The changes at the top of CAISO’s executive ladder that began last month with the installation of CEO Elliot Mainzer continued this week, as the ISO announced a new chief operating officer and the retirement of two veteran vice presidents.
Mark Rothleder, who has been with CAISO since its founding in 1997, will take the newly created No. 2 position as COO under Mainzer, who replaced Steve Berberich. (See CAISO Retiring, Incoming CEOs Field Questions.)
Rothleder currently serves as the ISO’s vice president of market policy and performance, a job in which he warned of potential summer shortfalls long before they occurred in August and September as California shifted from its reliance on natural gas to wind and solar. (See CAISO, CPUC Warn of ‘Reliability Emergency’.) Previously, a suite of vice presidents, including Rothleder, reported directly to the CEO.
Mainzer said in a news release that he looks forward to teaming up with Rothleder to “meet the company’s strategic goal of enabling a reliable transition to a clean energy grid.”
Petar Ristanovic, CAISO | CAISO
“Mark has been with the ISO since its inception, giving him immense and deep knowledge of our organization and the industry,” Mainzer said in the statement. “I know Mark will do an outstanding job in his new role as COO.”
Rothleder is the ISO’s longest-serving employee and previously held positions as executive director of market analysis and development, principal market developer and director of market operations.
“Since joining the ISO 23 years ago, Rothleder has worked extensively on implementing and integrating the approved market rules for California’s competitive wholesale energy and reserves markets,” the ISO said.
CAISO also said that Petar Ristanovic, vice president of technology, and Eric Schmitt, vice president of operations, are retiring at the end of the year.
Ristanovic, who has more than 35 years of experience in the electric industry, came to CAISO from Siemens Energy Automation, where he served as global innovation manager. Previously he worked at the University of Belgrade’s Nikola Tesla Institute of Electrical Engineering, developing and implementing advanced power system applications.
Schmitt, who also has more than 35 years of experience, oversees California’s bulk electric system operations, real-time engineering and market services. Before joining the ISO in 2011, he served as senior vice president at Science Applications International Corp. in Tysons, Va.
“Petar and Eric represent the gold standard in the energy industry, and both were instrumental in shaping the California ISO into the pioneering, modern power grid and electricity market of today,” Mainzer said.
CAISO has not announced plans to replace them and did not respond to an inquiry by press time.
Offshore wind advocates said Wednesday they are confident the industry will retain its bipartisan support regardless of the results of the U.S. elections this year.
“We are in a world now where utilities in Indiana are rushing forward building wind farms,” said Seth Kaplan, director of government and regulatory affairs for Ocean Winds, the joint venture between ENGIE and EDP Renewables that has partnered with Shell New Energies to sponsor Mayflower Wind.
“It’s a changed world, where there is a broad recognition that this is the kind of generation we are able to build now because of other concerns in terms of health, in terms of cost and such, that we are not seeing other types of large-scale generation getting built,” Kaplan told the American Wind Energy Association’s Offshore Windpower Virtual Summit.
Seth Kaplan, Ocean Winds | AWEA
As power plants retire, and as loads rise with new demand from electric cars and electrification of heating and cooling, “it is a truly bipartisan, across-the-board need for this large-scale generation source to move forward,” Kaplan said. “It is not wholly dependent on climate policy; it’s not wholly dependent on state policy. Those are all elements, but there is a unifying bipartisan need from the shipyards in Louisiana to the ports in Massachusetts to the folks who want new generation in New York City.”
Regulatory Push
Moderator Joshua Kaplowitz, senior counsel for GE Renewable Energy, noted that the federal regulatory regime governing offshore natural resources dates from nearly 100 years ago. Regulations specific to OSW have not been updated since the Bureau of Ocean Energy Management was created in 2011.
“We have come a long way — and I have been involved in this industry for 15 years now — but we continue to evolve. There is more work to be done,” said Geri Edens, counsel for Vineyard Wind, a joint venture between Copenhagen Infrastructure Partners and Avangrid Renewables.
Geri Edens, Vineyard Wind | AWEA
BOEM has done a “tremendous job” trying to make regulations largely modeled on those for the oil and gas industry fit the needs of OSW development, with little experience beyond the failed Cape Wind project, Edens said. “So, it’s time to move on and try to start thinking about how the regulatory process can be improved.”
Edens said she hoped the agency, which announced a rulemaking in 2014 to update the regulations and provide more flexibility, will make more progress under a new administration.
