NEPOOL’s Reliability Committee failed to endorse cost overruns on Eversource Energy’s Greater Boston Transmission Project during the committee’s monthly meeting Oct. 20.
The proposal won 60% support, below the 66.7% needed for a recommendation to the PC.
The project’s cost increased by $191 million (33%), primarily because of the underground Wakefield-Woburn, Mystic-Woburn and Sudbury-Hudson lines. Those three lines will cost an additional $147 million, which brings their total to $352 million.
The need to underground the 115-kV Sudbury-Hudson, initially proposed as an overhead line, accounts for an increase to $91 million, which is more than double the original cost of $45.3 million. Eversource was unable to secure property leasing rights from the Massachusetts Bay Transportation Authority (MBTA) for an overhead line. The project has an in-service date of December 2023.
Eversource performed an updated alternative analysis and found that a new 9-mile, 115-kV underground transmission line within an MBTA right of way was the “most cost-effective and constructible alternative.” The two alternatives analyzed — a new 10.3-mile, 115-kV underground transmission line entirely in roadways ($110.4 million), or multiple upgrades to convert a 14.5-mile, 69-kV line to 115 kV, reconductor 11.6 miles of other 115-kV lines and upgrade seven substations ($116.1 million) — had higher costs.
Hydro‑Québec transmission substation
The Wakefield-Woburn and Mystic-Woburn lines increased to a combined $260.6 million from $160.2 million, representing more than half of the total cost increase. Eversource said additional restrictions on the design and construction required a realignment of underground work within roadways to avoid interference with existing utilities. Restrictions on work hours and the number of crews also increased the construction bids, the company said.
The remaining 30 parts of the project saw an additional 12% increase in cost to $411 million from $367 million. However, these transmission cost allocations were previously supported by the RC and approved by ISO-NE.
RC Supports Proposed Revision to ISO-NE/NYISO Coordination Agreement
The RC voted in support of the RTO’s proposed revisions to its Coordination Agreement (CA) with NYISO to eliminate the need to make a FERC filing when the grid operators update their description of shared interconnection facilities.
The grid operators share interconnections at NY/NE Northern AC Interconnection (comprising the PV-20, K7, K6, E205W, 393, 690/FV and 398 interties), the Northport-Norwalk Harbor Cable and the Cross-Sound Cable Interconnection (CSC).
ISO-NE and NYISO will update the detailed list of interconnection facilities on their respective websites rather than maintaining it in Schedule A of the CA, which requires a FERC filing any time changes are made to it. The addition or removal of an interconnection would still go through the grid operators’ respective stakeholder processes and filed with FERC.
ISO-NE and NYISO have agreed to add the “+/-” notation to the CSC Intertie, which is in the list of interconnections within the list of interconnection facilities that will be posted on both websites. ISO-NE will use “its best efforts” to notify the RC within one week following the posting of any revision to the listing of interconnections. If an RC member identifies and reports a perceived error, the RTO will contact NYISO and discuss the concern. The posting will be modified if they agree a change is warranted. ISO-NE will notify the RC member and explain why the change is not justified as well. Entities can also subscribe to the ISO-NE webpage to receive immediate notices of the revision of posted documents.
The Participants Committee will vote on the CA revisions at its Nov. 5 meeting. ISO-NE and NYISO expect to file the revised CA by the end of the year with an effective date in early 2021.
ICR and Related Values for ARAs Recommended by Vote
The RC voted to recommend that the PC support ISO-NE’s proposed installed capacity requirement (ICR) and related values for Forward Capacity Auction 12’s three annual reconfiguration auctions (ARAs) to be conducted in 2021.
The committee approved net ICRs of 32,925 MW for 2021/22 (ARA 3), 32,765 MW for 2022/23 (ARA 2) and 32,980 MW for 2023/24 (ARA 1). The committee also approved a 958-MW value for the Hydro-Québec interconnection capability credit for ARA 3, with the amount rising to 969 MW for ARA 2 and down to 941 MW for ARA 1.
The PC will vote on the ICR and related values on Nov. 5, with a FERC filing expected by Nov. 30.
ERCOT staff have begun issuing price corrections and resettling 25 operating days affected by two market errors earlier this year.
The Board of Directors approved the price corrections earlier this month, as the errors were not caught in time by staff to resettle the operating days on their own. Staff are working with stakeholders to better define “significance,” the only threshold required to take pricing errors to the board. (See “Board Approves 2 Sets of Price Corrections,” ERCOT Board of Directors Briefs: Oct. 13, 2020.)
Staff began issuing market notices with the final resettlements last week, two days at a time. The grid operator released tables with the resettled amounts for the June 8-9, June 10-11, June 12 and 15 and June 16-17 day-ahead operating days.
Dave Maggio, ERCOT | ERCOT
In an email to RTO Insider, Dave Maggio, ERCOT’s director of market design and analytics, said the resettlement tables are intended to provide a “market-wide net change in dollars broken out by different components of settlement.”
As an example, he said, the June 10 price correction addresses the effect on market participants that had day-ahead energy sales for that day. A net amount of approximately $5,000 will be redistributed to those participants.
“It’s worth noting that the same market participant is likely to be involved in multiple components of settlement,” Maggio said. “For example, an individual market participant may be receiving additional dollars for day-ahead energy sales and may owe additional dollars for day-ahead real-time obligations that were purchased.
