WECC’s Stakeholder Engagement Task Force (SETF) last week floated a straw proposal that would make sweeping changes to the regional entity’s stakeholder group structure by consolidating or replacing most of its standing committees while winnowing out subcommittees not engaged in vital projects.
The proposal would have WECC retain its Reliability Assessment Committee (RAC) while disbanding the Market Interface (MIC) and Operating (OC) committees. It would also create a new Operations, Security and Market Interface Committee (OSMIC). Membership in the two remaining committees would be limited to a fixed number of stakeholders serving staggered terms, WECC said.
The RAC is the key stakeholder group involved in WECC’s resource adequacy initiative. “The RAC has developed a study program that provides reliability assessments aligned with the WECC Long-Term Strategy and Reliability Risk Priorities,” the SETF wrote. “Because this is a committee focused on delivering impactful work products, we propose to retain this committee.”
WECC earlier this year identified RA as seminal to its “invented” future, which is “characterized by a partnership where we put a strong focus on collaborating with stakeholders to strive for what we consider to be our common goal of having a reliable and secure interconnection.” (See WECC Seeks to ‘Invent’ Future with RA Forum.)
Meanwhile, the SETF said that while the OC and the MIC periodically deliver work products, they are primarily “networking and information sharing” committees.
“We believe that the primary purpose of the standing committees should be the delivery of seasonal, quarterly, annual or biannual work products. Stakeholder networking and information sharing should be viewed as a secondary benefit of participation on a standing committee,” the proposal contends.
The SETF plan would also disband the Joint Guidance Committee and create a new Performance Review Board (PRB) “to ensure the RAC and OSMIC are delivering relevant and timely work products to the appropriate audiences.”
The PRB would establish performance and stakeholder metrics to gauge the output and effectiveness of standing committee projects. The performance metric would focus on the “quantity and timeliness” of a committee’s work, possibly measuring the number of work products produced and the ability to meet deadlines. The stakeholder metric could focus on the “quality and dissemination” of that work, with specific metrics for the number of downloads or requests for presentations of a work product by outside organizations.
“We believe the best way to improve both the quality and quantity of stakeholder engagement at WECC is to give stakeholders the chance to help develop timely, relevant and meaningful work products. If WECC is producing rigorous and impactful work products, the best and brightest subject matter experts will want to participate,” the SETF wrote.
The PRB would report to WECC’s Board of Directors. It is proposed to be a small group with members drawn from WECC management, the board and stakeholders. The group would meet “as needed, but at least annually,” to evaluate standing committee performance.
“The PRB should provide guidance and leadership direction to the standing committees. It should not simply monitor the standing committees. The PRB should be an ‘active,’ not a ‘passive,’ body that scrutinizes the work of the standing committees,” the proposal states.
The proposal would also see WECC staff move beyond providing “administrative assistance” to stakeholder groups to assuming more of a “partnership” role in which those staff would contribute subject matter expertise to committees. WECC’s executive team would also assign a staff member as project management support for every standing committee project or initiative that will produce a work product, “ensuring all work meets WECC’s high standards of quality and rigor.”
The plan also seeks to disband all subcommittees, work groups and task forces not directly involved in developing standing committee work products.
“All stakeholder gatherings to share information, discuss issues and network will be managed through the WECC Strategic Engagement team and will take the form of trainings, workshops and forums,” the proposal said.
WECC is seeking stakeholder comments on the straw proposal by Nov. 2.
Offshore wind advocates are calling for changes to RTO transmission planning and cost allocation rules to reduce costs and development risks for connecting an estimated 30 GW of generation on the East Coast through 2035.
In a white paper released Oct. 26, the Business Network for Offshore Wind lays out its view of the policy options facing FERC, RTOs and states and the changes it says could ensure the most cost-effective transmission buildout. Grid Strategies’ Michael Goggin, who contributed to the paper, will be among 25 witnesses scheduled to appear Tuesday at a FERC technical conference on offshore transmission.
Brandon Burke, policy and outreach director for the Business Network and the primary author of the paper, said current RTO processes fail to capture all the benefits of offshore transmission, particularly that of an interregional network that could improve resilience in PJM, NYISO and ISO-NE.
It also says OSW development could be hamstrung by the “free rider” problem: that transmission upgrades paid for by an individual generator can benefit those who did not contribute.
Potential offshore wind transmission topologies | Business Network for Offshore Wind
OSW Targets, Projections
Connecticut, Maryland, Massachusetts, New Jersey, New York and Virginia have set targets to procure 29.1 GW of OSW by 2035, with almost 6.3 GW of procurements awarded, according to the American Wind Energy Association. The departments of Energy and the Interior say the U.S. could deploy up to 86 GW of OSW, including on the West Coast and in the Great Lakes by 2050. “Aggressive decarbonization” could result in more than 100 GW on the East Coast alone, according to the white paper.