“Now you see developers have to request numerous departures from the regulations because … all the things that go into gathering that data are onerous and not always feasible to submit at the same time that you submit a COP [construction and operations plan],” Edens said.
Claire Richer, federal affairs director at AWEA, noted acting BOEM Director Walter Cruickshank testified Sept. 22 before the Senate Energy and Natural Resources Committee that Congress has provided sufficient funding needed to hire the staff to assess all new lease areas and OSW proposals.
Claire Richer, AWEA | AWEA
BOEM worked through the pandemic and held a series of public hearings over the summer on the 800-MW Vineyard Wind project and the 1-nautical-mile turbine spacing advocated by developers and recommended by the U.S. Coast Guard. (See Developers Seek 1-Mile Spacing for Vineyard Wind.)
Kaplowitz asked about BOEM’s authority under the Outer Continental Shelf Lands Act of 1953, “authority that was appended to Energy Policy Act of 2005 as a couple paragraphs to the end of one of the sections of a statute … that has primarily been an offshore drilling statute.” Are there changes that can be made to enhance BOEM’s authority with respect to offshore wind permitting? he asked.
“It’s really up to the developers to figure out what they want and what they think will be the best way forward,” Richer said. “A lot of folks in Congress want to help offshore wind. I think there’s a lot of bipartisan support. … If we want it, we need to push for it.”
Joshua Kaplowitz, GE Renewable Energy | AWEA
Kaplan advised being “extremely careful” with making changes to a complicated regulatory structure, likening it to a game of Jenga, where if you pull any piece out it can cause the blocks to fall.
“Predictability is better than unpredictability,” Kaplan said.
Almost four years after the first wind turbines began commercial operations in American waters, and three weeks before an election that could change federal policy on climate change, speakers at the American Wind Energy Association Offshore Windpower Virtual Summit said it is time to engage everyone in the need for an energy transition.
Ali Zaidi, New York state | AWEA
“We’ve got to scramble all the jets in terms of the talent we need to attack the climate challenge and unlock the climate opportunity,” said Ali Zaidi, New York Gov. Anthony Cuomo’s deputy secretary for climate policy and finance. “That means people from all disciplines joining us. It means people bringing a diversity of backgrounds and skillsets.”
East Coast offshore wind projects and lease areas | AWEA
Marine biologist Ayana Johnson, co-founder of the Urban Ocean Lab, which describes itself as a think tank for the future of coastal cities, sounded a similar message.
“I think this is a moment in human history where we all need to think really carefully about what we’re good at and what we can contribute to [climate] solutions. There are plenty of problems [and] plenty of work to be done. So, the question is, how are we each best suited to make things better,” she said.
For Johnson, the answers led her and journalist Alex Blumberg to launch a podcast on climate solutions, “How to Save a Planet.” She also co-edited an anthology of essays and poems, “All We Can Save.” And she helped craft Democratic presidential candidate Elizabeth Warren’s “Blue New Deal,” a plan for restoring ocean habitat and adapting to climate change.
Ayana Johnson, Urban Ocean Lab | AWEA
But while Johnson has found her place, she fears many others haven’t been engaged.
“The environmental movement and … renewables [supporters] haven’t done a great job of describing what the future looks like if we get it right,” she said. “We have tons of media about the apocalypse and the day after tomorrow and the uninhabitable earth, and the fire and brimstone. But we don’t have [a picture of] what if we do put offshore wind in all these places? What if we do have great public transit? What if we do transition to regenerative farming? What does that look like?
“And so a lot of my work right now is about how do we make more concrete what we’re working towards so we’re not just [saying] ‘Oh, I should run away from the apocalypse,’” she added. “We’re not running, honestly. We’re just kind of sauntering away from the apocalypse. And we need to pick up the pace.”
AWEA CEO Tom Kiernan said the offshore wind industry needs to speak as one voice to realize the potential of 83,000 new jobs and $57 billion in investments the organization estimated in its economic impact assessment earlier this year.
“We do now have lots of different organizations advocating for offshore wind, and we’re not always perfectly aligned,” Kiernan said. “By working more as one, we can help our government partners do what we are asking them to do. So, for example, we are asking the federal government to establish transparency and consistency in the regulatory process. … We’re asking them to finalize additional wind areas and subsequent lease areas that can be auctioned. And we’re asking them to continue engaging with the fishing industry to find solutions that work for all of us.”
AWEA CEO Tom Kiernan | AWEA
Kiernan said that was the motivation for AWEA’s decision to merge into a new group that also embraces solar power and storage, the American Clean Power Association. It is expected to launch in January.
