The ERCOT Technical Advisory Committee canceled its Oct. 24 meeting, citing a lack of items to be considered this month. It’s the fourth TAC meeting to be canceled this year, and the third in five months.
ERCOT has distributed its membership applications and agreements for 2019, recommending that entities interested in joining the grid operator do so well in advance of Nov. 9 to avoid potential processing delays.
Applicants may join as a corporate, associate or adjunct members. Corporate membership includes the right to vote on general membership matters, such as election of certain board members, election of TAC representatives and members of TAC subcommittees, and amendments to the Certificate of Formation and bylaws.
Market participants are not required to be members.
Membership terms are for no more than a year and do not renew automatically. Dues are required at the time of application; applicants can request waivers for good cause.
Confirmation of board members and TAC representatives for 2019 will take place at the annual membership meeting Dec. 11.
More Information and copies of ERCOT’s bylaws and Articles of Incorporation can be found on the grid operator’s website.
SACRAMENTO, Calif. — Solar and wind will replace fossil fuels. Big batteries will store renewable energy. And every new vehicle sold will be electric.
The 1,000 or so attendees at CAISO’s Stakeholder Symposium got a glimpse of what the future could hold from visionaries, venture capitalists and carmakers during the event’s 10th anniversary at the Sacramento Convention Center.
“If we come back here in 2030 or 2040, we won’t even recognize the grid,” said Ron Dembo, a former Yale University professor and high-tech entrepreneur who kicked off the event as its keynote speaker.
Dembo’s message was to prepare for the unpredictable. He gave the example of a forest fire so fierce that it could jump a major freeway and burn down an urban neighborhood. That happened last year in Santa Rosa, Calif., but many experts would have called it highly unlikely before it occurred, he said.
“We’re moving into a more volatile world, and that requires a different way of looking at things,” he said.
Dembo and Mark Rothleder, CAISO’s vice president of market quality and renewable integration, said factors such as global temperatures, renewable energy and regional collaboration would guide the future grid. (See Can Calif. Go All Green Without a Western RTO?)
Other speakers warned about the dangers of climate change but laid out options that could limit global warming in the decades ahead.
Brian Davis, vice president of energy solutions at Shell’s New Energies business, explained the company’s Sky Scenario, a roadmap for meeting the goals of the international Paris Agreement and keeping global warming to under 2 degrees Celsius, primarily through the “deep electrification” of energy systems.
The company’s plan envisions moving to all-electric light transportation, a vast reduction in energy derived from oil and an equivalent increase in solar and wind production, and an end to deforestation and reforesting an area the size of Brazil.
Though extremely challenging, “it’s technically, economically and industrially possible to do it,” Davis, the conference’s final speaker, told the audience.
Between Dembo’s and Davis’ big-picture perspectives, panelists got down to the nuts and bolts of shaping tomorrow’s grid today.
Dan Richard, chairman of California’s High-Speed Rail Authority, said the controversial multibillion-dollar project, should be a way that the state’s 40 million residents, regardless of income, can travel up and down the state at 200 mph.
“So all Californians can benefit from this,” Richard said as part of a three-person panel on the electrification of the transportation sector and the future of mobility. “We don’t want this to be the Lexus train.”
The high-speed rail project has begun construction near Fresno, one of the state’s more affordable urban areas, and could put residents of that Central California city within commuting distance of jobs in Los Angeles, Richard and others said.
The rail line is one of outgoing Gov. Jerry Brown’s big infrastructure projects and has been criticized as an expensive boondoggle by many residents and elected officials. Richard said it’s a problem of imagination.
“People can’t imagine having high-speed rail” and what it will mean for them, he said.
One critic from Fresno acknowledged to Richard that it could mean that she and her husband could go to San Francisco for dinner and a show and be home by bedtime, he said.
China has built 8,000 miles of high-speed rail lines in only 15 years, and anyone who’s seen it quickly comprehends the benefits, he said.
