activities.” It also said because Cleary is a private individual, “there are no common officers or directors of parties” to the ownership transfer and that her role at Southwest Generation isn’t relevant.

FERC said Cleary’s connections are not a concern because Public Citizen did not prove that the transaction would harm competition.

“Public Citizen has not argued, let alone demonstrated, that its allegations, if proved true, show that the proposed transaction will have an adverse effect on competition, rates, regulation or result in cross-subsidization,” the commission said.

FERC agreed with IIF that because Cleary and Dennis Clarke, the seller, are private individuals, there are no common officers or directors of parties to the transaction.

December 20, 2020

Business Group Seeks to Triple Clean Energy R&D Funding

R&D — Norm Augustine, retired chairman and CEO of Lockheed Martin | *Bipartisan Policy Center*

A group of utility CEOs and other business leaders last week said the U.S. should triple federal funding for clean energy innovation to $25 billion annually over the next five years, calling it essential for addressing climate change and ensuring a leadership role for the U.S. in new technologies.

The American Energy Innovation Council, an 11-member group whose principals include the chairs of Southern Co., Dominion Energy, Xcel Energy and Royal Dutch Shell, said the increase should include a boost for the Advanced Research Projects Agency – Energy to $1 billion a year from the current $425 million.

Founded in 2010, the council is a project of the Bipartisan Policy Council, which presented a panel discussion Thursday on the group’s recommendations.

“There was a great deal of skepticism when we started as to whether [climate change] was really a problem. Today I think there are very few people who question whether or not we have a serious problem,” said Norm Augustine, retired chairman and CEO of Lockheed Martin. But he added: “We have a long way to go. Even today, about 88% of the world’s energy consumption use still comes from fossil fuels. That’s a number that’s declined by about 1% in the last quarter of a century.”

R&D — The American Energy Innovation Council said additional federal funding is needed to sustain innovations through the second “valley of death” between prototype and demonstration projects. | *American Energy Innovation Council*

A ‘Sputnik Moment’

The group cited research that 50 to 85% of annual GDP growth in the U.S. “can be traced to innovation.” In its first 11 years, ARPA-E provided $2.4 billion in funding for more than 950 projects, 166 of which have attracted more than $3.3 billion in private-sector follow-on funding, the group said. “Technology innovation improves productivity across industries and creates entirely new ones. Economists agree that innovation is the key engine of long-term economic growth and stability,” it said.

The council said the U.S. should expand “centers of excellence,” such as the Department of Energy’s Energy Hubs, Energy Frontier Research Centers and Lab Embedded Entrepreneurship Programs.

“Technology innovation requires expensive equipment, well trained scientists, multiyear time horizons and flexibility in allocating funds. This can be done most efficiently and effectively if the institutions engaged in innovation are located in close proximity to each other, share operational objectives and are accountable to each other for results,” it said. “Resources should not be spread thinly across many institutions working on the same problem.”

The group said it is alarmed that competing nations’ investments in science and technology are outpacing the U.S.

In fiscal year 2020, Congress appropriated about $9 billion for energy research, development and demonstration. But the U.S.’ “research intensity” — the ratio of R&D investments to GDP — has stagnated, while China’s tripled between 1995 and 2019, the group said.

“China’s recent announcement that it intends to completely decarbonize its economy by 2060 should be viewed as a new ‘Sputnik moment,’” they wrote, referring to the Russian satellite that prompted the U.S.-Soviet Union space race.

Valleys of Death

Although federal funding for early-stage R&D has increased in recent years, they said, “the later stages of demonstration and deployment continue to lag in resources and prioritization. Closing this gap is essential to successfully commercialize breakthrough technologies.”

Augustine said ARPA-E “does a fabulous job in dealing with that first ‘valley of death’” — the feasibility challenge between research and prototypes. But he said neither government nor industry has addressed the second gap between prototype and demonstration projects.

R&D — Former PG&E Corp. CEO Geisha Williams | *Bipartisan Policy Center*

The council recommended creation of a national, politically neutral “Energy Strategy Board” that would include experts in energy technology and markets, develop a long-term national energy plan and oversee a “New Energy Challenge Program” to build large-scale pilot projects.