Although OSW resources on the East Coast are relatively close to load centers, they are generally distant from optimal points of interconnection to onshore transmission networks. “In many areas, only lower-voltage transmission and distribution lines extend to the coast, though at certain points high-capacity transmission lines do extend to existing or retired coastal power plants,” the Business Network said. “When the capacity of the existing onshore electricity grid is reached, and low-cost points of interconnection have been utilized, these grid/interconnection constraints could arrest the future growth of the U.S. OSW project pipeline.”
The report identifies eight models for offshore transmission and its cost allocation, including private generator lead lines — the approach being used for the first group of U.S. OSW projects — and one employing partial federal funding.
Planned vs. Project-by-project Approach
“The optimal outcome will almost certainly involve a mix of both generator tie-line and network elements,” the group said. “While there is debate about the optimal configuration of offshore transmission and the onshore grid upgrades necessary to integrate it, a planned transmission strategy is almost always ultimately more efficient than an unplanned, project-by-project approach.”
An offshore transmission network that connects multiple OSW projects would optimize onshore upgrades and make more efficient use of the limited number of optimal onshore interconnection points. It also could benefit from economies of scale by using higher-capacity transmission lines and converter stations, the Business Network says.
Networked offshore transmission also would allow for rerouting power during interruptions on a single tie line and increase the utilization factor of individual network lines “because geographic diversity causes wind plants to have different output patterns, allowing sharing of network capacity.”
Brattle Group analyses of New England and New York have found that a planned approach could minimize environmental disruptions by reducing the total length of installed cable by about half versus a project-by-project approach.
Costs, Curtailments
The paper says putting 30 GW of OSW in service would require about $100 billion in capital spending, up to $20 billion of it for offshore transmission; onshore upgrades would be “comparably large.”
It cited a Brattle study that a planned offshore network in New England would cost $500 million less in capital spending with savings of $55 million annually from reduced power losses. It could also produce another $300 million in yearly savings by delivering power to higher-priced locations on the grid.
After the first 6.7 GW of OSW is installed, Brattle said, using generator tie-lines to interconnect the remaining 8 GW of capacity in the New England OSW lease areas would result in 13% curtailment, compared with 4% under a planned approach.
East Coast wind lease areas and major onshore transmission | Business Network for Offshore Wind
Risks of Network Model
But the paper acknowledged “considerable debate regarding whether a planned offshore transmission network connecting multiple OSW facilities to shore versus an incremental approach driven by generator tie lines serving individual OSW installations will better facilitate the steady expansion and long-term success of the U.S. OSW industry.”
An offshore network entails more regulatory, political and other risks than generator tie lines for individual projects, which it said can undermine the ability to attract investors.
“As the scale of the proposed transmission solution increases, from an individual offshore wind facility tie line, to a line serving multiple OSW projects, to a network line with multiple onshore points of interconnection, and finally to an interregional offshore network, there are increases in both the potential benefits and the policy and political challenges that must be overcome. …
“The permitting process [for shared offshore transmission] is at best unclear,” the Business Network said, noting FERC’s ruling in July that PJM can deny injection rights to merchant offshore transmission networks unless the project also connects to another grid operator. (See FERC Rules Against Anbaric in OSW Tx Order.) Anbaric appealed the ruling to the D.C. Circuit Court of Appeals on Oct. 16.
Role for Government
The paper said “the most fundamental problem” with RTOs’ transmission planning is the reliance on the generator interconnection queue process to determine what transmission should be built. “The lens of generator interconnection is just one of many benefits of those transmission upgrades.”
Because of the “free rider” phenomenon, the white paper says “there is an essential role for government policy in ensuring that adequate transmission is built to realize … societal benefits, similar to the role governments play for highways, sewer systems and rail networks.”
In many regions, the cost of large upgrades to the grid are assigned to interconnecting generators even though the upgrades benefit the entire region, the group said. “An analogy to that policy would be requiring the last vehicle entering a congested highway to pay the full cost of adding another lane to the highway.”
Potential landing spots for offshore wind generators | Business Network for Offshore Wind
The group said the risks of network models can be reduced by policy changes clarifying “how transmission will be planned, paid for and permitted.”
The white paper also sees a potential role for DOE in optimizing transmission development, noting that three RTOs and their 20 states and D.C. will have roles in determining transmission planning and cost allocation for OSW on the East Coast.