“Working powerfully and at scale together, we can have a bigger influence with Congress, the administration and with state capitals throughout the country,” Kiernan said. “This is a once-in-a-generation opportunity to create a whole new energy industry for America.”
Among the companies that have agreed to join the new organization are EDF Renewables, Berkshire Hathaway and NextEra Energy. Notably, the Solar Energy Industries Association has declined to join, although it says it expects to work with the group.
State OSW targets | AWEA
Eric Thumma, who leads Avangrid Renewables’ U.S. OSW commercial activities, was also bullish on the economic impact of the new generation. “We’re talking about very large capital expenditures that are going to have significant multiplier impacts,” he said.
Thumma said Avangrid estimates its Kitty Hawk project off the coast of North Carolina and Virginia could produce 2.5 GW of power and $2 billion of benefits through the development and construction of the project through 2030. “That doesn’t count approximately $100 million annually of wage increases and jobs that we’ll have through the next 25 years of operations and maintenance,” he said. “These projects can be economic engines. [Combining the Kitty Hawk project and Dominion Energy’s 2.6-GW OSW project off Virginia], you have a pretty big amalgam of 5 GW of projects.
“What drives investments are the power purchase agreements and [offshore renewable energy credit] agreements. [States have] really laid out a schedule that we can have confidence in that there’s going to be solicitations. That allows us to start talking about our ongoing investments and give the supply chain some confidence that those [requests for proposals] are going to be there.”
Eric Thumma, Avangrid Renewables | AWEA
Thumma said states could do more, however, by working more closely together on their OSW plans.
“We’ve sort of seen these [procurements] as one-offs. … As a former state official, I understand the simplicity of it and the motivation to do it. But is there a way to further collectively rationalize and work together on these projects? And if you did that, would there be some spillover effects into other areas of policy, like transmission interconnection, where we know there’s going to need to be cooperation in order to enhance the industry? I set that forward as a charge to the states to see if we can have some additional state leadership and cooperation in those areas.”
Chris Hart, Atlantic Shores Offshore Wind | AWEA
Chris Hart, president of Atlantic Shores Offshore Wind, a joint venture of EDF Renewables and Shell New Energies that is developing an OSW project off of Atlantic City, N.J., said the industry’s success will depend on collaboration with fishing interests and other stakeholders. To that end, the company hired two lifelong New Jersey fishermen as liaisons to the recreational and commercial fishing industries.
“They really put their reputation as fishermen on the line by working with the offshore community. We don’t take that lightly,” he said. “We’re working with them to build a collaborative, respectful relationship with a very tightly knit community that makes up New Jersey fishermen.
“We have to listen more than we speak. … We don’t have all the solutions. We may not even have the right problems identified. We need to listen.”
MISO and SPP state regulators appear intent on completing their work to improve the RTOs’ interregional coordination before 2021 arrives.
The Seams Liaison Committee (SLC), comprising regulators from the Organization of MISO States and SPP’s Regional State Committee, met virtually and briefly Monday, deciding to develop a decision matrix to help them prioritize the various recommendations offered up for their consideration.
Admitting he may have had “reckless optimism about wrapping up at the end of the year,” Arkansas’ Ted Thomas, SLC co-chair along with Texas’ DeAnn Walker, said the matrix should “do good,” given the difficulty of holding in-depth discussions over the internet.
“The joy of virtual meetings,” he said.
Thomas, Walker and OMS Executive Director Marcus Hawkins will work together on the decision matrix. They hope to have a workable format that they can discuss with the full RSC and OMS on Oct. 26 and 29, respectively.
Walker said she wanted to have an “orderly way” to step through the recommendations made by the RTOs’ market monitors. That came into clearer focus, she said, as Hawkins went through a list of recommendations and the grid operators’ responses. (See MISO, SPP Respond to Monitors’ Studies.)
SPP responded to recommendations for coordinated transaction scheduling, interface pricing and the MISO Independent Market Monitor’s report on market-to-market (M2M) coordination. Staff added clarifying remarks and noted which recommendations are included in SPP’s 2020 Market Roadmap.
MISO detailed its responses to the same recommendations, noting whether they have been included in its Integrated Roadmap or the IMM’s 2019 State of the Market report.
NERC’s Reliability and Security Technical Committee (RSTC) held a special meeting Wednesday to wrap up unfinished agenda items from its last meeting in September, when it ran out of time because of an extended debate over a plan for taking over the work of the disbanded Planning, Operating and Critical Infrastructure Protection committees. (See NERC RSTC Briefs: Sept. 15, 2020.)
