SPP said last week that its Board of Directors has created a Holistic Integrated Tariff Team (HITT) comprising directors, regulators, staff and stakeholders to take an all-encompassing look at the different challenges facing its footprint and develop a set of high-level recommendations in response.
The team is hoping to replicate the success of a “synergistic” planning project team created nine years ago. That team produced a report that led to SPP’s integrated transmission planning process and the “highway/byway” cost allocation methodology for new transmission upgrades.
Transmission lines | Wind Energy Transmission Texas
The 16-member HITT includes Directors Larry Altenbaumer and Graham Edwards and state commissioners Shari Feist Albrecht (Kansas Corporation Commission) and Dennis Grennan (Nebraska Power Review Board).
The Nebraska Public Power District’s Tom Kent will serve as chair of the team and Dogwood Energy’s Rob Janssen as vice chair. SPP Legal Counsel Paul Suskie will serve as the team’s staff secretary.
Kansas City Power & Light’s Denise Buffington said she is looking forward to being one of four investor-owned utility representatives on the team. Buffington chaired a task force that was unable to reach consensus on improvements to SPP’s methodology for assigning financial credits and obligations for sponsored transmission upgrades under Attachment Z2 of its Tariff.
“Based on my experience with the Z2 task force, I anticipate there will be a lot to learn and it will be a multiyear process,” Buffington said.
The 16-person HITT will assess:
SPP’s transmission planning and study processes, including generation interconnections, the interconnection queue, energy resource and network resource interconnection service, aggregate studies, capacity requirements, and related FERC planning requirements.
Transmission cost allocation issues, including regional and zonal funding, directly assigned costs, Attachment Z2 credits, cost allocation impacts on transmission pricing zones with large wind resources, and state-by-state supply resource mix requirements and goals.
Effects on the Integrated Marketplace from a changing resource mix, access to lower cost generation and potential changes in production tax credits.
Disconnects or potential synergies between transmission planning and real-time reliability and economic operations.
Any other areas and issues seen as appropriate and reasonably related to the scope of work.
The HITT will report to the board’s Members Committee and provide status reports to the Regional State Committee, Markets and Operations Policy Committee and Strategic Planning Committee. SPP expects the team to complete its work with a written report by April 2019. It can request additional time, if needed.
AEP’s Wind Catcher project, with its GE turbines, has a potential 2 GW of energy-only resources. | GE
SPP stakeholders will be able to listen to the meetings and discussion through teleconference.
The group’s creation was approved during a board executive session March 13. During that same meeting, the board approved 18 policy statements that will guide Mountain West’s pending membership into SPP. (See SPP Begins Work of Integrating Mountain West.)
Joint Petition on SPP RE’s Dissolution Filed with FERC
NERC, the Midwest Reliability Organization and SERC Reliability Corp. have submitted to FERC a joint petition in connection with the SPP Regional Entity’s dissolution.
The filing follows the NERC Board of Trustees’ February vote to dissolve the SPP RE by terminating the RTO’s regional delegation agreement, ending a reliability oversight role that concerned both the reliability organization and FERC. (See NERC Board Approves Dissolving SPP Regional Entity.)
The petition requests FERC approval of:
The termination of the amended and restated delegation agreement (RDA) between NERC and SPP.
The proposed transfers of SPP RE registered entities to MRO and SERC by July 1, 2018.
The amendments to RDAs between NERC and MRO and between NERC and SERC to reflect the changed geographic footprint resulting from the transfer.
NERC requested that the commission expedite consideration of the petition and shorten the comment period to no more than 14 days “to allow a timely transition of registered entities from SPP RE to MRO and SERC with minimal disruption.”
FERC on Friday gave MISO the go-ahead on a second type of market definition for energy storage, though the commission warned that the RTO must address several more issues before storage can participate without obstacles.
MISO proposed the creation of a Stored Energy Resource Type II Tariff definition last April following Indianapolis Power & Light’s complaint against the RTO’s restrictive storage participation rules. (See MISO Ordered to Change Storage Rules Following IPL Complaint.)
