SPP’s dream of operating an energy market in the Western Interconnection came closer to reality Friday with its Board of Directors’ approval of start-up funding for the Western Energy Imbalance Service (WEIS) market.
The board accepted staff’s recommendation to budget $9.5 million to develop and stand up the market. The Members Committee supported the recommendation, with only Xcel Energy’s Southwestern Public Service abstaining from the vote during a conference call.
Committee members peppered SPP staff with questions about the proposal’s costs to existing members and whether the RTO will maintain a division between Eastern and Western members. Staff assured members there will be no increase to corporate overhead.
Asked how the market will help “East-side members,” Senior Vice President of Operations Bruce Rew said current members would benefit from the “additional use of the SPP system.”
“That will provide additional revenue through corporate overhead costs and reduce the SPP administrative fee accordingly,” Rew said.
Staff said they have been tracking expenses to develop the market proposal and will continue to do so. The RTO said it will add 13 employees to perform the WEIS functions and will begin the hiring process “as soon as practical.”
“We have a 16-month schedule, and there’s a lot of work to be done,” Rew said.
SPP says it will finance the costs during the implementation period by issuing debt. It will then recover the costs from the WEIS participants over eight years, beginning in December 2020, using a formulized rate that includes projected annual production costs, start-up principal and interest charges, and current net energy for load.
Market participants who terminate WEIS services within the first eight years are obligated to pay their portion of the remaining implementation costs. Additional participants who enter the market within that period will be allocated a portion of the original implementation costs.
The WEIS will operate similarly to SPP’s imbalance market, which ran from 2007 to 2014, centrally dispatching energy on a five-minute basis under a Western joint dispatch agreement. Members will operate under a separate tariff and market protocols from SPP’s Eastern Interconnection members. Should a WEIS member decide to join the RTO as a transmission owner, the balance of its implementation costs would be spread out among the market’s remaining participants.
SPP has long explored offering market services in the Western Interconnection and seeking new members. An effort to integrate the Mountain West Transmission Group fell apart last year, but the grid operator’s attempt to provide reliability coordination services to 12% of the region’s load is on schedule to meet a December timeline. (See SPP Western Reliability Briefs: Week of Sept. 16, 2019.)
The WEIS market will become the West’s second, joining CAISO’s Western Energy Imbalance Market.
SPP says the WEIS will go live in February 2021. It already has five market participants in Basin Electric Power Cooperative, Tri-State Generation and Transmission Association, and three Western Area Power Administration entities: Colorado River Storage Project, Rocky Mountain Region and Upper Great Plains. All five organizations signed contracts in September to fund the market’s development. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)
The grid operator said it will accept additional participants through Oct. 25. Market participants who want to join the WEIS after that date will be onboarded through SPP’s normal processes.
Xcel, Colorado’s largest load-serving entity, and three partners — Black Hills Energy, Colorado Springs Utilities and Platte River Power Authority — have announced they are evaluating both the WEIS and the EIM. (See Colorado Utilities Examine Market Membership.)
SPP made the WEIS public in June, distributing a proposal to 19 interested parties in the interconnection.
It expects to file a WEIS Tariff with FERC early next year. Legal staff said they were not aware of any necessary state regulatory filings.
In a major setback for developers of small power projects, FERC on Thursday launched a rulemaking to overhaul its regulations under the Public Utility Regulatory Policies Act, the 1978 federal law enacted to spur competition in the U.S. electricity sector (RM19-15, AD16-16).
Thursday’s Notice of Proposed Rulemaking signals the commission is aiming for top-to-bottom changes to PURPA, including elimination of a fundamental principle of the rules: fixed-price contracts for qualifying facilities (QFs).
In seeking the changes, FERC is responding to longstanding complaints about PURPA by utilities and the state commissions that regulate them. But the commission has also roused the objections of PURPA supporters and its lone Democratic member, Commissioner Richard Glick, who in a partial dissent said the NOPR would “effectively gut” the regulations.
FERC ruled in 2016 that Entergy did not have to purchase power from Occidental Chemical’s Taft plant in Louisiana because the PURPA generator had unconstrained transmission access and could sell its output in the MISO wholesale market. | Occidental Chemical
In a statement accompanying the NOPR, FERC called the effort its “first comprehensive review” of the regulations since they were implemented 39 years ago.
“It’s clearly time for FERC to revisit its PURPA policies,” Chairman Neil Chatterjee said. “Congress told us to review our policies from time to time to ensure that our regulations continue both to protect consumers and to encourage the development of QFs. That is precisely what we are doing here.”
But in his dissent, Glick said the NOPR suggested that FERC “no longer believes that PURPA is necessary” and warned that it is encroaching on Congress’ authority.
“Whether PURPA’s goals remain relevant is a decision for Congress, not an administrative agency. The commission should not be seizing the reins from Congress in order to isolate an important debate about national energy policy within an independent regulatory agency,” Glick said.