Janea Scott, one of the five members of the California Energy Commission, moderated the transportation panel. She pointed out the problem of making electric transportation available to lower-income residents, for whom electric cars remain unaffordable and impractical.
Adam Langton, an electric vehicle expert with BMW of North America, said installing charging stations in lower-income neighborhoods would help, but that electric busses and trains should also be part of the solution.
“Think about electric miles,” he said.
Creating Utility-scale Storage
A separate panel, moderated by CAISO Director of Regional Integration Phil Pettingill, talked about EVs in the context of stored energy.
In 2018, demand for lithium-ion batteries for vehicles exceeded the demand for batteries for consumer electronics, said Yayoi Sekine, who leads the Americas coverage for Bloomberg’s energy storage practice. The demand for EV batteries has shot up rapidly and will increase to 1,500 GW of storage by 2030, she said.
A major problem now is how to store enough renewable energy to charge those car batteries and supply other energy needs after the sun sets. Solar generation is becoming less expensive and more abundant, especially in California, but it ramps up when it’s often least needed in the daytime and must be stored to meet peak evening and early-morning demand.
“Once you have enough batteries, you’re soaking up the solar,” Sekine said.
Sekine and her fellow panelist Yet-Ming Chiang, a professor at the Massachusetts Institute of Technology, said they believed bigger and less costly lithium-ion batteries were the best bet for large-scale storage going forward.
“The technology that works today and is dropping in cost is lithium-ion,” Chiang said.
However, he said scientists should look to cheaper and far more plentiful chemical components such as sulfur and saline for batteries. Future energy storage could end up looking more like chemical factories, with building-size vats connected by pipes and wire, than blocky batteries, he said.
“I think we’re on the cusp of significant growth in grid-scale storage.”
Investing for the Future
Carbon reduction is bound to be another growth area, said Nancy Pfund, founder and managing partner of DBL Partners, a venture capital firm that invests in social, economic and environmental change.
Pfund’s advice to investors was to “follow the carbon.” The past century was optimized for carbon, she said. “The next century will be optimized for carbon reduction and avoidance,” she said.
Fighting climate change will mean monetizing carbon reduction for private industry rather than relying on environmental groups and governments. In addition to transportation, agriculture is a major sector that produces atmospheric carbon and is ripe for technologies to reduce its greenhouse gas emissions, she said.
Pfund was joined on the symposium’s investment panel by Jill Anderson, vice president of customer programs and services with Southern California Edison, and Jackie Biskupski, mayor of Salt Lake City. The panel was moderated by Dede Hapner, formerly Pacific Gas and Electric’s vice president of FERC and ISO relations.
CAISO Chairman David Olsen said California’s ambitious goal of getting all of its energy from renewable and other zero-carbon sources by 2045 would require “electrifying just about everything.” And Valerie Fong, chair of the ISO’s Western Energy Imbalance Market, said, “Our industry is changing at an unprecedented rate.”
Wrapping up the conference, Shell’s Davis said it’s a remarkably dynamic time to be part of the electricity sector, as evidenced by the symposium’s discussion topics.
“Who would have thought 20 or 30 years ago the energy industry was an exciting place to work?” Davis said.
Sempra Energy’s transmission footprint in Texas is set to expand with the announcement Thursday that its Oncor utility subsidiary is acquiring transmission owner InfraREIT, while Sempra will buy a 50% stake in Sharyland Utilities.
Sempra CEO Jeffrey Martin said the combined $1.37 billion deals are “rotating capital away from noncore assets to core assets” in the company’s ongoing shift away from generation resources and commodities into the guaranteed rates of return of regulated infrastructure.
InfraREIT and Sharyland are both owned by Hunt Consolidated, which made a play for Oncor in 2016 but scrapped the deal after the Texas Public Utility Commission attached conditions considered unacceptable by the creditors of Oncor parent Energy Future Holdings. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.) Sempra acquired EFH’s 80% interest in Oncor earlier this year in an all-cash buyout valued at $9.45 billion. (See Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)
Martin called Oncor the “logical” owner of InfraREIT’s assets because of their “significant overlap” with the utility’s existing service territory. Sempra CFO Trevor Mihalik noted that approximately 260 miles of InfraREIT’s lines were previously owned by Oncor, but they were exchanged for Sharyland’s distribution system as part of a 2017 rate case settlement. (See Texas PUC OKs Settlement in Oncor-Sharyland Asset Swap.)