SITES Revisions Underway
The issue that caused the most contention at the September meeting was the scope document for the Security Integration and Technology Enablement Subcommittee (SITES), intended to recommend “practices for incorporating cyber and physical security aspects” into utilities’ business activities. Several participants expressed surprise at the focus on cybersecurity at the expense of transformative business applications, which they had understood to be the goal of the subcommittee. The document was tabled for further discussion.
RSTC Vice Chair David Zwergel, of MISO, asked for volunteers to help revise the document, with the goal of bringing it back to the committee for approval at its next meeting in December. Kayla Messamore of Evergy, ERCOT’s Christine Hasha and Carl Turner of Florida Municipal Power Agency agreed to take part in the revision process.
Consent Agenda Items Approved After Debates
The RSTC’s business for this meeting primarily consisted of items from the previous meeting’s consent agenda that were pulled for further discussion because of a motion by Brian Evans-Mongeon of Utility Services Inc.:
Standard authorization request (SAR) for MOD-025-2 — Unit verification and modeling.
SAR for revisions to PRC-023-4 — Transmission relay loadability.
Reliability guideline: Gas and electrical operational coordination considerations — posting for 45-day comment period.
Reliability guideline: Distributed energy resource verification — posting for 45-day comment period.
White paper on assessment of DER impacts on NERC reliability standard TPL-001.
All items passed, with the exception of the reliability guideline on gas-electric coordination. The guideline was remanded to the Operating Reliability Subcommittee on a motion by Evans-Mongeon, who argued that NERC’s Electric-Gas Working Group deserved a chance to provide input into the resolution before it was passed.
Another dispute emerged during the discussion on the SAR for MOD-025-2, when Duke Energy’s Greg Stone moved that a provision in the document’s scope section calling for data to be “analyzed and used properly by transmission planners and planning coordinators” be removed, on the grounds that the language was not clear. However, his motion was defeated, with several members arguing that editing a SAR is not the committee’s purpose and that if the wording was vague, then it could be addressed by stakeholder comments.
Evans-Mongeon also questioned the white paper on assessment of DER impacts to TPL-001, calling it premature in light of the fact that the System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group is working on another white paper covering DER impacts to the rest of NERC’s standards that could be released as early as December. He moved for the paper to be held so that a more thorough evaluation of DER impacts to all reliability standards can be completed.
In response, SPIDER Chair Kun Zhu, of MISO, explained that the group had already done “thorough homework” on TPL-001 and felt there was no reason to delay its analysis until work on the other standards was completed, when releasing the results earlier might help achieve a more reliable system. This view was supported by most other members, and the white paper was endorsed by the committee.
Committee Feels Growing Pains
Part of Wednesday’s meeting was taken up with complaints about procedural quirks of the new committee. Several members expressed surprise upon learning that approval of motions required a two-thirds majority of all members present, as opposed to all members voting. Turner and Evans-Mongeon raised questions about whether votes at previous meetings had been recorded properly, as they had assumed that approval only required a simple majority.
Several members also said the procedure currently used for initiating debate on a proposal, which requires a motion and a second in favor of the proposal, is unnecessarily confusing as members may not be aware that the motion is opening debate rather than beginning a vote. Chair Greg Ford, of Georgia System Operations, promised that the committee would consider revising its procedures with an eye toward clarity.
An estimated 20,000 to 30,000 MW of offshore wind capacity representing a $28 billion to $57 billion investment in the U.S. economy will be operational by 2030, according to the U.S. Offshore Wind Power Economic Impact Assessment.
OSW project development, construction and operations could bring a projected 83,000 jobs in that time and deliver $12.5 billion to $25.4 billion per year in economic output. During a panel at the American Wind Energy Association’s Offshore Windpower Virtual Summit on Wednesday, state officials from Massachusetts, New Jersey, New York and Rhode Island discussed their role in training tens of thousands of people for those jobs as part of that hoped for economic boon.
Kirsten Holland | Massachusetts Clean Energy Center
Kirsten Holland, program manager for offshore wind for the Massachusetts Clean Energy Center (CEC), said a “well trained and highly skilled workforce” is needed for OSW jobs where educational requirements range from apprenticeships to advanced degrees. Holland’s agency released an assessment in 2018 examining the workforce needs and economic impact associated with 1,600 MW of OSW development.