“Currently, there is no single entity responsible for planning offshore transmission across the East Coast, convening stakeholders and working with the industry and states on transmission options,” it said, suggesting DOE could provide technical research and support for stakeholder engagement. “Potential studies include analyzing the benefits of different scales and configurations of transmission expansion, quantifying how expanded transmission can reduce capacity and energy costs by capturing interregional diversity in electricity supply and demand, and finding solutions that minimize the total cost of onshore and offshore transmission.”
Beyond Order 1000
It called on FERC to build on Order 1000 by requiring RTOs to incorporate public policy requirements — such as states’ renewable portfolio standards and OSW procurements — into transmission planning. Order 1000 “only required regions to ‘consider’ public policy requirements. State OSW mandates and procurements need to be integrated into transmission planning, as they are law and the procured offshore projects are being built,” it said.
The group also says current interregional transmission planning processes have failed to identify large projects that would benefit multiple regions because “although Order 1000 requires neighboring transmission planning regions to coordinate planning, it does not require a joint process or evaluation of interregional solutions and their benefits.”
PJM’s response to Order 1000 — the “state agreement” approach — “provides an opening for eastern PJM states with OSW targets to partner [and] pay for transmission” but fails to address the free rider problem, the Business Network said. “If a state will benefit from another state’s transmission investment whether they pay for it or not, they have little incentive to pay for it. However, if each state refuses to pay for transmission upgrades that benefit the entire region, nothing gets built and the entire region suffers.”
It said the interconnection queue cluster process, in which a large number of interconnection applications are evaluated simultaneously and share upgrade costs, could achieve some economies of scale but also fails to allocate the costs to all those who will benefit from additional transmission capacity. “Moving transmission planning and cost allocation to the regional transmission planning process is the only solution for that problem,” it said.
The current interconnection process also leaves generation developers at risk that initial upgrade estimates will escalate if others in the transmission queue drop out.
Counting all Benefits
The Business Network also says RTOs are “leaving economic, reliability, resilience, hedging and other benefits on the table” because they are difficult to quantify. “In cases in which precise quantification is not possible, using an estimate will result in a more optimal level of transmission investment than arbitrarily assigning zero value to a benefit that is widely acknowledged to be large. If benefits are not quantified, they should be at least qualitatively taken into account in the planning process.”
It said transmission planners should use at least a 15-year time horizon for OSW transmission cost-benefit analyses and use advanced modeling to co-optimize transmission and generation planning.
RTO planners “have chosen short time horizons, often 10 years, to calculate the benefits of transmission because of future uncertainty around generation and load. With renewable resources, however, future generation additions will occur in the locations with optimal resources. Those locations are known today and are unlikely to significantly change over time,” the Business Network said. “Transmission assets typically have a useful life of 40 years or more, and that lifetime can often be indefinitely extended by replacing key pieces of equipment.”
Success Stories of Proactive Tx Development
As examples of the “proactive” approach to transmission planning that facilitates renewables, the Business Network cited Texas’ Competitive Renewable Energy Zones, California’s Tehachapi Wind Resource Area near Los Angeles and MISO’s Multi-Value Projects.
“MISO’s approach considers the value of transmission for meeting economics, reliability and public policy (renewable interconnection to meet state RPS requirements) needs. MISO made sure to spread planned transmission projects across the entire MISO footprint to ensure that all zones received projects and had a strong benefit-to-cost ratio, ensuring their support for the overall portfolio.”
The Colorado Public Utilities Commission last week dismissed formal complaints filed against Tri-State Generation and Transmission Association by two of its members, saying it lacked legal jurisdiction to rule on the proceeding.
In a 3-0 vote during a deliberations meeting Thursday, the PUC determined that FERC’s August order affirming its exclusive jurisdiction over Tri-State pre-empted it from acting on exit-fee disputes raised by La Plata Electric Association and United Power (19F-0620E, 19F-0621E).
Tri-State and two of its largest members have been battling before the PUC and in district court over the amount of fees to leave the G&T cooperative. Tri-State claimed FERC jurisdiction last year by accepting non-utility member MIECO, a natural gas trader. It subsequently proposed a contract-termination payment methodology that FERC accepted in August. (See FERC Affirms its Jurisdiction over Tri-State G&T.)
The PUC said the order reversed an earlier FERC decision allowing the complaints to proceed at the state commission.
The Colorado commission found it also did not have jurisdiction to determine whether Tri-State’s admission of MIECO is proper under state law because the question is “a matter of corporate law, not public utilities law.” It suggested that United continue pursuing its pending case in Adams County District Court challenging MIECO’s membership.