The companies plan to submit the transactions as a single integrated filing over the next few weeks for approval by the Texas PUC, company officials said during an analyst call Thursday. It will also require review and approval by FERC and other federal agencies, they said.
The deals are expected to receive final approvals and close in mid-2019.
Hunt will be the noneconomic general partner of Sharyland and continue to manage daily operations and appoint executive management.
Sempra said no equity will be issued to cover the price tag of the transactions. Sempra will fund its $1.12 billion share — which includes the $98 million to become a limited partner in Sharyland — with the proceeds from its recently announced $1.54 billion agreement to sell the majority of its renewable portfolio to Consolidated Edison.
The remainder of Oncor’s payment for InfraREIT will be funded through a capital contribution from Texas Transmission Investment, which owns the remaining 19.75% of Oncor. The deal includes InfraREIT’s outstanding debt of approximately $945 million and allows the company to solicit superior bids.
The deal also includes an “asset exchange” between InfraREIT and Sharyland that will result in all of InfraREIT’s assets being located in North, Central and West Texas and all of Sharyland’s being located in the southern part of the state. InfraREIT will receive two South Plains and Lubbock Power and Light interconnections, along with a Golden Spread Electric Cooperative transmission line that connects with its existing Competitive Renewable Energy Zone assets. Sharyland will receive a DC tie and assets in the city of McAllen that connect with its existing Cross Valley transmission line.
The swap will be a “like-kind exchange with no impact on taxes,” Mihalik said.
Infrastructure over Commodities
The deal continues Sempra’s bid to move away from the volatility of commodities in favor of the infrastructure that transports them, along with the stable returns those assets provide.
Oncor CEO Alan Nye explained the company’s focus in Texas by highlighting the state’s position as the second-largest economy among U.S. states and expectations that ERCOT’s load will increase 16% within 10 years. “Significant” transmission expansion will be necessary to interconnect the roughly 40 GW of wind capacity and 30 GW of solar currently in ERCOT’s interconnection queue, he said, along with oil and gas development in the Permian region of West Texas.
“The purchase of InfraREIT gives us access to high-quality transmission assets that are adjacent to our service territory and are a great fit for our portfolio,” Nye said. “InfraREIT’s existing presence in the panhandle and Permian places it in a unique position to benefit from these trends. … The larger the footprint we have in Texas, the more exposure we have to potential transmission investment opportunities.”
Sempra last month announced it was selling its interest in 980 MW of resources — 11 solar assets across the Southwest, and solar and battery storage development projects and one wind facility in Nebraska — to Consolidated Edison. The company’s remaining seven wind facilities of roughly 720 MW, additional wind development projects and approximately 40 Bcf of natural gas storage in the Gulf Coast region remain up for sale.
CEO Brad Jones abruptly left NYISO this week and will be replaced, at least temporarily, by General Counsel Robert Fernandez.
The ISO’s Board of Directors announced Fernandez’s appointment as interim CEO in a press release Wednesday.
Kevin Lanahan, vice president of external affairs, declined to elaborate beyond the press release, except to say Jones’ departure was “a personal decision by Brad.”
Former NYISO CEO Brad Jones and acting CEO Robert Fernandez | NYISO
Stakeholders told RTO Insider that senior ISO officials have told them the news was a surprise to them. “It’s a really big mystery … it came out of nowhere,” said a stakeholder, who, like others interviewed for this story, asked not to be identified. “Usually there’s a transition announced. We’re shocked. … We’re all sort of in the dark on this.”