“It really laid the groundwork for our workforce development initiatives by demonstrating that there are thousands of jobs and hundreds of millions to billions of dollars in economic impact associated with just 1,600 MW of offshore wind built out,” Holland said.
Building on that initial assessment, Holland said the CEC maintains a website dedicated to training and educational programs for clean energy jobs, including OSW, which lays out career pathways, educational offerings and training programs. Additionally, Holland said there is an active process to identify unemployed or underemployed people to set up those “who need the jobs most” with education and technical training programs.
According to Holland, another priority area was increasing access to OSW jobs, specifically those in the commercial fishing industry. She said $2 million in grant funding to 15 institutions, including a public university, community colleges and other organizations, have helped build a bridge to new employment opportunities and training over the last two years.
Laura Hastings, deputy director of the Rhode Island Department of Labor and Training’s Real Jobs program, said her state offers the Wind Win RI certification program for high school students looking to work in the OSW industry. The state also offers two free years of tuition at a community college for a renewable energy program, and there is a partnership with the Business Network for Offshore Wind to train companies that want to work in the industry. (See Tiny RI Seeks its Share of Offshore Wind Jobs.)
Earn and Learn
Matthew Vestal, senior adviser for large-scale renewables at the New York State Energy Research and Development Authority, noted his state’s legislative mandate to install 9 GW of offshore wind by 2035. By his “fairly conservative estimate,” that could mean 10,000 jobs and the capacity to provide enough renewable energy to power 6 million homes and produce 30% of the state’s electricity load.
Matthew Vestal | NYSERDA
“We recognize that offshore wind is a very unique economic opportunity,” Vestal said.
Vestal said New York is spending $20 million to create the Offshore Wind Training Institute at the Farmingdale State College and Stony Brook University campuses and additionally providing grant funds for the Center of Excellence for Offshore Energy at SUNY Maritime College. The developers of the Sunrise Wind project will spend $10 million on the Offshore Wind Training Center at Suffolk County Community College. (See related story, Preparing the Wind Energy Workforce.)
Brian Sabina | NJEDA
Brian Sabina, senior vice president of economic transformation at the New Jersey Economic Development Authority, said Gov. Phil Murphy wants to expand opportunities for good-paying OSW jobs through “on-ramps and off-ramps” so that people can “earn and learn at the same time,” especially people of color and women.
“We’ve more than doubled participation in apprenticeship programs by Black, Latinx and female apprentices,” Sabina said.
One area where apprenticeships are needed is welding, a skilled trade that Sabina said has leveled off in New Jersey. That is where increased regional cooperation comes into play, according to Hastings.
Laura Hastings | RI Department of Labor & Training
“Welding is robust in Rhode Island and Connecticut, as we can build nuclear submarines, largely with welders, so that’s one way we can use regionalization to play on each other’s strengths versus what we don’t have,” Hastings said.
“There’s definitely the opportunity for direct or indirect collaboration on workforce training,” Vestal added. “I think there’s the ability to send workers to different states to make this a regional workforce rather than a state-by-state workforce.”
For students in either high school or college considering the OSW industry, Hastings said that critical-thinking and problem-solving skills are in-demand attributes, aside from education and training initiatives.
“Being able to look at something critically and come up with a new solution that doesn’t exist yet, this industry is ripe for that, and if that’s the kind of person and kind of thought process that you go through, that would only help you,” Hastings said.
A set of longstanding agreements do not obligate Xcel Energy’s Colorado utility subsidiary to provide an electric cooperative with priority firm transmission service to deliver energy from two third-party suppliers, FERC affirmed Thursday (EL20-14-001).
The commission’s ruling on rehearing stemmed from a dispute between Xcel’s Public Service Company of Colorado (PSCo) subsidiary and Glenwood Springs-based Holy Cross Electric Association, a co-op that serves about 55,000 customers in Eagle, Pitkin, Garfield, Mesa and Gunnison counties.
Holy Cross entered into two power purchase agreements with the Arriba (wind) and Hunter (solar) projects and asked PSCo to provide it with firm transmission service to deliver the contracted energy under a grandfathered transmission agreement between the companies — and not under PSCo’s Open Access Transmission Tariff.
In December 2019, PSCo asked FERC to rule that Holy Cross’ requests are not permitted under the companies’ power supply agreement, transmission integration and equalization (TIE) agreement, or operating agreement for economy — or non-firm — energy purchased by the co-op.