FERC approved the new definition effective Dec. 1, 2017, but noted it lacked unique bidding parameters for storage resources, a path for storage to receive make-whole payments and an outline detailing how storage could provide voltage support and black start services (EL17-8, et al.).
But the commission said that all those aspects could wait until MISO’s compliance filing on Order 841, which requires RTOs and ISOs to allow energy storage resources full access to their markets. (See States, Utilities, RTOs Push Back on Storage Order.)
Exterior of Harding Street energy storage facility | DOE
“Even though the SER-Type II category will not fully accommodate the unique physical and operational characteristics of such resources, our action allows Indianapolis Power and other electric storage resources to participate in MISO’s markets while MISO develops and files with the commission proposed Tariff revisions that facilitate electric storage resource participation in compliance with Order No. 841,” FERC said.
A MISO compliance filing detailing a storage participation model consistent with Order 841 is due to FERC in December. From there, RTOs will have one year to implement the rules they have proposed.
FERC’s Friday order gave MISO 30 days to establish whether its new storage category is eligible to provide up and down ramp capability and to specify whether storage is subject to day-ahead energy must offer obligations.
An SER-Type II must be able to continuously discharge for four consecutive operating hours across a coincident peak each day; in return, it can function as demand response in the day-ahead market and can participate in the annual capacity auction. It can operate in front of the meter and supply energy, capacity, spinning reserve, supplemental reserve and regulating reserve. When it was created last year, MISO officials acknowledged that there was more to be done to remove barriers to entry. Prior to FERC’s ruling, storage could participate in MISO markets only as behind-the-meter regulating reserves (SER-Type I).
FERC agreed with IPL’s critique that it’s unreasonable for the SER-Type II to rely on “rules that were designed for other types of resources.”
SER-Type II is modeled on MISO’s existing DR resources for offer and dispatch purposes and treated as generation resources for settlements.
“Those participation models do not accommodate the unique features of electric storage technologies … and thus MISO’s proposed interim SER-Type II category has a number of significant technical deficiencies,” FERC said. MISO’s lack of bidding parameters left the commission unsure of how the RTO will use state-of-charge management to economically clear the resource in the day-ahead or real-time market.
“Storage resource-specific bidding parameters are an integral part of accommodating the unique physical and operational characteristics of electric storage resources,” FERC said.
The commission also said it was unreasonable for MISO to settle SER-Type II resources as generation resources without determining whether storage would be eligible for make-whole payments. “MISO has not explained why electric storage resources should not be provided with uplift payments in appropriate circumstances,” the commission said.
FERC’s order wasn’t all criticism; the commission acknowledged that in the interim, the SER-Type II category “improves market access for electric storage resources compared to the existing options under the MISO Tariff.” The commission also said it understands that MISO is limited by its current software and systems and the 60-day deadline it imposed on the RTO to create the new definition.
“Thus, although we find that MISO’s proposed interim SER-Type II category … does not fully accommodate the participation of electric storage resources as required … we find that MISO can address some of these Tariff deficiencies in its Order No. 841 compliance filing,” the commission said. MISO should turn to its stakeholders to solve the issues raised over the resource definition, FERC said. (See MISO Rules Must Bend for Storage, Stakeholders Say.)
No Rehearing for IPL
Last week’s order also contained a denial of a rehearing request from IPL.
Though FERC’s first order on IPL’s complaint directed MISO Tariff revisions that accommodate the participation of all storage resources in markets that they are technically capable of, FERC did not order the RTO to compensate providers of primary frequency response or rule that its current dispatch rules could harm the life of a storage battery, as IPL had requested.
Harding Street Energy Storage | AES
IPL sought rehearing last year, arguing that FERC disregarded 1996’s Order 888 when it refused to unbundle regulation service and primary frequency response. Keeping the two together, IPL argued, is preferential against its battery when compared to other generators. The utility also continued to contend that participation in MISO’s regulation market will degrade the useful life of its battery.
FERC didn’t bite at either argument.