A second stakeholder said the ISO’s vice presidents were not informed of Jones’ departure until Wednesday morning — shortly before the press release was issued — so they could brief their subordinates. “Secrets like this don’t keep very well. So, the limited subset of people who did know didn’t know for long,” he said.
Asked whether Jones had fallen out with stakeholders, he said “there’s always dissatisfaction” with ISO actions. “I guess they wouldn’t be doing their jobs right if they didn’t piss most of the people off” occasionally. But he said Jones had a reputation for being “even-handed and open to input. I don’t think I’ve heard anyone say a bad thing about the guy — which is pretty unusual.”
Jones, who joined NYISO from ERCOT, was commuting regularly from the ISO’s offices to his home in West Texas, according to sources. He had said he would not move permanently to New York while he had school-age daughters in Texas. He did not respond to a request for comment Thursday.
The Board of Directors tapped Fernandez as interim CEO at a meeting Tuesday. Stakeholders said Jones attended a Liaison Committee meeting with the board Tuesday and that there was no hint that it would be his last.
Lanahan declined to say whether the board intended to keep Fernandez as CEO or would launch a search for a successor.
NYISO Board Chair Ave Bie, former chair of the Wisconsin Public Service Commission, praised Gonzales in the ISO’s release, calling him “extremely talented” and saying he “will ably guide the company as we move forward during this transition period.” She did not respond to a request for comment.
Fernandez was named the ISO’s general counsel and chief compliance officer in 2000 after stints at Long Island Lighting Co. and independent power producer Sithe Energies. He has been involved in “all aspects of corporate governance, including market participant committee decision-making, appeals to the Board of Directors, as well as enterprise risk management,” the release said.
He earned his J.D. from Brooklyn Law School, a Master of Laws in taxation from New York University School of Law and a bachelor’s degree from Stony Brook University.
Jones, a registered engineer with a master’s degree in finance, joined NYISO in October 2015 from ERCOT, where he had been senior vice president and chief operating officer. Though born in Florida, Jones has spent most of his time in Texas, where he and his wife raised their six children. (See New NYISO Head Brings Broad Experience.)
Tom Kleckner and Michael Brooks contributed to this article.
MISO will shut down its regional planning office in Metairie, La., by the end of next year, RTO officials confirmed Wednesday.
The move will leave MISO with three physical locations: Carmel, Ind., Little Rock, Ark., and Eagan, Minn. MISO said it will not renew the lease at the Two Lakeway Center office building in the New Orleans metro area when it expires at the end of 2019. By then, the RTO hopes to complete relocation of employees and equipment.
MISO Metairie office location | Google
MISO spokesman Mark Adrian Brown said every employee at the Metairie office has the option to relocate to one of the other three offices. He said RTO leadership first disclosed the closure to employees in spring to ensure they had enough time to make relocation plans.
MISO is assisting affected employees with the transition. “We are working with each individual to ensure they have the information and support they need during this process,” Brown said.
The RTO has maintained the Metairie location since 2012, the year before it officially integrated Entergy’s territories into its footprint.
The closure will save MISO money, but it’s not clear how much, as the RTO doesn’t disclose how much it spends on property. Brown said shuttering the space will help support the RTO’s “overall organizational health.”
“MISO carefully studied a number of factors in the decision-making process. MISO is a steward of our members’ resources, and we must always consider the most efficient solutions and opportunities that enhance the value we deliver,” Brown in an email to RTO Insider. He added that the move would bring employees together and allow them to collaborate in its remaining and more modern regional offices.
In a 2019 budget report to the Audit and Finance Committee of the Board of Directors, Finance Subcommittee Chair Mitchell Myhre of Alliant Energy said the closure will “provide financial benefits in 2019 and beyond.” In recommendations this year, the seven-member committee also said MISO should be open to decreasing its scope of operations to cut costs.