Avoiding Avoided Cost
Chatterjee’s words of assurance about QFs notwithstanding, QF developers appear to have much to lose from the outcome of the NOPR. The proposal closely aligns with a set of PURPA recommendations that the National Association of Regulatory Utility Commissioners floated nearly two years ago after complaining about the time and expense of administering PURPA projects. Many commissions have long sought to rein in the volume of PURPA projects, particularly in Western states. (See NARUC Calls for PURPA Reforms, Outlines Proposed Changes.)
Reflecting one of NARUC’s key priorities, the NOPR zeroes in on what is sacred ground for QF developers: PURPA’s requirement that utilities contract with small projects at a fixed “avoided cost” rate — or the incremental cost a utility would have to pay to generate power itself.
QF developers say that requirement is vital to their financial viability, ensuring they receive ample and predictable compensation for their output over a contract period. But utilities and regulators complain that the avoided-cost calculations currently used to set contracts increasingly exceed the steadily declining costs of power available in open markets, unjustly adding to the bills of ratepayers.
Larry Greenfield, of FERC’s Office of General Counsel, answered questions on the commission’s proposed PURPA changes.
While the NOPR wouldn’t erase PURPA’s avoided-cost provision, it would upend the current rules by eliminating the notion of fixed-cost contracts. FERC says it would provide “flexibility to state regulatory authorities so they can accommodate recent wholesale power market developments.” That flexibility would extend to granting states the ability to:
Require that energy rates — but not capacity rates — in QF power sales contracts vary according to changes in the purchasing utility’s avoided costs at the time the energy is delivered.
Allow QFs to retain their rights to fixed energy rates, but to base them on projections of what energy prices will be at the time of delivery during the term of a QF’s contract.
Set energy and capacity rates based on competitive solicitations conducted in a transparent and nondiscriminatory manner.
The NOPR also proposes to allow state regulators to use LMPs to set the “as available” QF energy rates for resources selling into RTOs/ISOs — or to use competitive prices from liquid hubs to set those rates in areas without organized markets.
In his dissent, Glick expressed concern that elimination of fixed-price contracts “will make it more difficult — or in some cases impossible — for QFs to obtain financing. The option to enter a contract with a fixed or known price has played in essential role in encouraging QF development.”
Glick also contended that the contracts “have played an important role in ensuring that QFs receive nondiscriminatory rates, especially in areas of the country with vertically integrated utilities that are guaranteed to recover the costs of their prudently incurred investments through retail rates. Neither the record nor the rationale in this NOPR addresses these concerns in a manner that is even remotely convincing.”
The NOPR takes up yet another NARUC recommendation in proposing to modify PURPA’s “1-mile rule,” which is used to determine whether affiliated QFs located proximate to each other should be considered part of a single larger facility. Regulators in the interior West have complained that large developers have “gamed” the rule by parceling large projects in such a way that they unjustly earn PURPA treatment. (See PURPA Critics Call for Reforms.)
While the commission proposes to maintain the “irrebuttable” presumption that facilities 1 mile apart or less constitute a single facility, it calls for giving states the latitude to determine that facilities located more than 1 mile apart, but less than 10 miles apart, could comprise a single facility. Facilities 10 miles apart or more would still benefit from the irrebuttable presumption that they are separate facilities.
The NOPR additionally proposes to eliminate the “rebuttable” presumption that QFs with a net capacity at or below 20 MW don’t have nondiscriminatory access to certain markets, replacing that threshold with 1 MW. One exception: The threshold for cogeneration facilities would remain at 20 MW.
FERC is also seeking to require states to establish objective and reasonable criteria to determine a QF’s commercial viability and financial commitment to construction before it is entitled to a contract or legally enforceable obligation. It would also allow an entity to protest a QF self-certification or self-recertification without having to file and pay for a declaratory order.
‘Meaningful Evolution’
FERC’s newest member, Commissioner Bernard McNamee, issued his own statement in support of the NOPR.
“The changes the commission is proposing through this Notice of Proposed Rulemaking are designed to protect consumers while also encouraging the development of alternative generation and cogeneration facilities,” McNamee said. “To achieve these ends, the proposed rules will provide state utility regulators more flexibility to rely on market pricing when determining the rates utilities pay to qualifying facilities under PURPA, provide more transparency to interested stakeholders, and extend the benefits of competition to a greater number of consumers.”
Joshua Kirstein, of FERC’s Office of General Counsel, summarized the commission’s PURPA ruling at Thursday’s open meeting.
Support came from other corners of the power sector as well.
“We applaud FERC Chairman Chatterjee for his leadership and for prioritizing PURPA reform,” Edison Electric Institute President Tom Kuhn said. “By initiating this important NOPR, Chairman Chatterjee has reaffirmed that there are concrete steps FERC can take to better protect electricity customers from unnecessary energy costs and drive additional investments in renewable energy, all while meeting the commission’s responsibilities under the act.”
American Public Power Association CEO Sue Kelly said the electricity sector has undergone a “meaningful evolution” in its resource mix since PURPA’s enactment. “We applaud FERC for recognizing the need to ensure that PURPA’s implementation is aligned with today’s energy landscape,” she said.