“If you go from … research to prototype to demonstration it takes tremendous resolve, tremendous leadership and tremendous resources,” former PG&E Corp. CEO Geisha Williams said. “And I will tell you that no one company has the wherewithal to make it happen. It requires a very strong private and public partnership. And frankly, it’s going to require the type of funding that only the federal government can provide.”

“The U.S. government hasn’t had an energy plan for a long time,” Augustine added. “We don’t even have a capital budget for anything. … I know of no successful company that doesn’t have a capital budget.”

R&D — The American Energy Innovation Council said the U.S. should triple federal funding for clean energy innovation to $25 billion over the next five years. | *American Energy Innovation Council*

Augustine said such long-term planning is essential for a successful R&D program. “There will be failures; we’re talking about research and development,” he said. “My background is principally aerospace, and not every rocket works, I’ll guarantee you that. I’m afraid that’s true in the energy arena as well.”

Most Promising Technologies

R&D — Chad Holliday, chairman of Royal Dutch Shell | *Bipartisan Policy Center*

The group identified as the most promising technologies large-scale energy storage, advanced nuclear reactors, renewable and low-carbon hydrogen, and carbon capture and removal.

“If we try to focus on everything, it will be too much,” said Chad Holliday, chairman of Royal Dutch Shell. “But I think hydrogen is certainly one of the candidates for [research spending], and I believe carbon capture and storage is a second candidate for that.”

“There’s a lot of projections that suggest within 30 years, hydrogen in itself could be about 20% of the entire energy supply requirements [of] the entire world,” said Michael J. Graff, CEO of industrial gas manufacturer American Air Liquide Holdings.

Legislation

Speakers on Thursday expressed optimism that some of the priorities identified by the council will receive attention in an energy package as part of the year-end budget omnibus bill.

A discussion draft of the energy package includes a 75% increase in ARPA-E’s budget and funding for large-scale demonstrations of carbon capture utilization and storage technology, said Rep. Lizzie Fletcher (D-Texas), who also participated in the BPC forum.

ARPA-E’s budget would increase gradually, from $435 million for fiscal year 2021 to $761 million for fiscal 2025.

U.S. Rep. Lizzie Fletcher (D-Texas) | *Bipartisan Policy Center*

The Better Energy Storage Technology Act, which would reauthorize DOE’s grid-scale storage research, also is part of the package, said Fletcher, chair of the House Science, Space and Technology Subcommittee on Energy and a member of the House Transportation and Infrastructure Committee. At least one demonstration project would be due by September 2023.

Fletcher said House Democrats’ $1.5 trillion Moving Forward Act, which passed 233-188 in July, is not expected to clear this session, but it could be a “framework” for an infrastructure package in the next Congress. The bill, which received only three Republican votes, would allocate more than $70 billion to upgrade the electric grid to accommodate more renewables and electric vehicle charging and provide tax credits for EVs.

“A lot of people are talking about the challenges. We need a lot of people talking about the answers,” Fletcher said. “I think that it’s essential that this work centers on crafting ambitious but workable plans and depoliticizing this conversation. … That’s why … AEIC’s leadership and vision at this moment is so important.”

December 20, 2020

SPP FERC Order Briefs

FERC last week approved Basin Electric Power Cooperative’s revised market-based rate tariff, allowing it to make wholesale sales of energy, capacity and ancillary services at market rates in its Southwest, Southeast, Northeast and Northwest regions, effective Sept. 30, 2020 (ER20-2590).

SPP — The Basin Electric service territory | *Basin Electric Power*

The order expands Basin Electric’s authority to make sales at market-based rates beyond the SPP and Central regions. The commission found the cooperative’s lack of horizontal or vertical market power in the requested regions satisfied its requirements for market-based rate authority.

FERC designated Basin Electric, which became commission jurisdictional in November 2019, as a category 1 seller in the Southwest, Southeast and Northeast regions and as a category 2 seller in the Northwest.