“That court is where the question of MIECO’s membership should be answered,” the PUC said. “Because [FERC] dismissed the formal complaints without prejudice, the PUC will be ready to adjudicate the exit fee questions if United Power prevails.”
Tri-State CEO Duane Highley said in a statement that the cooperative was “pleased” with the PUC’s decision, and that “questions of Colorado corporate law are a matter for the state courts.”
Tri-State has 42 utility members and 45 overall in its four states but has been troubled in recent years by member complaints about high rates and its slow embrace of renewable energy. It reached an exit agreement with Delta-Montrose Electric Association earlier this year. Kit Carson Electric Cooperative was the first to leave Tri-State in 2016.
Last week, Tri-State said it has filed for FERC approval of its community solar program. Gunnison County Electric Association will be the first member to participate in the program, which the cooperative said provides additional flexibility for its members’ community solar projects.
As he is often wont to do, American Electric Power CEO Nick Akins opened his company’s third-quarter earnings call with financial analysts Thursday by quoting a rocker. He used Lenny Kravitz’ hit “Fly Away” to symbolize the shared pain “many of us have … during 2020 with these multiple challenges”:
“‘I wanna fly away.’
“Probably figuratively and literally,” Akins mused. “But there is light at the end of the tunnel.”
AEP’s year-to-date residential sales are up 2.6% when compared with last year, largely because of people spending more time at home during the COVID-19 pandemic, Akins said. Commercial and industrial sales are still down year-to-date, 4.9% and 7%, respectively, but showing signs of life.
“Both our commercial and industrial classes are showing steady improvement from the low we experienced in the second quarter as some businesses reopened over the summer,” he said. “We expect this trend will continue into 2021, barring additional unanticipated negative economic impacts from the pandemic.”
AEP reaffirmed its 2020 operating earnings guidance range of $4.25 to $4.45/share.
Akins headed off questions about the ongoing federal investigation into an alleged bribery scheme tied to the passage of Ohio House Bill 6 during his prepared remarks. (See FirstEnergy, AEP CEOs Deny Wrongdoing.)
AEP’s C&I sales are showing improvement since the pandemic-induced shutdowns. | AEP
“I’ll just say flatly that we have nothing new to report from AEP’s perspective,” he said. “Any potential legislative change is not imminent, particularly given a noisy election cycle. So, perhaps we’ll hear more after the election.
“As we’ve said earlier, any change to the existing legislation is likely to be financially insignificant for AEP, and we will still be pushing for forward-looking legislation regarding clean energy options, energy efficiency and other technology enhancements,” Akins said. “Regarding the legal issues surrounding HB6, also nothing new to report, and my previous comments stand on this subject.”
AEP’s share price, which closed Wednesday at $90.40, closed at $92.20 on Thursday, the highest it been since early March.
SPP staff are busy preparing to address critical comments on the grid operator’s revised Tariff for its Western Energy Imbalance Service (WEIS) as they work to keep the project on track.
The latest filing has drawn more than a dozen intervenors (ER21-3, ER21-4), including repeat protesters Xcel Energy-Colorado, Colorado Springs Utilities and Black Hills Energy. All three Colorado utilities plan to join CAISO’s Western Energy Imbalance Market.
“After a quick read of the comments and protests, the issues are similar to what we have seen in the past,” SPP’s Nicole Wagner said during the Western Markets Executive Committee’s webinar Friday.
RTO staff held a premeeting with FERC staff a couple weeks ago and will meet this week among themselves to determine next steps and how they will reply to comments and protests. SPP has asked for a response by Dec. 1, which would keep the WEIS market on track for its Feb. 1 go-live date.
FERC staff’s primary concern is with the Tariff’s joint dispatch transmission service (JDTS) provisions. SPP staff will collaborate with WEIS transmission providers to ensure their respective tariffs incorporate the correct JDTS language.
David Kelley, SPP’s director of seams and market design, said the regulatory delay has left the WEIS program in yellow status, which the RTO defines as “needing attention.”
Market trials are also considered in yellow status as participants gear up for the start of parallel operations on Dec. 10. Participants are currently testing dispatch signals to resources but will begin “playing” in the production environment during parallel ops.
SPP will launch the WEIS with eight members covering the Western Area Power Administration’s Colorado Missouri and Upper Great Plains West balancing authority areas.
The market, based on the Energy Imbalance Market that SPP operated from 2007 to 2014, continues to attract interest in the West. Bruce Rew, SPP’s senior vice president of operations, recently told the RTO’s stakeholders that several additional utilities reached out to the grid operator following the rolling blackouts in California late this summer. (See Theories Abound over California Blackouts Cause.)