“Today’s vote was a much-needed first step in the process of modernizing PURPA,” National Rural Electric Cooperative Association CEO Jim Matheson said. “FERC’s rules implementing PURPA today promote the uneven, unplanned and uneconomic development of facilities and provide subsidies that promote these facilities at the expense of our members, system reliability and other more affordable resources.”
The Electricity Consumers Resource Council (ELCON) was more measured in its endorsement of the NOPR, saying that it supports “thoughtful reform” of the 1-mile rule and “improving avoided cost estimates,” while applauding FERC for recognizing that cogeneration facilities are “unique” among QFs. But the group also emphasized that PURPA still plays an “essential” role in encouraging competition.
“The majority of states remain under cost-of-service regulation, where industrial self-supply and competitive power generation face uncompetitive conditions both within and outside of organized wholesale electricity markets,” ELCON CEO Devin Hartman said. “It is imperative that FERC proceed in a manner that enhances competition and reduces barriers to self-supply in regulated states, whereas loosening PURPA implementation would run counter to FERC’s stated intent of protecting consumers and preserving competition.”
Renewable advocates expressed disappointment in Thursday’s development.
“Rather than focusing on PURPA’s goal of ensuring competition, this proposed rule will have the effect of dampening competition and allowing utilities to strengthen their monopoly status,” said Katherine Gensler, vice president of regulatory affairs for the Solar Energy Industries Association. “The proposed rule is a move away from competition, and we hope FERC rethinks the most harmful portions of this proposal. We will continue to push for PURPA reforms that increase competition, transparency and enforcement.”
Comments on the NOPR will be due 60 days after its publication in the Federal Register.
FOLSOM, Calif. — CAISO’s Board of Governors on Wednesday heard that the ISO could face capacity shortages as soon as next year if steps aren’t taken to address the potential shortfall, including keeping aging natural gas plants from retiring as planned.
In a presentation to the board, CAISO Vice President Mark Rothleder said summer peak demand is shifting from late afternoon to early evening. People now are going home and turning on their air conditioning around 7 p.m., just as solar power peters out, he said.
“The issue is not so much at the peak hour,” Rothleder said. “It’s at the near-peak hour as the sun goes down.”
By next summer there could be insufficient capacity to meet the ISO’s system reliability requirements, which include a 15% planning reserve, Rothleder said.
Imports that aren’t already under contract could fill the gap, but tightening supply in the West makes those imports unreliable. California’s neighbors are using more of their own electricity instead of exporting it, he said.
Rothleder said the shortages could start in the hot summer days of 2020 with a 2,300-MW shortfall at 7 p.m., increasing to 4,400 MW in 2021 and 4,700 MW in 2022. The problem could worsen when Pacific Gas and Electric’s Diablo Canyon Power Plant, the state’s last nuclear generating station, shuts down in phases starting in 2024, he said.
California is on an ambitious push to use carbon-free energy, but to avoid a crisis it may be necessary to prevent older natural gas peak plants from shutting down, Rothleder told the board.
“We’ve got the last tranche of once-through cooling scheduled for retirement” near the end of 2020, Rothleder said. Those plants can generate about 4,000 MW, he said.
Once-through-cooling (OTC) plants are being phased out because they use water from oceans and estuaries, killing billions of marine organisms including fish larvae and shellfish, according to the California Energy Commission.
“We need to get on the track of procurement” to generate more energy, Rothleder said.
CAISO said there could be a resource shortage in the next two years. | CAISO
Increasing wind and geothermal energy production, and adding more short- and long-term storage, would provide energy after sundown without greenhouse gases, he said.
In public comments Wednesday, speakers encouraged the board to move quickly to address the resource adequacy problem.
“We urge the ISO to continue to work on this expeditiously. Soon. Now. Not later,” said Eric Eisenman, PG&E’s director of FERC and ISO relations.
Board Chair David Olsen responded, “This is obviously our top priority. Front and center for us.”
Edward Randolph, director of the California Public Utilities Commission’s Energy Division, told the board that the commission also is acting on the threat.
“We do take what is being raised here today pretty seriously,” Randolph said.
On Sept. 12, a CPUC administrative law judge issued a proposed decision requiring load-serving entities in Southern California Edison’s service area to procure 2,500 MW of additional resources between August 2021 and August 2023. ALJ Julie Fitch also recommended keeping the OTC plants operating, a decision that’s ultimately up to the state Water Resources Control Board.
“Procurement shall be conducted on an all-source basis, including both existing and new resources, and may include LSE-owned resources when justified,” Fitch wrote.
“The commission should act now to forestall a potential system reliability emergency by 2021 and require ‘least regrets’ actions with respect to OTC deadlines and LSE procurement,” she said.
The CPUC could vote to adopt the decision as early as Oct. 24, it said.
MINNEAPOLIS — NERC’s Stakeholder Engagement Team (SET) has agreed to expand the membership of the new committee that would replace the Planning, Operating and Critical Infrastructure Protection committees, stakeholders were told last week.