The power supply agreement stipulates that Holy Cross will purchase its full requirements from PSCo but that it may purchase economy energy from third-party suppliers. The TIE agreement lays out the terms under which PSCo and Holy Cross have agreed to operate their respective transmission networks as one system, with PSCo serving as the operator. The operating agreement sets out the procedures for scheduling and accounting for economy energy purchased by Holy Cross.
On March 31, FERC ruled that Holy Cross was not entitled to firm transmission service from PSCo under the agreements, concluding that the co-op’s capacity on the integrated system is limited to its load ratio share and that the additional firm service would exceed that share. The commission also pointed out that PSCo is not obligated to treat economy energy purchases as firm deliveries entitled to NERC’s highest curtailment priority.
Holy Cross Electric serves 55,000 customers in western Colorado. | Holy Cross Electric
On April 30, Holy Cross filed a request for rehearing and a conditional request for clarification of the March order. The co-op contended that the TIE agreement is governed by Colorado law, which holds that “written contracts that are complete and free from ambiguity will be found to express the intention of the parties and will be enforced according to their plain language.” Holy Cross added that Colorado legal precedent holds that, in contract disputes, parol evidence (that is, oral evidence from outside the actual contract) is only permitted when a contract is ambiguous, and that “a contract’s silence does not necessarily invite the introduction of parol evidence to clarify intent.”
Holy Cross contended that FERC’s March order provided no evidence that the TIE agreement is ambiguous, and it challenged the commission for using the power supply and operating agreements as parol evidence to interpret the TIE agreement, which it argued is separate from the other two agreements.
The co-op also contended “that the load ratio share capacity entitlement under the TIE agreement cannot reasonably be construed as limited to Holy Cross’ purchases from PSCo because the ‘detailed and unambiguous wording’ of the TIE agreement shows that Holy Cross’ ‘load ratio share capacity rights are a function of its native load and not any specific Holy Cross resource, including the power supply agreement,’” FERC noted.
‘Untenable’
The commission brushed aside that argument, calling it “untenable.” The issue at hand, the commission said, “is whether Holy Cross is entitled to firm transmission service for certain third-party purchases, which requires an analysis of the TIE agreement, power supply agreement and the operating agreement.” The commission had properly considered the rights of both parties under the three agreements without resorting to use of parol evidence, it said.
“In interpreting the term ‘load ratio share’ under the TIE agreement, the commission appropriately cited the definition in section 1.9 of that agreement, which references the method for calculating load ratio share in Appendix A, provision 6, to conclude that Holy Cross’ load ratio share is based on its requirements demands,” FERC wrote. “The commission did not look to any agreement other than the TIE agreement in interpreting the term ‘load ratio share’; nor did the commission look outside the TIE agreement to determine Holy Cross’ transmission capacity entitlement under the TIE agreement.”
While the TIE agreement lays out Holy Cross’ transmission entitlement, it does not address the question of whether the co-op’s request for additional firm service fits within that entitlement, the commission said. To make that determination, FERC examined the power supply agreement, which requires Holy Cross to purchase its full requirements from PSCo with exceptions made for economy energy.
“That Holy Cross is currently required to purchase its full requirements from PSCo is based on Holy Cross’ obligations under the power supply agreement and is not, as Holy Cross contends, an interpretation of the term ‘load ratio share’ under the TIE agreement,” FERC said. “Rather, given that Holy Cross’ load ratio share of the integrated transmission system is based on its requirements demands, and it is currently required by the power supply agreement to purchase its full requirements from PSCo, it necessarily follows that Holy Cross’ firm transmission capacity entitlement is being used to serve the full requirements of Holy Cross’ load, and that ‘for Holy Cross to obtain firm transmission service to receive power from the Arriba and Hunter projects, Holy Cross would require transmission capacity that is in excess of its load ratio share of the capacity of the integrated system.”
The commission additionally rebuffed Holy Cross’ contention that the March order prevents the co-op from using its rights under the TIE agreement on a basis comparable to PSCo. Holy Cross argued that the TIE agreement embodies FERC’s “golden rule” of comparability, which prohibits either party from making “adverse distinctions” about the other party’s use of an integrated transmission network.
“This argument … incorrectly presumes that the TIE agreement is the equivalent of an open access transmission tariff, which it is not,” the commission said. “As PSCo explained in its petition, the TIE agreement is a grandfathered transmission service agreement that predates Order No. 888.”
FERC on Thursday gave NERC and WECC the go-ahead to introduce regional reliability standard BAL-002-WECC-3, but it also ordered the organizations to return in 2023 with a progress report on its effects on the bulk power system (RM19-20).