California’s port infrastructure will pose a key — but not insurmountable — obstacle to the development of floating offshore wind (FOSW) projects along the state’s coastline, industry experts said Thursday.
The subject arose during a scoping workshop the California Energy Commission convened to seek public input on its “draft research concept” regarding the development and testing of FOSW technology.
While West Coast offshore wind development lags that of the East Coast, 14 developers responded to the U.S. Bureau of Ocean Energy Management’s 2018 call for information and nominations to develop wind facilities off the coast of California. Development is more of challenge along the West Coast compared with the East because of the very narrow continental shelf and steep drop-off close to shore, necessitating the construction of floating — rather than fixed-bottom — turbines. (See Differences Aside, West Coast OSW Can Learn from East.)
BOEM’s three call areas off the California coast are located in remote areas far from the state’s major ports. | BOEM
During Thursday’s virtual workshop, the CEC laid out a tentative objective that state-funded research projects support “the development and pilot demonstration of innovative floating offshore wind component(s) and installation processes that advance the readiness, reliability and cost-competitiveness of floating offshore wind in California.” It also seeks to increase understanding of how FOSW will affect sensitive wildlife species and habitats in the region.
The final research concept will guide the CEC’s investment plan for dispensing grants through California’s ratepayer-funded Electric Program Investment Charge (EPIC) program, which currently invests about $130 million annually across all energy research and pilot programs.
During the workshop, Alla Weinstein, CEO of Castle Wind, said she thinks a key issue was omitted from the CEC’s stated objective. She noted that a still unreleased report by the National Renewable Energy Laboratory, discussed publicly during a recent California Public Utilities Commission meeting, found that the “distance to port” for projects in federal lease areas will be the “main driver” of the cost of energy for California FOSW.
BOEM’s call for nominations designated three sites for development, including the Humboldt Call Area off California’s remote North Coast and the Morro Bay and Diablo Canyon call areas off the sparsely populated Central Coast.
“The distance to port is one element, but also the port infrastructure and limitations that are visible right now are going to be the biggest challenges the industry is going to face,” Weinstein said.
The CEC failed to include the issue as one of its main focus areas despite the fact that “it is the single most important [factor] for the levelized cost of energy [LCOE], and it should be included as one of the top priorities,” Weinstein said. The CEC’s Silvia Palma-Rojas earlier told workshop participants that the commission is targeting an LCOE of $75/MWh or lower for California FOSW.
Sam Kanner, offshore wind lead for the independent Otherlab, noted that many California ports “are inaccessible to floating wind designs because of transit draft and air draft considerations from bridges or whatnot.”
“In California, there are only a few ports that could handle floating offshore wind, maybe six or so, and the largest ones are quite far away from the current lease areas,” said Markus Wernli, assistant vice president at civil engineering firm WSP USA. “That compares to the East Coast, where you could draw a circle of 50 miles and get 27 ports out of it.”
Wernli advised the CEC to focus on those ports that can most feasibly handle FOSW development. He said the commission should “help people in those communities around those ports understand what it means to have a facility that does work in offshore wind.” He recommended the state develop environmental and economic studies for those areas and assess supply-chain logistics.
Jason Cotrell, CEO of RCAM Technologies, which specializes in 3D concrete printing of renewable energy structure components, emphasized the importance of the state’s role in studying its ports. He recounted how the New York State Energy Research and Development Authority (NYSERDA) performed a 2018 study of that state’s port infrastructure for suitability for OSW development.
That study “identified 11 relatively small ports, many of them behind bridges, many of them underutilized, as potential candidates,” Cotrell said. “Too small for a staging of an offshore wind plant, but certainly potentially valuable.”
Cotrell’s company determined it could have used a small Brooklyn port identified in the report to annually produce “something like $50 million” in offshore wind components using its 3D printing technology. He said wind developer Equinor later chose the site as an operations-and-maintenance base for its offshore facilities.
Studies such as the one performed by NYSERDA are “very important to small companies like ours that have limited means and resources to perform these studies ourselves,” Cotrell said, adding that new technologies could unearth the manufacturing and O&M of ports that have been previously “written off.”
“So, there may be a lot of potential that perhaps some of us have not seen yet in California ports,” Cotrell said.
Pilot Concerns
Some workshop participants took issue with another aspect of the CEC’s objectives, advising the commission against seeking to develop a full-scale FOSW pilot, saying the cost would far exceed EPIC grant budgets.
“If the funding is intended to put hardware in the water and do a physical demonstration, you’re looking at a very large sum of money, and that is in the tens of millions of dollars,” Weinstein said. “I think there needs to be a realization that installing a full-size prototype in the water probably will not happen just because of the amount of money that will be required is beyond the funding that you have and the cost-share that would be required would be effectively prohibitive.”