Under FERC Order 697, category 1 status applies to wholesale marketers and producers that own or control 500 MW or less of generation per region; do not own, operate or control transmission facilities other than that necessary to connect individual resources to the grid; are not affiliated with anyone that owns, operates or controls transmission facilities in the same region as the seller’s generation assets; are not affiliated with a franchised public utility in the same region as the seller’s generation assets; and do not raise other vertical market power issues. Category 2 sellers are those that do not fall into category 1 and are required to file updated market power analyses.

SPP TCR Collateral Requirements Upped

The commission on Wednesday accepted SPP’s proposed Tariff revisions to establish minimum collateral requirements for transmission congestion rights (TCRs) (ER21-79.)

The RTO’s stakeholders and staff strengthened the use of credit in SPP’s TCR market following the 2018 GreenHat Energy default in SPP Board/Members Committee Briefs: April 28, 2020.)

Tri-State Order 845 Compliance Lacking

FERC ruled last week that Tri-State Generation and Transmission Association has partially complied with Orders 845 and 845-A, directing a further compliance filing within 60 days (ER20-687).

SPP — The Tri-State G&T footprint | *Tri-State G&T*

The commission in May said Tri-State had partially complied with the orders, directing the cooperative to describe the specific technical screens or analyses and the triggering thresholds or criteria it will use to determine which facilities are contingent facilities — unbuilt interconnection facilities and network upgrades upon which an interconnection request’s costs and timing are dependent.

In its order on Thursday, FERC found Tri-State’s proposed changes to its pro forma large generator interconnection procedures described the specific technical screens and analyses and provided requisite transparency. However, it said Tri-State’s proposal to evaluate system performance “against the technical screens” was not clear as to where the cooperative would post the information and what is included in its “posted engineering standards.”

The commission directed Tri-State to submit a description of the transmission provider’s posted engineering standards and the posted information’s location. FERC also ordered Tri-State to identify whether the interconnection customer’s costs, timing and study findings are dependent on the unbuilt facility, consistent with the definition of contingent facilities.

FERC disagreed with renewable energy developer Gladstone New Energy’s protest that Tri-State’s proposed changes were beyond the scope of the proceeding. The commission said the cooperative did not add to its existing procedure for determining contingent facilities, but instead revised it.

FERC issued Orders 845 and 845-A in 2018 and 2019 to increase the generator interconnection process’ transparency and speed. The changes are grouped into three categories: improved certainty for interconnection customers; promoting more informed interconnection decisions; and process improvements. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)

December 20, 2020

LIPA Allowed to Compete for NY EV Prize Funds

The New York Public Service Commission on Thursday ruled that projects located anywhere in New York may be eligible for state-sponsored electric vehicle prize competitions, granting a request from the Long Island Power Authority (LIPA), which is normally not subject to PSC jurisdiction.

The commission in July approved just over $700 million in spending over the next five years to install more than 50,000 light-duty EV charging stations throughout the state, including $80 million for three prize competitions to be administered by the New York State Energy Research and Development Authority (NYSERDA) (18-E-0138). (See NYPSC Approves $700 Million for EV Chargers.)

The EV Make-Ready Program is funded by investor-owned utilities through a cost-sharing program meant to incentivize utilities and charging station developers to site EV charging infrastructure in places that will provide maximum benefits to consumers.

The commission’s declaratory ruling Thursday “remains consistent with the July order by continuing the policy that benefits will accrue to the ratepayers funding a chosen prize,” said Bridget Woebbe, assistant counsel in the Department of Public Service. “However, other communities throughout the state would also be allowed to participate in the prize competitions so long as a separate funding source is secured for any project selected outside of an investor-owned utility service territory.”

NY EV Prize Funds — Southampton, Long Island offers plug-in EV charging at the Ponquogue Beach parking lot. | *Southampton Town*

LIPA and its service provider, PSEG Long Island, have pledged to add 4,650 new charging ports by 2025 — enough to support 188,00 EVs — beginning with a proposed investment next year of $4.4 million.

Gov. Andrew Cuomo’s office said the three prizes are intended to support clean transportation options benefiting “lower socio-economic and environmental justice communities.”