MISO’s 2019 budget has not yet gone before the larger stakeholder community. The Finance Subcommittee will present the 2019 budget to the Advisory Committee on Oct. 24. The RTO is recommending a $312.6 million total operating budget and $27.2 million capital expense budget. MISO’s base operating budget, at $269.6 million, represents a 2% increase from 2018. (See “MISO Spending Closely Tracks 2018 Limit; RTO Ups 2019 Budget,” MISO Board of Directors Briefs: Sept. 20, 2018.)
FERC on Thursday approved reliability standards for mitigating supply chain risks in industrial control system hardware, software and computing and networking services. The commission also ordered NERC to develop rules expanding the supply chain protections to include electronic access control and monitoring systems (EACMS).
The commission’s final rule, intended to build on existing critical infrastructure protection (CIP) standards, approved NERC reliability standards CIP-013-1 (Cyber Security – Supply Chain Risk Management), CIP-005-6 (Cyber Security – Electronic Security Perimeter(s)) and CIP-010-3 (Cyber Security – Configuration Change Management and Vulnerability Assessments). The final rule hews closely to the commission’s January 2018 Notice of Proposed Rulemaking (RM17-13). (See FERC Backs NERC Supply Chain Standards.)
| Pixabay
The new rules, effective 60 days after publication in the Federal Register, will be implemented over 18 months, as requested by NERC. The commission said the transition was needed because compliance will likely require technical upgrades, with implications for capital budgets and planning cycles that have longer time horizons.
Counterfeits, Malicious Software
The rules are intended to protect the bulk electric system from counterfeits or malicious software and tampering. They require affected entities to implement security controls addressing: software integrity and authenticity; vendors’ remote access; information system planning; and vendor risk management. FERC said the rules will cover 288 reliability coordinators, generator operators, generator owners, interchange coordinators or authorities, transmission operators, balancing authorities and transmission owners.
FERC acknowledged the rules did not cover the supply chain risks of EACMS such as firewalls, authentication servers, security event monitoring systems, and intrusion detection and alerting systems. The commission said NERC must propose rules to address the gap within 24 months. “Once an EACMS is compromised, an attacker could more easily enter the [electronic security perimeters] and effectively control the BES cyber system or protected cyber asset,” FERC said.
The commission also noted the standards generally don’t address physical access control systems (PACS) or protected cyber assets (PCAs). “We remain concerned that the exclusion of these components may leave a gap in the supply chain risk management reliability standards. Nevertheless, in contrast to EACMS, we believe that more study is necessary to determine the impact of PACS and PCAs,” the commission said. “Compromise of PACS and PCAs are less likely. For example, a compromise of a PACS, which would potentially grant an attacker physical access to a BES cyber system or PCA, is less likely since physical access is also required.”
Budgets OK’d
The commission also approved NERC’s 2019 business plan along with almost $166 million in spending allocated for the U.S. share of funding NERC, its regional entities and the Western Interconnection Regional Advisory Body (WIRAB) (RR18-9).
The 2019 budgets include $62.5 million for NERC; $102.8 million for its seven regional entities’ funding and almost $630,000 for WIRAB.
Including funding from other sources, NERC’s 2019 budget is $79.1 million, an 8.4% increase over 2018. Most of the increase is attributed to expanding staffing and functions at its electricity information sharing and analysis center (E-ISAC). (See New NERC Chief Not ‘Smartest Guy in the Room’.)
NERC’s budget includes 205 full-time equivalents, an increase of six from 2018.
WASHINGTON — FERC on Thursday approved SPP’s proposal to allow generators to include major maintenance costs associated with the number of starts or run hours in their mitigated start-up and no-load offers in the RTO’s energy market (ER18-1632).
Under the changes, effective Jan. 15, 2019, generation owners will be required to submit each of their resources’ maintenance costs to SPP’s Market Monitoring Unit. If they’re validated, the MMU will then assign the costs by maintenance activity to either the resource’s start-up offer or the no-load offer.
Maintenance workers inspect a turbine. | Turbine Generator Maintenance
SPP said the proposal would not only result in more accurate compensation for generators’ costs, but also better help the RTO determine whether to dispatch resources and incent generators to run when dispatched.