The new standard takes the place of BAL-002-WECC-2a, approved by FERC in January 2017 as the regional equivalent of the continent-wide BAL-002-3 (Contingency reserve for recovery from a balancing contingency event) and successor to the original regional standard BAL-002-WECC-2. The standards specify the “quantity and types of contingency reserve required to ensure reliability under normal and abnormal conditions.”
The WECC standard includes a more stringent deadline for entities to restore contingency reserves following a disturbance recovery period: 60 minutes compared to 90 for the NERC equivalent. In addition, the WECC-mandated method for calculating minimum contingency reserves is more stringent than that given in the NERC standard because it requires “minimum contingency reserve levels that will be at least equal to the reliability standard minimum … and more often will be greater.”
Regional Requirement to be Removed
NERC and WECC originally submitted the new regional standard to FERC last September, arguing that some aspects of BAL-002-WECC-2a had been made redundant by the BAL-003-1 standard introduced in 2014.
| WECC
In particular, the organizations claimed that requirement R2 of the regional standard — mandating that balancing authorities and reserve sharing groups in the WECC region maintain at least half the minimum contingency reserves as operating reserves — was no longer necessary. Requirement R1 of BAL-003-1 “addresses the same frequency response components … but in a results-based manner” because of its requirement that BAs “achieve an annual frequency response measure that is equal to or more negative than its frequency response obligation.”
To address any potential concerns about reliability impacts from retiring the 50% spinning reserve requirement, WECC performed a field test from May 2017 to April 2018 in which it obtained data from each BA and reserve sharing group on disturbance control standard (DCS) performance and frequency response in the Western Interconnection. In their petition to FERC, NERC and WECC said that “all 66 DCS events occurring during the field test period had a 100% pass rate, showing no degradation to DCS performance.”
Not satisfied with the submission, FERC issued a data request in February 2020 to the organizations seeking further data from May 2018 to September 2019, along with NERC’s frequency response records for the Western Interconnection from May 2017 to September 2019. The updated information was submitted in May 2020.
Standard Approved; Monitoring to Continue
With the expanded data set continuing to support NERC and WECC’s assertion, FERC gave its approval to the standard as “just, reasonable … and in the public interest.” However, the commission indicated it still holds reservations about “unique aspects of contingency reserves in the Western Interconnection [that] raise concerns about deliverability of contingency reserves within reserve sharing groups.”
Specifically, FERC noted that both the Northwest Power Pool and the Southwest Reserve Sharing Group contain BAs that have hydroelectric resources, which “represent a significant share of … contingency reserves.” The commission expressed concern that transmission constraints or limits on the hydroelectric system may constrain the ability of member BAs to access these resources.
As a result, FERC ordered that NERC and WECC submit an additional informational filing 27 months after the implementation of BAL-002-WECC-3, covering the same categories of data from the February 2020 data request for the 24 months following implementation. The commission also mandated that the organizations inform it immediately of “any adverse impacts resulting from the retirement of requirement R2” that are observed during the reporting period, along with any corrective actions that are taken or considered.
FERC on Thursday approved CAISO’s procedure for distributing more than $2 million in penalty proceeds and nonrefundable interconnection study deposits to its members (ER20-2604).
CAISO’s Tariff requires it to collect penalties for violations of its rules of conduct and deposit them in an interest-bearing trust account. At the end of each calendar year, CAISO distributes the proceeds, with accrued interest, to eligible market participants based on a formula that factors in the pro rata share of the grid management charge paid to the ISO by each participant. The Tariff also requires CAISO to seek FERC’s approval for any disbursements of penalty proceeds, which totaled $622,500 in 2019.
“The methodology in CAISO’s proposal is consistent with relevant provisions in its Tariff for allocating and distributing penalty proceeds to scheduling coordinators,” FERC found.
CAISO had also petitioned FERC for permission to distribute $1,452,574.98 in nonrefundable interconnection study funds for projects interconnecting to Southern California Edison’s distribution system. The ISO noted the funds would be allocated to market participants without accounting for whether a participant had been assessed a financial penalty over the course of the year.
FERC determined that the methodologies in CAISO’s proposal were consistent with its Tariff. The commission concluded that “our decision to grant the petition is consistent with the commission’s disposition of prior CAISO filings where it proposed to distribute forfeited interconnection study funds with interest … without accounting for whether or not a scheduling coordinator had been assessed a financial penalty under section 37 or Tariff during the relevant calendar year.”