Weinstein said that, unless a pilot is installed in state waters — which would not be representative of the actual builds in federal lease areas — it will require a lease from BOEM “that takes years and a lot of money and will not really lead to a demonstration project.”
“I think it’s really important for the commission to understand that developers are poised and ready to build utility-scale off the coast of California,” said Ross Tyler, senior developer at RWE Renewables. “Yes, there are still lots of unknowns from a technical perspective, but some of the technical challenges are being addressed as we speak, and I think [EPIC] is a noble effort to be part of that.”
But Tyler agreed with Weinstein that a full-scale pilot would be cost-prohibitive and said the industry is not really seeing demonstration projects, which would have to be permitted by BOEM and completed within the next three years.
“I think you really need to take a look and perhaps eliminate this notion of having pilot-scale in the water. Otherwise, the developers will not really be interested in participating. That’s my take,” Tyler said.
Cotrell agreed with Weinstein and Tyler about the infeasibility of a full-scale FOSW pilot but did see potential benefits from pilot projects for individual FOSW components.
“For example, in our case, we have some concepts and a little bit of funding to explore the 3D concrete printing of suction bucket anchors, which are the third-most capital-intensive component of a floating wind turbine,” behind the turbine itself and its foundation, Cotrell said.
He said his company could manufacture those anchors and even tow them out to sea and embed them at pilot-scale but could not attach them to a full-scale FOSW turbine at EPIC funding levels.
“I just wanted to offer the different perspective of a component developer that pilot-scale tests and projects are certainly possible, but a lot of care has to be taken with the definition,” Cotrell said.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
B. The MRC will be asked to endorse revisions to Manual 15: Cost Development Guidelines resulting from the biennial periodic review process. The revisions include reformatting and rewording in sections 2.6.1 and 2.6.8 to provide more clarity.
Endorsements/Approvals (9:10-9:45)
1. 2020 Installed Reserve Margin Study Results (9:10-9:25)
Members will be asked to endorse the 2020 Reserve Requirement Study results, including the installed reserve margin (IRM) and forecast pool requirement (FPR). PJM is recommending an IRM of 14.4%, down from 14.8% in 2019. The FPR is essentially the same as 2019, at 1.0865 (8.65%) instead of 1.086 from the previous year. The study determines the IRM and FPR for 2021/22 through 2023/24 and establishes the initial values for 2024/25. The results are based on the 2020 capacity model, load model and capacity benefit of ties. (See “Installed Reserve Margin Study Results,” PJM PC/TEAC Briefs: Oct. 6, 2020.)
2. Liquidation Process (9:25-9:45)
Members will be asked to endorse proposed Tariff and Operating Agreement revisions addressing PJM’s rules for liquidating defaulted financial transmission rights positions. PJM is looking to re-establish the ability to liquidate defaulted FTR open positions and to provide flexibility in the way it exercises liquidation rights based on market liquidity, the size of the defaulted portfolio and market conditions. (See “Liquidation Process,” PJM MRC/MC Briefs: Sept. 17, 2020.)
MC endorsement will be sought on the same day.
Members Committee
Endorsements/Approvals (12:45-1:15)
1. Schedule 9-2 Options (12:45-1:00)
Stakeholders will be asked to endorse near-term changes to PJM’s administrative rates as recommended by the Finance Committee. The RTO recovers its operating expenses through Schedule 9 of the Tariff, with 90% of Schedule 9 revenue tied to actual load multiplied by a transmission factor, and the rest connected to transactional activity.
The transactional FTR billing volume, which has increased 97% since 2011, is tied to Schedule 9-2, PJM said, with the FTR administration service revenues exceeding costs because of an increase in the volume of FTR bidding activity. (See “Schedule 9-2 Options,” PJM MRC/MC Briefs: Sept. 17, 2020.)
Shirley Bloomfield, Lonni Dieck and Deborah Wheeler will join the board effective Jan. 1, 2021, the same date the new bylaws take effect (RR20-2).
SERC’s newest independent board members | SERC
Of the three new directors, Dieck has the most direct utility experience, having served as senior vice president and treasurer at American Electric Power from 2008 to 2019 — part of what SERC notes as “37 years of financial experience, primarily in the utility industry.” Currently, Dieck serves as treasurer of the board at Ronald McDonald House Charities of Central Ohio and on The Women’s Fund of Central Ohio’s board.