Stakeholders had debated over what qualifies as major maintenance, and SPP decided to allow only activities agreed to in advance by the MMU and the resource owner to be eligible for cost recovery. Generation owners have 30 days to submit these to the MMU, which estimates that more than half of the 700 resources in SPP will apply to include major maintenance costs in their offers.
“We find SPP’s proposal to include a major maintenance cost component in mitigated start-up offers and mitigated no-load offer to be a just and reasonable means of addressing concerns over the recovery of costs resulting from the gradual deterioration of resources’ operating equipment in the SPP Integrated Marketplace,” the commission said.
The changes received support from the MMU, which had opposed earlier versions of the proposal, as well as City Utilities of Springfield and Golden Spread Electric Cooperative. No one submitted protests.
Chairman Kevin McIntyre did not attend Thursday’s open meeting and did not vote on the order.
While the deadline for compliance filings on FERC Order 845 remains at least three months away, PJM is making sure it’s prepared.
During an Oct. 16 conference call, PJM staffers Susan McGill and Michelle Harhai outlined 10 reforms included in the order, six for which the RTO has already drafted Tariff changes. The remaining four are in progress.
The order, expected to remove even more barriers to storage interconnection, explicitly revises the definition of a generating facility to include storage, permits interconnection customers to apply for interconnection service lower than the capacity of their generating facilities and requires transmission providers to provide interim interconnection agreements for limited operation of generating facilities prior to completion of the full interconnection process.
FERC on Oct. 3 granted an extension of the compliance filing deadline to 90 days while it considers multiple requests for rehearing of the order.
Energy storage | SDG&E
Takis Laios of American Electric Power said his company is finishing proposed revisions of PJM’s governing documents that it plans to submit for consideration.
PJM’s Pauline Foley said the revisions should be submitted “sooner rather than later” and cautioned Laios that because it’s a compliance filing, staff are trying to keep revisions “within the scope of [the order].”
“Anything beyond that would really be better handled in the stakeholder process,” she said.
Foley also noted that part of the challenge is marrying FERC’s order, which make assumptions about what’s already in grid operators’ tariffs, with what’s actually in PJM’s Tariff.
“The commission presumes that certain provisions are included in our Tariff, and a lot of the provisions when we originally made our 2003 compliance filing were not exactly as pro forma,” she said. With the expanded rules that FERC ordered, “we need to confirm that all of the provisions FERC presumes are there are actually there,” she said.
In response to a stakeholder question, Foley added that while “it’s not really practical to implement the order” before it’s fully been approved, interconnection customers can seek mutual agreements with transmission owners to utilize some of the impending rule changes.
MISO is hoping to avoid grid instability by possibly requiring inverter-based generation seeking to enter the interconnection queue to provide a specific set of calculations and documentation.
Under the plan, the owner of an inverter-based resource would be required to supply MISO its short-circuit ratio at the point of interconnection before completing an application. The RTO is also contemplating having a project owner either submit a manufacturer statement showing the inverter can operate stably or an Electromagnetic Transients Program (EMTP) study report confirming stable operation. Any project owner unable to prove stable operation will either have to add equipment to raise the short-circuit ratio or reduce the size of the project.
MISO interconnection engineer Warren Hess said the RTO will disallow use of its “momentary cessation” of active power output from inverter-based resources in order to prevent them from tripping offline unnecessarily. In that case, every generation resource would have to adhere to NERC’s PRC-024-2 standard, which requires generator owners to set their protective relays to ensure generating units remain connected during defined frequency and voltage excursions.
But stakeholders on an Oct. 16 Planning Subcommittee conference call said MISO might be requiring too much of inverter-based customers too early in the queue process. Some said the RTO should consider asking for short-circuit ratio values later in the queue process because those values will change as projects drop out of the queue. Consultant Roberto Paliza said such information should be provided at the end of the queue’s definitive planning phase, adding that MISO should make it clearer what performance standards it requires of inverter-based generation.