SET member Lloyd Linke, of the Western Area Power Administration, told a joint meeting of the OC and PC that the new Reliability and Security Council (RSC) will have 34 voting members: two each from Sectors 1-10 and 12, for a total of 22; 10 at-large members, a chair and a vice chair. The committee will also have five nonvoting members, including a NERC staffer as secretary, along with two U.S. federal representatives, and two Canadian representatives: one federal and one from the provinces.
If a sector does not have two members, the vacant slot will be filled by an additional at-large member to keep the total at 34 members.
The RSC will be only about a quarter of the size of the three technical committees it will replace, which have almost 120 voting members. But the SET’s original plan called for only one member from each sector, a proposal that met opposition. (See NERC Board Hears Debate over Committee Reorg.)
Linke also said the RSC meetings will be open to other stakeholders.
He said the move was driven by a desire for a “better functional alignment” between the technical comms and the Reliability Issues Steering Committee (RISC). Reducing travel and hotel costs “wasn’t a primary driver,” he said. “It wasn’t a big driver at all.”
The RSC members will have three- and two-year terms initially, then revert to staggered two-year terms. Once the committee is set up, the RSC nominating process will follow the model of the Compliance and Certification Committee.
Linke said one of the initial tasks of the RSC will be determining how to continue the “lessons learned” sharing and awareness functions used by the technical committees.
“We don’t want to lose that engagement,” said John Moura, NERC director of reliability assessment and technical committees. Concerns about the potential loss of functions “hit [NERC] staff strongly,” he said.
The SET rejected suggestions that the technical committees evaluate their subcommittees to determine their future. “There was a desire not to tie the hands of the new RSC,” Linke said.
The schedule calls for the RSC to hold its first meeting in March along with the three technical committees, which would end their operations effective June 1.
Some members expressed opposition to the proposed committee merger after the OC and PC split for their separate meetings.
“I don’t think the new structure is going to have the amount of expertise or dedicate as much time as [the technical committees] do,” Peter Brandien, vice president of systems operations for ISO-NE, said at the PC meeting.
“I think the most important aspect of this plan is the change of this legislative structure from one that is wholly elected to one that is partly elected and partly appointed. The world’s currently best-known example of that kind of legislature is Hong Kong,” said Robert Blohm, managing director of Keen Resources. “That’s my comment.”
SPP’s efforts to extend reliability coordination services to about 12% of the Western Interconnection’s load remains on a glide path, staff said this week during a pair of meetings with Western entities at Black Hills Energy’s offices in Rapid City, S.D.
The RTO is preparing for the start of shadow operations and a second certification visit by regulatory representatives in October. It plans to go live with RC services in the West on Dec. 3.
C.J. Brown, SPP’s director of system operations, told the Western Reliability Executive Committee on Wednesday that the grid operator is focused on closing issues identified by a Western Electricity Coordinating Council-led certification team’s August site visit. (See Certification Team Checks SPP’s Western RC Function.)
“Everything is on track,” he said.
The team did not find any “showstoppers,” Brown said, but left behind several issues it felt SPP needs to resolve before going live. Staff expect to close those issues by October and are on track to close about 40% of “recommended” issues before the certification team’s return visit on Oct. 9.
By then, SPP will have begun two months of shadow operations with Peak Reliability, WECC’s incumbent RC. Peak said in August 2018 it would wind down operations by the end of this year. SPP, CAISO RC Wins Most of the West.)
Shadow ops begin on Oct. 7, but SPP operators will begin staffing the RC desk on Sept. 25. A shadow ops model is expected to be in production on Oct. 1.
Brown said SPP staff have received a separate request from WECC, FERC and NERC staff to visit the RTO’s Arkansas headquarters in early November. The agencies conducted a similar visit to CAISO’s RC West.
“If it’s a good idea for California, it’s a good idea for SPP too,” Brown said.
| SPP
Tri-State Generation and Transmission’s Keith Carman, chair of the WREC, offered words of praise for Peak employees, who have been working closely with staff from the incoming RCs.
“These employees have been nothing but professional, responsive, kind and receptive,” Carman said. “It’s way unexpected too, considering the predicament they’re in.”
RCs have been compared to top cops for transmission reliability across wide geographic areas. They are responsible for ensuring each member focuses on reliability, particularly across the seams from one area of responsibility to the next.
Brown also briefed the NERC Operating Committee on the RC transition last week, telling members said SPP “will be more proactive” in November before going live at noon MT on Dec. 3.
SPP’s Yasser Bahbaz told the Western Reliability Working Group it has received more than 10,000 inter-control center communications protocol (ICCP) data points from CAISO as it works to stand up its western RC model. Staff is currently validating about 4,000 of those points, which changed from Peak’s model to CAISO’s.
“Someone made a change from an old name to a new name,” Bahbaz said. “We’re having to go one-by-one to reconcile.”
Brown said the CAISO model will become SPP’s primary model, with an earlier Peak model becoming secondary.
SPP has also downloaded Peak’s outage data into its systems and was to spend this week validating software applications with Peak’s balancing authorities. The RTO has already completed ICCP connectivity with its 13 RC customers.