Bloomfield is the CEO of NTCA – The Rural Broadband Association, a trade association representing small telecommunications companies operating in rural and remote communities. She has been with the group and one of its predecessors, the National Telecommunications Cooperative Association, for more than 30 years. Bloomfield also serves on the board of the National Rural Telecommunications Cooperative and GlobalWin, a professional association representing women in the tech industry, and has previously worked as a senior executive at both Verizon Communications and Qwest Communications International.
Wheeler has served as chief information security officer at a number of companies, including Ally Financial, Fifth Third Bank, the Federal Home Loan Mortgage Corp. and, since 2017, Delta Airlines. She also serves as governing board chair for Evanta’s CISO Forum in Atlanta and works as an adviser at software companies Proofpoint and Forcepoint.
“This is really an exciting moment for SERC as we continue a governance transformation that will improve the reliability and security of the electric grid,” board Chairman Greg Ford said in a press release. “The addition of three independent directors is essential to our continued strategic growth and will help to provide a balanced, independent perspective to our stakeholder expertise.”
With the appointments of Wheeler, Dieck and Bloomfield, SERC now meets the minimum required number of independent directors for its board under the new bylaws. The board is required to have 15 sector representatives and may have up to five total independent directors.
Other structural changes in store for SERC next year include:
requiring that a majority of the board, as well as a majority of the independent directors, be present to have a quorum for meetings;
eliminating the use of alternates and proxies for directors;
formalizing SERC’s membership body by transitioning the existing board structure into a members group, which will include a representative from each member company and meet at least annually to advise the board on the business plan and budget, elect independent directors and approve bylaw changes as needed;
changing the Board Compliance Committee into the Board Risk Committee; and
adding a Human Resources and Compensation Committee, Nominating and Governance Committee, and Finance and Audit Committee.
Implementation measures include revising SERC’s Regional Reliability Standards Development Procedure (RSDP) to reflect the new structure by, among other things, removing references to board representatives and alternates and replacing references to the SERC Executive Committee with the board. NERC earlier this month posted the revised RSDP for stakeholder comments, which are due by 8 p.m. Nov. 20. (See NERC Opens Comments on SERC RSDP.)
Missouri regulators have opened a working case to determine whether the state’s investor-owned utilities’ continued RTO membership “is in the ratepayers’ best interest.”
The state’s Public Service Commission issued an order on Oct. 14 that directs each IOU to participate in a workshop that has yet to be scheduled and to cooperate with the “investigation.” PSC staff will file a report with their findings by June 30, 2021 (EW-2021-0104).
The order applies to Evergy Missouri Metro, Evergy Missouri West, Empire District Electric and Ameren Missouri. Evergy Metro and Empire are SPP members; Ameren is a MISO member; and Evergy West is a member of both.
The PSC said it “believes there are benefits” to the IOUs’ RTO memberships but that they “exceed the long-term costs and commitments of RTO membership, especially given that the structure, services and membership of both Southwest Power Pool and the Midcontinent Independent System Operator continue to change significantly with the passage of time.
“The commission must inquire into the nature of the benefits of RTO membership, the monetized value of those benefits and what time horizons should be employed to compare asset lives (costs) to the values of benefits streams,” the PSC said.
According to the order, the workshop will determine:
the information needed to respond to the commission’s current and previous orders on RTO membership;
whether such information is reasonably and economically available, and if not, what kind of information could be used as a proxy to control costs and expeditiously respond to the commission;
the cost of gathering, analyzing and interpreting such information; and
whether there are any identifiable “deal breaker” events or event categories that would make it unreasonable for an IOU to remain in an RTO.
SPP said it welcomes the study and stands ready to support its members’ efforts to “evaluate the cost and benefits of their membership.”
“We fully respect that the states and utilities we serve need to ensure they’re receiving adequate value from their membership in SPP,” spokesman Derek Wingfield said. “We remain committed to continually finding new ways of adding value in collaboration with our stakeholders.”
MISO said it is aware of the investigation and is waiting for further guidance on how to assist.
The issue stems back to the early aughts, when the PSC initially placed contingencies on IOUs wishing to transfer functional control of their transmission systems to the RTOs. That allowed the commission to maintain jurisdiction and better understand whether RTO membership would provide the IOUs’ expected benefits, former Commissioner Steve Gaw said.
“At that time, there was no track history to go by in the Midwest, and the net-benefit calculations were estimated,” said Gaw, now with Advanced Power Alliance after six years on the PSC.
The problem has been that the IOUs have continually kicked the proverbial can down the road.
In 2011, the Evergy companies — then operating as Kansas City Power & Light — filed an interim report requesting the commission approve their continued participation in SPP beyond October 2013. In May 2013, the commission approved an interim agreement between KCP&L, PSC staff, the Office of the Public Counsel (OPC), SPP and Dogwood Energy that extended its approval through September 2018 (EO-2012-0136).