“Beyond that alleged (and unsubstantiated) harm to the battery facility from offering regulation service, a service Indianapolis Power is technically capable of providing, Indianapolis Power does not explain why we should undo the determination in Order No. 888 by unbundling regulation service and primary frequency response service,” FERC said. “Nor does Indianapolis Power argue that the battery facility lacks the equipment necessary to provide regulation service. Moreover, contrary to Indianapolis Power’s assertion, the commission in Order No. 888 did not explicitly bundle regulation and primary frequency response services together because resources providing one of these services could recover its costs by providing the other service.”
FERC also found no merit in IPL’s complaint that MISO’s state-of-charge management protocol would compel market participants to either limit their state of charge or their output capability to 50%.
“We find that MISO’s proposal to allow individual market participants to control their own state of charge is reasonable because it will allow market participants, who are more familiar with the unique technical characteristics of their facilities, to control state of charge while MISO studies the issue,” FERC said.
Order 841
Earlier this month, MISO asked for a six-month extension on Order 841’s deadlines and sought clarification regarding bid parameters and the minimum storage size to be eligible for wholesale market participation.
MISO attorneys have said the RTO is concentrating on whether it’s “operationally feasible” for it to complete FERC’s directive to include all storage resources above 100 kW in a participation model. MISO’s participation model is finite in how many market participants it can accommodate, staff said at a March Market Subcommittee meeting.
Meanwhile, MISO’s Energy Storage Task Force will clarify with the Steering Committee this week as to whether it will help influence the RTO’s December compliance filing. (See MISO Storage Task Force Talks Order 841.) Throughout 2018, the Energy Storage Task Force will discuss ways storage can participate further, including generator-and-storage interconnection combinations and competitive bidding on storage projects that solve transmission issues. (See MISO Staff, Stakeholders Envision Expanded Storage Participation.)
Duke Energy last week announced an updated carbon-reduction plan that anticipates relying on natural gas and technology advancements to phase out coal-fired generation by 2050.
In a report on climate change to shareholders, the company said it plans to retire nine coal-fired plants, totaling 2,006 MW, by 2024. Between 2011 and 2017, it retired 47 units equaling 5,424 MW.
In the short term, gas-fired generation will pick up the slack. Duke projects natural gas generation will increase from about 30% of the company’s total generation today to 42% in 2030, while coal generation will decrease to 16%. Generation from wind, hydro and solar renewables will double to 10%.
2030 Goals
Duke says it has committed to spend $11 billion by 2026 to build new gas-fired, wind and solar generation with the goal of reducing carbon dioxide emissions 40% from 2005 levels by 2030. That would put companywide carbon dioxide emissions around 91.8 million pounds per year.
| Duke Energy
The goal would include reducing carbon intensity — pounds of carbon dioxide created per kilowatt-hour of production — by 45% compared to 2005 levels, equaling about 0.7 pounds/kWh. As of 2016, according to the company, it has already reduced its carbon dioxide emissions 29% and its carbon intensity 25% below 2005 levels.
Coal-free by 2050
To phase out coal by 2050, Duke anticipates generation from renewables more than doubling again to 23% and gas-fired generation falling back to 33%. It would also rely on 13% from currently nonexistent technology that has zero emissions and can vary its output to match demand. Potential candidates are nuclear that can vary its output (current technologies are inflexible), closed cycle biomass-fired facilities and combined cycle gas turbines (CCGTs) with carbon capture and storage.
Duke plans to phase out coal-fired generation by 2050 by increasing production from natural gas, renewables and as-yet-unknown technology that is emissions free and can vary its output with demand. | Duke Energy
“In the past 15 years, we’ve seen dramatic advancements in energy technology, including abundant natural gas due to hydraulic fracturing, and declining prices of solar and wind technology. Given this rapid pace of development, we fully expect technology innovations in the coming decades,” the report explained.
The report assumes that, including efficiency programs, load increases 0.45% each year. It also relies on natural gas prices remaining flat through 2028 and increasing 4% annually after that, along with 20-year license extensions for its 9,000 MW of nuclear generation. The estimates are based on limiting global warming to no more than a 2-degree Celsius increase and assume that all emissions sources throughout the world reduce by the same amount: 74% compared to 2005 levels.