SPP has ‘Good Handle’ on Reserve Sharing Groups
SPP is not concerned with “special circumstances” surrounding reserve sharing groups (RSGs) in the West, Brown told the WRWG. RSGs consist of two or more BAs that collectively maintain, allocate and supply operating reserves for use in recovering from contingencies within the group.
The Northwest Power Pool’s RSG has reserve requirements for the Western Area Power Administration’s Colorado and Missouri (WACM) region’s BA, while other WACM entities are part of the Southwest Reserve Sharing Group.
“I believe we have a good handle on the RSGs,” Brown said. “It’s pretty basic. We run one.”
SPP is working to receive contingency reserve data from the NWPP and Bonneville Power Authority RSGs. It plans to soon request the contingency reserve data for each BA within its RC footprint.
“We want to ensure every resource is covered by an RSG or a reserves requirement,” Brown said. “We just want to know how it’s done in the West. We want to understand the situation, so we have [it] accurately modeled.”
Brown said SPP would only issue energy emergency alerts in the West for reliability concerns. BAs will be responsible for meeting NERC’s BAL-002 requirements.
“We don’t expect anyone to shed load for a compliance violation,” he said.
WREC Approves Doc Modification Process
The WREC unanimously approved a modification oversight process (MOP) to manage document modifications related to the RTO’s Western RC services. The WRWG had been working to finalize the document since May.
The MOP applies to documentation established by SPP or SPP working groups that might affect operations or have a compliance or financial impact on its Western RC services customers. (See “SPP’s MOP ‘Cleans Up Stuff,’” SPP Western Reliability Briefs: Week of May 13, 2019.)
The NERC Standards Committee on Wednesday delayed the posting of a standard authorization request (SAR) by SPP on generator weatherization because of a competing proposal from the Edison Electric Institute.
SPP proposed the SAR in response to the joint FERC and NERC staff report on the Jan. 17, 2018, cold weather event in the South Central U.S., which caused MISO and SPP to seek voluntary load reductions and nearly forced load shedding in MISO South.
The committee balked at posting SPP’s SAR for comment after Soo Jin Kim, manager of standards development, announced that NERC had received a competing SAR from EEI the previous day — too late for it to be considered on the agenda.
SPP’s SAR proposed development of a standard “to include such activities as winterization activities on generating units, winter-specific and plant-specific operator awareness training, and processes to ensure [balancing authority] and [reliability coordinator] awareness and accounting of unit limitations in performing operational planning analysis, and determining contingency reserves.”
Charles Yeung, SPP executive director of interregional affairs, amended the SAR to eliminate a reference to “fuel assurance” among its deliverables. “I’m trying to anticipate the alternate SAR because there was a concern about fuel assurance,” he said.
Several committee members said that the competing SARs should be posted simultaneously. “I think if they’re not posted concurrently … it will be extremely confusing,” said Jennifer Flandermeyer, director of federal regulatory policy for Kansas City Power & Light.
Howard Gugel, NERC director of engineering and standards, suggested the committee delay posting SPP’s SAR until the SC’s Executive Committee reviews the EEI proposal and then post them together.
After a lengthy debate, the committee voted 10-7 not to post the SPP proposal. It then approved on a voice vote a motion to remand the initial SAR back to SPP and direct the RTO to work with EEI to reconcile the differences between the two proposals. The EEI proposal was not publicly available as of Thursday, and an EEI spokesman did not respond to a request for comment.
The FERC/NERC report, released in July, said the need for a new reliability standard to improve generators’ winter performance was demonstrated by the 2018 incident as well as the large-scale unplanned outages during the 2014 polar vortex and the 2011 Southwest cold weather event.
The report found 183 generating units in the RC footprints of SPP, MISO, Tennessee Valley Authority and Southern Co. suffered an outage, derate or failure to start between Monday, Jan. 15, and Thursday, Jan. 19.
It said generator owners and operators should be required to winterize their units and provide their RCs and BAs with information about their preparations.
At the NERC Operating Committee meeting in Minneapolis last week, however, some stakeholders questioned regulators’ authority to issue such requirements, citing arguments that helped sink such an initiative in 2013. (See Déjà vu for Winterization Standard?)
Several said it would be improper to penalize generators if they suffered forced outages during severe weather.
“If you have power plants that haven’t run in weeks and you wait until the coldest day of the year to start them, you should anticipate a couple may have problems starting up,” said Allen Schriver, general manager of compliance for NextEra Energy Resources and COO of the North America Generator Forum.
“Whatever this SAR ends up being can’t mess up incentives already out there in the markets,” said Dan Woodfin, ERCOT’s senior director of system operations.
James Merlo, NERC director of reliability risk management, promised that a standard would not be punitive or require specific weatherization requirements.
“Some people have an expectation that we would say, ‘Winterize your generator. Use heat tracers.’ We don’t have standards like that,” he said.
“The expectations would be that you at least have a [winter operating] plan, and you’re going to operate to that plan. If you say you have firm fuel, then the expectation is that is what you purchased. … There were generators that said, ‘This is what I can operate at.’ Some of them were as low as -10 degrees Fahrenheit. We didn’t get … anywhere near that,” yet the units suffered outages, he said.