MISO is wrapping up its 2020 Transmission Expansion Plan (MTEP 20) with an eye on next year’s planning cycle that contains more aggressive renewable energy predictions.
MTEP 20 includes 514 projects costing slightly more than $4 billion. The most expensive project remains Ameren’s new Massac substation in Southern Illinois and the conversion of the nearby Joppa station from 230 kV to 345 kV, at an estimated cost of $112.4 million.
“At this time of the year, we’re ending MTEP 20 and starting MTEP 21,” planning engineer Scott Goodwin told stakeholders during a Planning Subcommittee meeting Tuesday.
MISO has closed the request deadline for special targeted study requests to be conducted under MTEP 21.
The Environmental Groups sector has requested the grid operator conduct two studies examining footprint changes if either LG&E and KU Energy or Memphis Light, Gas and Water join MISO within the next five years.
Transmission owners oppose the request. “We didn’t think MTEP is the place to evaluate new members. It’s about evaluating transmission projects,” Entergy’s Yarrow Etheredge said.
Goodwin said MISO will begin scheduling MTEP 21 subregional planning meetings to discuss project needs. The RTO will also soon release MTEP 21 economic models that draw on its new, 20-year futures scenarios, economic planner Nickolas Przybilla added.
The grid operator is relying on a combination of integrated resource plans and utilities’ public carbon-reduction commitments to predict resource siting under the new planning futures.
“It’s both the media and IRPs,” MISO Planning Manager Tony Hunziker said during a Planning Advisory Committee conference call Wednesday. “It’s recognizing that sometimes a press release precedes plans and also recognizing that not all utilities have to file integrated resource plans.”
Hunziker said MISO is drawing on the National Renewable Energy Laboratory’s Annual Technology Baselines to help predict when generation technologies are increasingly adopted.
MISO’s Future I expects solar expansion on par with the footprint’s current amount of wind generation. In Future II, the RTO foresees energy storage and electrification beginning to join solar on center stage. By Future III, electrification and storage take a consequential role in supply and demand, while wind and natural gas generation each taking a 30% share of the energy mix. Future III also assumes 50% renewable energy use.
Some stakeholders said MISO should not simply take utilities’ target announcements at face value and should rely on something more concrete to make future generation assumptions.
“I just don’t think we have evidence that utilities waffle a lot. I don’t think we have a record like that,” Clean Grid Alliance’s Natalie McIntire said. “When utilities make announcements, they tend to be well thought out.”
States, cities and utilities in the MISO footprint are fast piling up carbon-reduction goals.
Michigan is the latest state to announce a carbon-neutrality goal. Gov. Gretchen Whitmer late last month said the state will meet a net-zero emissions goal by 2050, if not sooner. The announcement late last month will likely cause utilities to rethink their IRPs.
Ameren and Entergy have also committed to carbon neutrality by 2050.
Queue Timeline Cutbacks Still in the Works
To reach those targets, MISO must make headway on the 106 GW of mostly renewable generation in its generator interconnection queue’s 705 projects.
The mammoth queue is down from a record 756 projects, totaling 113 GW, in August. MISO said about 20 interconnection customers in its South and West planning regions failed to provide proof of site control and were forced to withdraw projects.
To speed up queue processing, the grid operator plans to whittle down the three-part definitive planning phase and generation interconnection agreement negotiations from more than 500 days to a calendar year. (See Record Number of Entrants Line up for MISO Queue.)
MISO engineer Miles Larson said the RTO plans to cut about 140 total days from queue processing so it can catch up on projects and bring the four planning regions’ studies into the same queue-cycle year. MISO is currently processing queue cycles dating back to 2017.
“We continue to see an overwhelming support for reducing the [generation interconnection process] timeline,” Larson said during an Interconnection Process Working Group conference call Monday.
MISO wants GIA negotiations and execution pared from about 150 day to 100 days. That means some negotiations will simultaneously occur as staff wrap up final network upgrade studies.
Larson said MISO wants to arrive at a “repeatable and sustainable” process to keep the queue humming.
“The closer we can get our process to 365 days, the closer we get to aligning the DPP study process with the MTEP study process,” he said, referencing MISO’s plan to better match MTEP planning with network upgrades necessary for interconnections.
Larson said that for the cutbacks to stick, interconnection customers need to ready their generation projects as much as possible before entering the queue.
“MISO alone cannot reach the reduction goal,” he said. “In order to succeed in this effort, every entity needs to identify internal efficiency opportunities.”