They include a $40 million environmental justice program to reduce air pollution in “frontline communities” and create transportation “green zones” across the state and a $25 million program aimed at individual buyers that will seek “innovative and high impact approaches that enable access to clean transportation services for disadvantaged and underserved communities.”

In addition, a $20 million program will seek “innovative and high-impact approaches to medium- and heavy-duty electrification that can be replicated at scale, including for `last-mile’ solutions, one of the fastest growing emissions sources in this class of vehicles.”

The state’s EV program allocated $206 million toward equitable access and benefits for poor and disadvantaged communities, which also will be eligible for a higher incentive supporting up to 100% of the costs to make a site ready for EV charging. The Climate Leadership and Community Protection Act (CLCPA) requires all state agencies to prioritize greenhouse gas emissions reductions in disadvantaged communities and stipulates that at least 35% of the overall benefits of spending on clean energy programs benefit disadvantaged communities.

The commission has yet to rule on New York’s six local distribution companies’ recent proposals for managed charging programs, which were split between “passive” and “active” approaches. (See NY Utilities Diverge on Managed EV Charging.)

Long-term Concerns

While the initial focus was on funding projects located in communities served by investor-owned utilities, the commission said that the objectives to advance transportation electrification, expand access to clean transportation and reduce emissions in disadvantaged communities are relevant throughout the state. (See NY Panel Examines Vehicle Electrification, Cleaner Fuels.)

The prize competition is important “in that it expands the realm of the possible,” PSC Chair John Rhodes said. “We need functional, cost-effective electric transportation solutions across the board, and we need more innovation on a couple of areas: in finding good solutions for disadvantaged communities and neighborhoods and in terms of expanding beyond passenger and light-duty vehicles, which are relatively well established now as electric vehicle use cases, to other more heavy- and medium-duty vehicles.”

Commissioner Diane Burman supported the ruling but expressed concern for the future.

“I do think that at some point we’re going to have to consider a broader statewide policy for the medium- and heavy-duty sectors, and so [that] prize itself really is looking at how this investment and lessons learned from that may be,” Burman said.

Commissioner Tracey Edwards said the PSC should ensure that disadvantaged communities are not left behind.

“I would have liked to see for the future some status reports with NYSERDA that have a direct line back to our policies within the PSC, just some timelines and checkpoints to make sure that whatever we have outlined is actually working so that if we have to change course or amend any of the things in place, we have time to do that,” Edwards said.

Commissioner John Howard said he was concerned about financing the work required by the CLCPA and other initiatives to change the grid and electrify transportation and buildings.

“We cannot finance it exclusively through ratepayer dollars,” Howard said. “It is my sincere hope with a new administration in Washington that these initiatives will be funded at least in part if not in total through the federal [government]. The benefits will be both statewide and worldwide … and I agree with Commissioner Edwards that we need to be able to provide flexibility so that we can know quickly when things aren’t going as intended.”

December 20, 2020

NYISO Management Committee Briefs: Dec. 16, 2020

NYISO CEO Rich Dewey told the Management Committee Wednesday that the ISO succeeded in completing many stakeholder processes despite the coronavirus pandemic. “This has been probably one of the most challenging years of any of our professional experience,” he said, referring to the challenges of working remotely.

He thanked stakeholders and staff for helping the ISO replace its energy management system and business management system, complete a demand curve reset and roll out market rules for energy storage.

“I hope 2021 is a little easier, but there’s still a significant chance that it will get a whole lot worse before it starts getting better,” Dewey said. “So I want to encourage everybody to stay safe as we head into the holiday season.”

COO Rick Gonzales noted the “remarkable decrease in the fuel prices year-over-year” with natural gas in November averaging $1.47/MMBtu, down 44.5% from the previous year. Distillate prices dropped 36.9% year-over-year.

The ISO did an “ad hoc update to its generator survey to include pandemic impacts … but none of the generation sector participants are reporting outages or derates as a result of the pandemic,” Gonzales said. “As a result, we’re not projecting any reliability issues, certainly at this point in time, as a result of the pandemic.”