“Sometimes a standard is [about] getting everybody up to the same level of expectation,” he continued. “And when you have units telling us. … ‘We don’t have a cold weather preparedness plan. We don’t know what our temperature operating characteristics are; that’s troubling. It’s really beyond troubling. … Everybody sitting here is [saying] well, ‘That’s not my company.’ Well, it was someone’s company. It was several companies that gave these replies.”
John Stephens, director of power system control for City Utilities of Springfield, Mo., said he was troubled by recommendation 11 in the report, which said that when MISO relies on 3,000 MW of regional directional transfer (RDT) flows in determining reserve levels for MISO South, “it should remain mindful that … ‘any amount above 1,000 MW of the 3,000 MW north-to-south limit … [is] only available on a non-firm, as-available basis.’”
“If either party is depending on non-firm service to maintain reliability, you’ve already failed,” Stephens said.
“Non-firm is exactly what it says. If you and I go out on a boat and I [say] you can borrow my life preservers as long as I don’t need it, that’s non-firm,” he said, prompting laughter.
In response to a question from Stephens, David Zwergel, MISO’s senior director of regional operations, initially said the RTO did rely on the non-firm portion of the RDT for deliverability of its reserves.
After a break in the meeting, however, Zwergel said he needed to make a correction. “I checked back with our experts, and with the changes we’ve made, we do not rely on that non-firm capability for deliverability of reserves,” he said.
WASHINGTON — FERC has shifted several employees out of its Office of Enforcement, eliminating the office’s Division of Energy Market Oversight (DEMO), Chairman Neil Chatterjee announced Thursday during the commission’s open meeting.
DEMO staff responsible for reports examining broad market trends, such as the commission’s annual State of the Markets, were transferred to the Office of Energy Policy and Innovation (OEPI), according to FERC. Those responsible for data management support functions in Enforcement’s Division of Analytics and Surveillance (DAS) were transferred to the newly created Data Governance Division within the Office of the Executive Director (OED).
The remaining DEMO staff were shifted to other divisions within Enforcement. Employees monitoring and conducting analysis of market power using electric quarterly report (EQR) data and other market data moved to DAS. Staff administering and performing compliance functions related to EQR and financial forms moved to the Division of Audits and Accounting.
“This reorganization will allow the Office of Enforcement to be more focused on its core mission: continuing oversight of market activities, investigations and audits,” Enforcement Director Larry Parkinson said in a statement. “Assessing broader market trends fits squarely in OEPI’s mission.”
Of Enforcement staff, 9% moved to OEPI and 2% moved to OED, according to FERC. Compliance and market surveillance functions will remain in Enforcement. The office employs 163 full-time equivalents post-reorganization, according to spokeswoman Mary O’Driscoll.
Organizational chart for FERC’s Office of Enforcement as of Sept. 13, before the elimination of the Division of Energy Market Oversight | FERC
“The reorganization in no way impacts resources needed to address market oversight and compliance activities executed by the Office of Enforcement,” FERC said in a statement. Enforcement “maintains sufficient resources to execute comprehensive oversight and compliance activities on behalf of the commission.”
“This reorganization makes a lot of sense, and it will create efficiencies and more effectively align staff resources and functions,” Chatterjee said at the meeting. Enforcement “will maintain all of the resources it needs to comprehensively address market oversight and compliance.”
Noting that he has been critical of the commission for not being aggressive in its enforcement duties, Commissioner Richard Glick rebutted suggestions that the shuffle would “defang” Enforcement. “It seems to me like a simple matter of administrative efficiency, trying to move things around a little bit and make them function a little bit better,” Glick said. “If I thought there was something nefarious going on, I think the chairman knows and Commissioner [Bernard] McNamee knows that I wouldn’t be shy to talk about it.”
The San Diego City Council approved a plan Tuesday to create California’s second largest community-choice aggregator and the first providing electricity to all the customers of a major city.
“Today represents a monumental opportunity,” San Diego Mayor Kevin Faulconer told the councilmembers as he introduced a plan that’s been working its way through city government for the past year.
“Community choice is really the culmination of our climate efforts,” he said. “We will have full control about where we purchase power from. It will be clean energy.”
The joint powers agreement and ordinance, approved by a 7-2 vote, require the CCA to obtain all its energy from carbon-free sources by 2035, ahead of the state’s 2045 clean-energy timeline established in last year’s Senate Bill 100.
San Diego Gas & Electric, a subsidiary of Sempra Energy, has been the city’s monopoly electricity provider for decades, but Sempra has expressed interested in getting out of the retail electricity business and becoming a wires-only company.
“SDG&E is here to support the city of San Diego,” Vanessa Mapula Garcia, public affairs manager at SDG&E, told councilmembers. “We support our customers’ right to choose an energy service provider.”
The company will continue providing transmission and distribution services to the city, as it has done for more than a century.