Four years later, the commission accepted the companies’ motion to extend the interim period to 2021 and to absolve them of the requirement to file the 2017 interim report.
Ameren Missouri, which does business as Union Electric, received PSC approval in 2012 to transfer functional control of its transmission system to MISO, subject to certain conditions. Those conditions required the utility to file a new case addressing its continued participation in the RTO in 2015. At Ameren’s request, the commission extended the date to November 2017 and then March 2020 (EO-2011-0128).
In March 2019, the commission granted a motion by Ameren, commission staff, the OPC and the Missouri Industrial Energy Consumers to delay the rate-case filing until March 2023.
Acknowledging Ameren’s contention that “it would be unduly expensive to perform the comprehensive cost-benefit study” necessary to assess the value of its MISO membership, the PSC agreed that the study’s cost “outweighs the importance of the study.”
The growth of renewable energy resources stemming from technological developments and the resulting cost reductions has caused more than a few skirmishes, FERC Commissioner Richard Glick said on Wednesday.
“We’re seeing growth on renewable energy, and we’re seeing conflict as well: friction between the states’ efforts to promote renewable energy … and FERC’s regulation of wholesale electric markets,” Glick said in opening the first day of Renewable Energy Vermont’s annual conference. This year, the group is holding the conference online and over the course of three months.
FERC Commissioner Richard Glick | Renewable Energy Vermont
“I don’t think there’s necessarily a natural competition or divergence there, but we’ve seen for a variety of reasons traditional electric generators, primarily natural gas and coal, fighting it out in regional electricity markets,” particularly in the Eastern RTOs, Glick said.
“States want their decisions to be heard in these regional markets,” Glick said. “From my perspective, FERC’s responsibility is to figure out a way to help these RTOs design their markets and oversee [these] design changes to ensure that state policies are accommodated, not blocked. If we don’t do that, I think we’re headed towards a bad situation in which some states are going to drop out of RTOs, and certainly states aren’t going to do anything further that would give FERC additional authority over resource decision-making.”
REV Chair Josh Bagnato asked what FERC is doing that impacts Vermonters who are pushing for the clean energy transition.
REV Chair Josh Bagnato | Renewable Energy Vermont
“The commission has quite a bit of jurisdiction over the New England electricity market through our oversight of ISO-NE, so almost all wholesale transactions throughout the region are subject to FERC regulation and oversight. So, the decisions we make have a great deal of impact on the resource mix, prices and on reliability,” Glick said.
“I don’t think the people at ISO New England … get up in the morning and say, ‘How can we frustrate or block state programs?’ I don’t think they do that at all, but they are looking at the markets from a different perspective. They want to make sure that the lights stay on and that they provide power at a relatively reasonable price.”
The federal government right now “is relatively AWOL on greenhouse gas emissions, [so] it’s really up to the states at this point to address those issues, and I don’t think the commission blocking state policies, whether it be intentional or inadvertent, is the way to go at this point,” Glick said.
He cited a recent Lazard analysis that said wind and solar are now the most cost-competitive energy technologies, not only in the U.S., but around the world.
“That’s certainly been a pretty dramatic change,” Glick said. Though federal and state policies have helped somewhat, he said, far and away the biggest driver has been consumer demand, and that will certainly continue in the future.
Individual consumers as well as corporate America have concerns about climate change and would like to see a much greener mix in their utilities’ resource portfolio.
FERC Commissioner Richard Glick cited a recent Lazard study that shows that when U.S. government subsidies are included, the cost of onshore wind and utility-scale solar is competitive with the marginal cost of coal, nuclear and combined cycle gas generation. | Lazard
At first it was just Big Tech companies, “but now we’re seeing it all over the place, with Proctor and Gamble, Anheuser-Busch, Walmart — companies that you wouldn’t normally think of in terms of the energy space,” Glick said. “They’re saying, ‘We want to be 100% green and have a 100% net-zero emissions portfolio as quickly as possible.’ And they’re demanding that of utilities, which are going out and substantially changing the resource mix.”
Bagnato asked what three magic buttons Glick would push to help the transition to renewable energy.
“The first is more of an esoteric one, which is follow the science,” Glick said. “The U.S. is the only country in the world having this debate. … Two, massively build out the transmission grid to be able to accommodate offshore wind and … onshore wind and solar. Third, we have to have a federal policy. States have been doing a great job, but whether on carbon pricing or whatever, cooperation on a regional basis doesn’t work without a federal overlay.”