NYISO Strategic Plan 2021-2025

Executive Vice President Emilie Nelson presented the NYISO Strategic Plan for 2021-2025, reiterating the accomplishments of the year and looking ahead to how the ISO will incorporate the clean energy mandates in the state’s Climate Leadership and Community Protection Act.

NYISO Management Committee — NYISO’s five-year Strategic Plan takes the big-picture view of stakeholder processes to meet the CLCPA statutory requirements in the electricity sector. | *NYISO*

“The board [of directors] thought it was more important than ever in these times of uncertainty to provide some clarity on what the objectives of the organization are for the future,” Nelson said. “If you consider the multitude of planning studies looking out 10 to 20 years in order to inform how the grid is going to transition, there’s a lot of quality work there.”

In addition to deploying the energy storage participation rules in August, Nelson said the ISO continued its exploration of carbon pricing and won FERC approval for its distributed energy resources participation model. She also cited as accomplishments improvements to its market rules for ancillary services and a proposed design for the hybrid co-located model.

Stakeholders and NYISO staff worked hard through the demand curve reset process, “which is always very involved, and … we progressed through the largest class year in a record time, all representing improvements that stakeholders have worked with the ISO on through the years,” Nelson said of the transmission queue that began in August 2019 and concluded this fall.

Tx Planning Changes and TAM Clarification

The committee approved revisions to streamline the ISO’s economic and transmission planning and expand its scope to capture the grid’s ability to deliver energy from the future generation resource mix to the forecasted load. The changes rename the Congestion Analysis and Resource Integration Study as the System & Resource Outlook and double the assessment periods to 20 years, consistent with the study period for proposed economic or public policy transmission projects. (See NYISO Business Issues Committee Briefs: Dec. 9, 2020.)

NYISO will continue to make additional economic planning studies available to interested parties, including one on the new energy deliverability metric. The Board must approve the Attachment Y Tariff revisions before the ISO can make a Section 205 filing with FERC in January.

The MC also approved a clarification on how the ISO’s new Tailored Availability Metric rules apply to landfill gas resources as well as to wind and solar. The clarification will replace the terms “wind and solar resources” with “intermittent power resources,” which includes landfill gas, in section 5.12.14.3 of the Market Administration and Control Area Services Tariff.

December 20, 2020October 30, 2023

NE Energy Leaders Discuss Paths to Decarbonization

State energy and environmental policy leaders from Connecticut, Massachusetts, Rhode Island and Maine outlined their long-term strategies to achieve decarbonization goals Dec. 15 during a webinar co-hosted by the Connecticut Power and Energy Society and New England Women in Energy and the Environment.

Heather Hunt, executive director of the New England States Committee on Electricity (NESCOE), served as moderator of a panel that examined decarbonization “Plans, Roadmaps and Pathways to 2030 and Beyond.”

Hannah Pingree, director of policy innovation and future for Maine Gov. Janet Mills and co-chair of the Maine Climate Council, said Mills was elected in 2018 with climate and energy policy issues leading the way. The governor signed legislation in 2019 to reduce carbon emissions by 45% by 2030 and 80% by 2050, and create the Climate Council, which recently released its first report. Pingree said decarbonizing transportation “is certainly our biggest nut to crack,” as 54% of the state’s emissions come from that sector. Another major hurdle for Maine is the heating sector, she said, where Mills set a goal of installing 100,000 new heat pumps by 2025.

“For a state with about 500,000 homes, these are fairly aggressive goals, and they get a lot more aggressive as we get out to 2030,” Pingree said.

From top left: Judy Chang, Massachusetts Executive Office of Energy and Environmental Affairs; Katie Dykes, Connecticut DEEP; Hannah Pingree, Maine Governor’s Office of Policy Innovation and the Future; Heather Hunt, NESCOE; and Carrie Gill, Rhode Island OER | CPES/NEWIEE

Carrie Gill, an administrator in the Rhode Island Office of Energy Resources, said the electric and thermal sectors are responsible for “about two-thirds of our greenhouse gas emissions.” She noted that Gov. Gina Raimondo issued an executive order tasking her with developing pathways and action steps to meet 100% of the state’s electricity demand with renewable energy resources by 2030, “the fastest pace in the nation.”