The new entity, tentatively called the San Diego Regional Community Choice Authority, will likely include a dozen other communities in the San Diego region. The cities of Encinitas and Chula Vista, with a combined population of more than 300,000, have already voted to join, and others are expected to follow suit. San Diego, the state’s second largest city, has a population of 1.4 million; San Diego County totals 3.3 million.
California currently has 19 CCAs, and other areas around the state are considering forming CCAs to purchase and provide power, displacing investor-owned utilities in that role. The state’s largest CCA, the Clean Power Alliance in the Los Angeles area, has about 1 million customer accounts and 3 million customers.
The state’s first CCA was Marin Clean Energy, formed in 2010, following the passage of a state law in 2002 allowing CCAs.
State officials have expressed concern about the rapid spread of CCAs and their potential effects on reliability and resource adequacy in the areas they serve. On Aug. 30, however, a group of California stakeholders filed a plan with the California Public Utilities Commission that would replace the state’s current resource adequacy framework with a “central buyer” responsible for procuring resources for multiple years.
The central buyer proposal is the product of a settlement agreement that includes SDG&E, Calpine, the Independent Energy Producers Association, Middle River Power, NRG Energy, Shell Energy North America, Western Power Trading Forum and CalCCA, which advocates on behalf of the state’s growing number of community choice aggregators. (See Calif. Participants Float ‘Central Buyer’ RA Plan.)
PROVIDENCE, R.I. — New England renewable energy advocates are skeptical of federal officials’ claims to be acting in the public interest by delaying the final permits for the Vineyard Wind project in Massachusetts, raising the question of whether the Trump administration is slow-walking offshore wind approvals.
Early this summer, the project’s biggest obstacle appeared to be local, after the Edgartown Conservation Commission denied a permit for the project’s cables to come ashore on Martha’s Vineyard. (See “Land Ho is Wind Woe,” New England Officials Speak on Grid Transformation.)
But challenges rose to the federal level last month when the Bureau of Ocean Management announced it would postpone a final environmental impact statement and extend the project’s permitting timeline to conduct an expanded analysis of “cumulative impacts” from the multiple offshore projects proposed for New England.
Participants at a Sept. 10 Environmental Business Council of New England (EBCNE) meeting on Vineyard Wind questioned the federal government’s rationale for the delay.
“For years, we asked for cumulative impacts in things like port development, LNG facility development, energy development in general; and FERC said, ‘No, we never do that; we never ask how many ports do we really need. … One port rises and falls on its own merits,’” said the Institute at Brown for Environment and Society’s Curt Spalding, a former EPA regional administrator for New England during the Obama administration.
Spalding said the federal review under the National Environmental Policy Act “is not simply a written, hard and fast scientific process. The key decisions are made along the way by regulators that obviously look at all the data that NEPA generates. But let’s be honest: It’s a very politicized process in a lot of cases.”
As evidence of an overall strategy to delay development of renewable energy, and in particular offshore wind, Spalding pointed to apparent short-staffing at the National Oceanic and Atmospheric Administration, which he said “has not been given any resources to do all the reviews that we’re talking about. It’s a joke; it’s absurd. They’re being asked to review I don’t know how many projects, but they’re given no resources.”
Every Hour Matters
A joint venture between Avangrid Renewables and Copenhagen Infrastructure Partners, Vineyard Wind in May 2018 won a contract to supply Massachusetts with 800 MW of offshore wind energy. Later that year it won another lease area off Martha’s Vineyard in an auction conducted by BOEM. The company last month bid for the state’s second solicitation by offering several options on up to 800 MW in additional offshore wind energy.
Rachel Pachter, vice president of permitting affairs at Vineyard Wind, described the path to construction of the large project, which could ultimately generate as much as 3,200 MW. Asked about the BOEM delay, Pachter said, “The issue as we understand it is not specifically at all about Vineyard Wind. … This is about the other projects and their development, and them wanting to do a more comprehensive cumulative impacts analysis of all of those in order to better understand where the industry’s headed.”
“So they are not coming back to you asking for more information?” EBCNE President Daniel Moon asked.
“They’re coming back and asking for money, since we pay for a third-party contractor, but it’s really about future projects,” Pachter said. “They actually have all the information they need on Vineyard Wind.
“An important way to think about offshore wind farms, the way we think about them, is they’re really, really big logistics projects,” she said. “What matters most to us is how we can build this most efficiently, spend the least amount of time offshore and get everything done before the [winter] weather.
“Our windows to work are extremely critical. You can lose an entire year, and when we have vessels with half-a-million to million-dollar [per] day rates, these are all extremely critical to construction of the project. Every hour matters to us. And on the opposite side, making space for the right whale, to make sure that’s protected.”
Andrew Gottlieb, executive director of the Association to Preserve Cape Cod, said that “moving the goalposts of the regulatory process is nothing more than a cynical attempt by the administration to delay offshore wind development in general.”
“The senior levels of the federal government are really being captured by oil-and-gas-industry interests who see the potential for large-scale wind being a threat to wringing out the last nickel of what would otherwise be known as stranded assets,” Gottlieb said.