But Hess said that short-circuit calculations are relatively easy to provide once customers know the locations of their interconnections. He said MISO wants to avoid entering projects into the queue that ultimately cannot perform without causing harm.
“We are going to be here for guidance to help to calculate short-circuit ratios and coordinate with the applicable transmission owners. Since interconnection customers are deciding where to connect on the system, they should be responsible to work with the transmission owners to get short-circuit ratios for their inverter-based interconnection,” MISO Resource Interconnection Planning Manager Neil Shah said.
“Not doing anything is not an option,” agreed MISO Manager of Resource Interconnection Arash Ghodsian.
MISO staff also promised to work with interconnection customers and transmission owners to gather information and provide guidance on new interconnection requirements.
“This is going to be a two-way street,” Ghodosian said.
Staff said they plan to present draft Tariff language on the possible requirements at the Planning Subcommittee’s December meeting.
In two orders issued late last week affecting MISO’s generator interconnection queue, FERC rejected a maintenance fee for interconnection customers while also approving a new process for interconnecting external merchant HVDC transmission.
The commission on Oct. 12 rejected without prejudice MISO’s plan to create a new mechanism to allow transmission owners to calculate and recoup expenses related to the operation and maintenance of transmission owner interconnection facilities (TOIFs) (ER18-1731-001). TOIFs are “sole use” facilities that includes all infrastructure owned by the TO from the point of the change of ownership (on the system) to the point where an interconnection facility connects to the transmission system.
MISO proposed the “Annual O&M and Overheads Charge” because, while its current generator interconnection agreement makes interconnection customers responsible for all TOIF expenses, the RTO’s Tariff currently provides no method for TOs to recover those costs. The proposed charge would have been calculated by TOs and invoiced annually to interconnection customers, treating revenues from the charge as a revenue credit and subtracting it from a TO’s net revenue requirement.
MISO and the TOs contended their proposal was consistent with FERC’s cost-causation principles because the recovery mechanism ensured interconnection customers would pay their proportional share of maintenance expenses for interconnection facilities, eliminating the possibility that other customers would subsidize the facilities.
But the commission took issue with MISO allowing TOs to calculate the charge using estimated construction costs of the interconnection facilities from the GIA when they cannot determine the facilities’ actual costs. FERC said it wasn’t just or reasonable to allow use of estimates without requiring TOs to support their figures with a Section 205 filing. FERC also said MISO and the TOs did not provide evidence that the estimates would be a “reasonable proxy” for actual construction costs.
The commission additionally pointed out that MISO doesn’t file GIAs — which include the cost estimates — when they conform to its pro forma GIA template. It also pointed out the TOs don’t typically file detailed cost support for their GIA estimates of interconnection facilities. Consequently, MISO and the TOs essentially asked FERC to “accept the use of estimated values for the purpose of deriving a charge for operation, maintenance and repair of the facilities during their service lives without an opportunity to review the reasonableness of such estimates as a proxy for actual … costs,” the commission said.
FERC added that any future proposal should contemplate a partial-year charge for GIAs that expire midyear.
But FERC did accept MISO’s proposal to allow external merchant HVDC transmission projects to connect to its grid, effective July 18 (ER18-1410). The interconnection process is largely based on MISO’s existing queue rules but includes a separate pro forma “MHVDC” connection request form, a pro forma transmission connection agreement and a process for obtaining injection rights, which the project owner converts into external network resource interconnection service (E-NRIS) for its upstream generating facilities. In response to an initial deficiency letter from FERC, MISO explained that it relied on interconnection rules previously approved by FERC and an exhaustive stakeholder process to settle on the new process. (See FERC: MISO Merchant HVDC Procedures Incomplete.)
FERC said MISO’s plan was reasonable: “Because the MHVDC connection customer will go through MISO’s full interconnection process alongside internal generation customers, no issues of undue discrimination or preferential treatment arise between the external generators that may use the E-NRIS converted from injection rights and internal or other external generators that obtain NRIS or E-NRIS, respectively, through MISO’s [generator interconnection process].”