Rhode Island consulted with The Brattle Group to conduct an in-depth analysis, which led to a “suite of recommendations that we will act on beginning in 2021.” Gill said some of those recommendations include pursuing a change in the state’s renewable portfolio standard “to ensure that we’re reaching 100% renewables by 2030, and importantly that we maintain 100% renewables past 2030.” The state wants to continue progress on strategically modernizing the electric grid and will start to develop a role for energy storage, which Gill said is “a critical technology to balance renewable energy generation and electricity demand, especially as we green the regional grid.”

Katie Dykes, Connecticut’s Department of Energy and Environmental Protection commissioner, said state statutes require reduced carbon emissions economywide 45% from 2001 levels by 2030 and 80% by 2050. Additionally, last year Gov. Ned Lamont issued an executive order directing Dykes’ agency to evaluate pathways to achieve a 100% carbon-free electric supply for Connecticut by 2040.

“We all have very ambitious goals; some of them are framed slightly differently, but we know that to make progress effectively and get the best value out of the various strategies that we’re all implementing to meet these goals, our participation together in a shared regional grid ties together our fates in meeting these individual state goals,” Dykes said. “Strong regional collaboration is really essential to this effort for our integrated resources plan.”

Dykes said the electrification of the thermal and transportation sectors provides “the clearest pathways, both through procurement mechanisms and technologies that are continuing to come down in cost for reducing carbon emissions affordably.” She said the continued progress in decarbonizing the electric supply pays dividends and ensures that “those measures that we implement to clean up our transportation and thermal sectors will be even more effective in reducing emissions when we plug them in.”

State-by-state carbon dioxide emission-reduction targets for New England | CPES/NEWIEE

Judy Chang, undersecretary of energy for the Massachusetts Executive Office of Energy and Environmental Affairs, said her state has committed to net-zero greenhouse gas emissions by 2050. Energy efficiency is the No. 1 “pillar” of its strategy, she said.

“We have to limit the way we leak,” Chang said. “We leak our energy out of our windows and walls.”

Massachusetts will also need about 15 GW of offshore wind and 25 GW of solar “to power our economy,” and those numbers need to roughly double for the rest of New England “for the next 30 years.”

“We can’t do this by piecemeal planning, and we can’t afford to go into this without a long-term view,” Chang said. “We also cannot afford on the wholesale market side to keep going with our current market design and the current way of planning for transmission.”

That requires collaboration, she said, and “not only do we need to collaborate from a regional perspective … but also at the federal level.”

“We cannot actually achieve all the things that we want to achieve in the next 10 years as we set targets for 2030 without a federal government that can also support that,” Chang said.

Collaboration between the states, such as the Regional Greenhouse Gas Initiative or, potentially, the Transportation Climate Initiative, is not going anywhere. Earlier this fall, five of the six New England governors, excluding New Hampshire, signed a joint statement that was later followed by a vision statement from all six states through NESCOE calling on ISO-NE to make changes and reforms to wholesale market design, transmission planning and RTO governance to enable states to better meet their decarbonization goals. (See New England Governors Call for RTO Reform and States Demand’ Central Role’ in ISO-NE Market Design.)

“I think this is acutely needed, not only to ensure that our voices are heard and that there’s responsiveness within the [ISO-NE] board to state public policies, but also transparency and accountability to consumers,” Dykes said.

She added that from her time as chair of Connecticut’s Public Utilities Regulatory Authority, she recognizes the importance of “transparency and accessibility of the deliberative process that is incredibly important from a governance standpoint.”

“I’m optimistic about where it will take us and the possibilities for real collaboration amongst states, and with the ISO, that I think will be in our future,” Dykes said.

Chang announced an upcoming series of technical conferences in January and February on wholesale market design, transmission planning and governance reform.

“Understanding there are resource constraints on people and organizations, we really cannot afford to just go along and hope that we will land with the right market design and the right transmission pieces that need to be built,” Chang said. “I think that’s the ultimate vision … to really work collaboratively so that we can achieve this future in the least amount of disruption and at the lowest cost.”