Responding to the claims of critics, BOEM spokesperson Tracey Moriarty told RTO Insider: “Because BOEM has determined that a greater build out of offshore wind capacity is reasonably foreseeable — more than what was analyzed in the initial draft [environmental impact statement] — BOEM has decided to supplement the draft EIS and solicit comments on its revised cumulative impacts analysis.”
NOAA backed BOEM’s view, asserting that the agency “is committed to ensuring fishing activities and offshore renewable energy interests can operate in harmony,” according to agency spokesperson John Ewald. “We appreciate BOEM’s desire to strengthen their analysis and more fully address the cumulative impacts of offshore wind activities through development of a supplemental environmental impact statement.”
NOAA did not address the contention that it has inadequate resources to expedite project reviews.
The EBCNE meeting also featured a panel that provided a flavor of the logistical complexity of building a wind farm.
“Throughout this multiyear review period, there has been a considerable amount of attention focused on Vineyard Wind because they are the first project, the project that’s farthest through permitting,” said panel moderator Maria Hartnett, of consulting firm Epsilon Associates, which has been working on Vineyard Wind for two years.
Priscilla Brooks, vice president and director of ocean conservation at Conservation Law Foundation, said, “Our approach to offshore wind has been one of wanting to see this industry advance, with a focus on siting projects … how to site them in an environmentally sensitive way and also ensure that they get a fair environmental review.”
Jill Rowe, director of ocean science at consultancy RPS Group, which has been working with the project since 2017, said the company has done “many of their [construction and operations plan] sections, have provided permitting support … but there’s a lot of science.” She said RPS has brought its experience from the oil and gas industries to the offshore world.
PJM says it won’t take sides in a debate between transmission owners and load interests over the TOs’ proposal for removing substations and other “critical” assets from NERC’s CIP-014-2 list.
NERC’s critical infrastructure protection standard CIP-014-2 requires TOs to identify and protect transmission stations and substations whose loss or sabotage could result in widespread instability, uncontrolled separation or cascading outages. The TOs last month proposed Tariff Attachment M-4, which outlines a process for vetting transmission projects to remove the assets from the list.
Some stakeholders contend PJM rules require that addressing the CIP-014-2 assets must involve an open and transparent discussion with stakeholders. But doing so, the TOs contend, could reveal the highly secretive location of these facilities.
The RTO said it will stay on the sidelines of the transparency debate and encouraged stakeholders to work out the Tariff language among themselves.
“PJM is prepared to assume the role of an independent, third party to assess whether a transmission project will effectively address the critical infrastructure and associated operations and reliability risks giving rise to the CIP-014 designation in the first place,” PJM spokesperson Susan Buehler said in an email to RTO Insider. “By so doing, PJM can ensure that projects meet the shared objective to reduce critical facilities outright. Because this is a PJM transmission owner proposal, we encourage dialogue between the transmission owners and other stakeholders.”
Consumer Advocates of the PJM States questioned why the draft attachment wasn’t scheduled for discussion at the August meeting of the Markets and Reliability Committee or the Planning Committee. (See PJM TO Tariff Filing Stirs up Transparency Concerns.)
Last week, the D.C. Office of the People’s Council presented a problem statement and issue charge that would require all sectors come together to manage future CIP-014 projects. (See “Consumer Advocates: CIP-014 Projects Need More Transparency,” PJM PC/TEAC Briefs: Sept. 12, 2019.)
American Municipal Power took the debate a step further on Tuesday when the company publicized its “profound” concerns about the TOs’ proposal in a letter to PJM’s planning department and Board of Managers. Of particular concern, AMP said, was the TOs’ attempt to classify CIP-014-2 projects as supplemental, which it said could hide large-scale upgrades with regional and interregional impacts behind a veil of secrecy.
“Given the importance of these substations to regional and possibly interregional operations, there can be little question that the planning of those substations would be conducted through the PJM-administered Regional Transmission Planning Process,” AMP CEO Marc Gerken wrote.
PJM said NERC assigned TOs the role of managing physical security for CIP-014-2 facilities. Ken Seiler, vice president of planning, told the Planning Committee last week that staff support the idea of reducing or eliminating the number of CIP-014-2 assets in the RTO’s territory, but he would not comment on the transparency concerns raised by the consumer advocates. There are less than 20 “critical” assets within the footprint.
“The elephant is in the room, so it’s not like we are ignoring it,” he said. “PJM conceptually supports the idea of electrically making critical facilities noncritical. We think that’s the best thing for this system.”
Pulin Shah, director of transmission strategy and contracts for Exelon, said TOs “will follow the process laid out in the Consolidated Transmission Owners Agreement and the Tariff” when collecting and responding to stakeholders’ comments on Attachment M-4. Exelon has led the PC and MRC discussions on the attachment thus far, though it was just one of several members of the Transmission Owners Agreement-Administrative Committee that helped develop the proposal, Shah said.
“We have extended the comment period to ensure we allow ample time for stakeholders to provide their comments and questions, as the transmission owners determine next steps,” he said. “We will review and respond accordingly to relevant comments and questions through this process, as opposed to having one-off discussions that could lead to confusing the issue.”