“When it comes down to it, the resettlement is really just a shuffling of dollars around between market participants,” Maggio said.
RTC Group’s Protocol Work Completed
Staff said a stakeholder group working on revision requests needed to implement real-time co-optimization (RTC) has completed its review process by reaching consensus on all proposed protocol changes.
The revision requests will be finalized and posted with urgent status before going before several stakeholder groups, culminating in the Technical Advisory Committee and Board of Directors meetings in November and December, respectively. The TAC and the board will be asked to endorse and approve 11 change requests.
The Real-Time Co-optimization Task Force has met 33 times since April 2019, first developing key principles and then protocols. The Texas Public Utility Commission in 2019 directed ERCOT to add RTC, a market tool that procures energy and ancillary services every five minutes to find the most cost-effective solution for both requirements. The grid operator plans to go live with the tool in 2024. (See ERCOT Stakeholders Dig into Real-Time Co-optimization.)
ERCOT OKs Petra Nova’s Mothballing
ERCOT has approved the mothballing of NRG’s Petra Nova plant, part of the world’s largest carbon-capture facility. | NRG Energy
ERCOT said on Oct. 20 that a reliability analysis has determined NRG Energy’s Petra Nova Power Unit 1 is not needed to support the transmission system and can be mothballed as requested.
NRG last month sent the grid operator a notification of suspension of operations (NSO) that indicated it intended to place the resource in seasonal mothballs, effective Dec. 20. The unit will be available to the market June 1 to Sept. 30. (See NRG to Mothball Petra Nova CCS Plant.)
Petra Nova has a summer capacity of 71 MW. It was retrofitted at a cost of $1 billion to capture carbon from one of NRG’s nearby W.A. Parish Generating Station coal-fired units. Industry analysts don’t expect the plant to return to operation until oil prices stay consistently above $50 or $60/barrel.
ERCOT’s protocols require it to perform the reliability analysis before approving an NSO.
Voting is underway through 8 p.m. Nov. 4 to fill nine spots on NERC’s Standards Committee that are slated to open at the end of the year, following a nomination period that closed Oct. 15. (See NERC Seeks Nominations for SC Vacancies.)
Committee members — apart from the chair and vice chair — are elected from each of 10 industry segments to serve two-year terms. Each segment nominates two representatives, with terms staggered so that half of the membership is replaced each year.
NERC received only one nomination for the following segments, so they will run unopposed. Appendix 3B of NERC’s Rules of Procedure (ROP) requires each nominee to receive at least one vote before taking their seat:
Segment 1, Transmission Owners: Troy Brumfield, American Transmission Co.;
Segment 3, Load-serving Entities: Linn Oelker, LG&E and KU;
Segment 4, Transmission-dependent Utilities: Barry Lawson, National Rural Electric Cooperative Association;
Segment 5, Electric Generators: James Howell, Southern Co.;
Segment 7, Large Electricity End Users: Venona Greaff, Occidental Chemical;
Segment 8, Small Electricity End Users: Philip Winston, unaffiliated (formerly with Southern Co.); and
Segment 9, Federal, State and Provincial Regulatory or Other Government Entities: Kimberly Jones, North Carolina Utilities Commission.
Four of the nominees — Yeung, Oelker, Lawson and Greaff — are already serving on the committee. Of the remaining new members, Brumfield would replace Dominion Energy’s Sean Bodkin; Howell would replace William Winters of Consolidated Edison; and Winston would take over from independent member David Kiguel. The Segment 9 seat is currently vacant.
The Segment 7 seat will be vacant through December 2021. NERC sought an additional nomination to fill this position, but because only Greaff was nominated, the position will remain open for another year. Segment 6 (Electricity Brokers, Aggregators and Marketers) will see a competitive election, with current member Rebecca Moore Darrah of ACES Power challenged by Justin Welty, senior manager of NERC reliability standards at NextEra Energy.
Members of each segment will be sent emails with a link to vote for their respective election. Each registered ballot body in an industry segment may cast one vote per position being filled. Proxies are allowed, but members must designate their proxies via email to NERC prior to voting.
Canadian Nominees Still Lacking
Segment 10 (Regional Reliability Organizations and Regional Entities) will use an “alternate election procedure” as allowed in the ROP to choose its nominee, according to an announcement. No details about the procedure were provided; NERC’s only requirements for such actions are that the process be ratified by at least two-thirds of the registered entities in the segment in which it will be applied and that it be approved by NERC’s Board of Trustees.
The status of Canadian representation on the committee is also not clear at this time. Currently, only two representatives from Canada serve on the committee: the independent David Kiguel and Robert Blohm of Keen Resources. While Blohm will remain on the committee through December 2021, Kiguel is planning to step down at the end of the year.
This means that Blohm is set to be the country’s sole representative on the committee in 2021, which is not permitted because of a requirement that the committee have at least two Canadian members. Under the ROP, if the regular election does not result in enough Canadian representation, the Canadian candidate who receives “the next highest percentage of votes within their respective segment(s)” will be named as an additional member to serve until the following year’s election.
It is not clear what happens if none of the segments nominates a suitable candidate. However, with Segment 10 the only division yet to submit a nominee and none of the other candidates qualifying, the committee may have to consider more options soon.
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.)