100% Renewables Unrealistic
The report explains that renewables have diminishing returns because of lower capacity factors and sides with academics who — in a recent white-paper war — argued there are cheaper ways to achieve zero carbon dioxide emissions in the energy sector than switching completely to renewables.
“As the adoption of renewables grows to between 20 and 30% of total generation, the value of the resource begins to diminish due to extended periods of excess energy in the spring and fall and insufficient output during the winter months,” Duke said. “We do not believe 100% renewables can reliably deliver the power required by a modern economy. Similarly, we do not advocate for 100% natural gas or nuclear energy. An analysis published in the Proceedings of the National Academy of Science[s] concluded that a decarbonized energy system would very likely need other technologies besides renewables, including nuclear and carbon capture and sequestration.”
Another analysis concluded “that the high-renewables scenario was likely the most costly, while both the mixed scenario (renewables, nuclear and carbon capture on fossil) and the high-nuclear scenario would likely cost less,” Duke’s report said.
DENVER — Out in the wild, wild West, four different entities are offering reliability coordination (RC) or market services, Mountain West Transmission Group members are pursuing RTO membership with SPP, and CAISO is pressing the California legislature to allow it to become an RTO.
That was the backdrop of another Colorado Public Utilities Commission public information session last week, its fifth, on the potential marriage between SPP and Mountain West.
“We here are in control of the dowry. We have to be persuaded before this can go any way you want it,” Commissioner Frances Koncilja said, reminding her audience that the PUC has jurisdiction over Mountain West members Black Hills Energy and Public Service Company of Colorado (PSCo).
The March 20 session, “What is Going on with Reliability and Market Services in the West?”, brought together SPP, Mountain West, CAISO, PJM and Peak Reliability, all of which are considering offering RC services or setting up markets in the West.
SPP and Mountain West have been working on their combination since January 2017. Mountain West members in January 2018 signed a nonbinding letter of intent to explore getting RC service from SPP by Sept. 1, 2019. In February, they sent revocable notices of withdrawal to Peak, effective that same date.
Just after New Year’s Day, CAISO gave Peak, the Western Electric Coordinating Council’s (WECC) RC, 20 months’ notice that it is leaving Peak to offer its own reliability services for half the price. Peak, meanwhile, is continuing with its plans to offer market services in the Western Interconnection through a joint effort with PJM called PJM Connext. (See CAISO to Depart Peak Reliability, Become RC and Peak, PJM Detail Western Market Proposal.)
“Clearly, we’re interested in how this region is shaking out,” said PUC Chair Jeffrey Ackermann. “People are keeping their feet in different prospects. Where are the points of no return from the Mountain West perspective, in terms of SPP? Are we having basically sidebar conversations, or are we still in a state of flux?”
Peak CEO Marie Jordan’s comments seemed to imply that SPP’s integration of Mountain West is a done deal. She referred to sharing data with SPP, which she called a “good operator,” and working to ensure that Peak smoothly coordinates the transition of its RC responsibilities to SPP and CAISO.
Peak and SPP already have a seams agreement in place that Jordan said has “worked great” over the years. The entities share four DC ties, over which they are capable of exchanging 720 MW of energy.
“It’s going to be important [that SPP] gets to the data, so they can start building their model,” Jordan said. “They need to be able to interface with our model to have a really good strong handoff for reliability coordination. There will be a tremendous amount of interaction between us.
“The horse is out of the barn,” she said. “CAISO set this in motion when they issued the notice to leave Peak. Our intention is to ensure [that] as we make this transition, we do this well for the reliability of the Western Interconnection.”
Between CAISO and the Mountain West members, Peak stands to lose almost 40% of its $45 million annual operating budget. Jordan said Peak’s core RC costs are estimated at 5.5 cents/MWh, or about 60 cents/MWh per customer annually. To protect its investment in RC support tools, she said Peak must separate those costs from its RC-only costs to take on its new competition.
“As it relates to the overall reliability of the West, I’m a little bit concerned that it’s a race to the bottom with a focus on costs,” she said. “But if we’re going to compete, that’s an important step.”
Enter, then, PJM, and its collaboration with Peak.
“We are proposing an alternative that provides an opportunity for entities in the West to participate in a market that is for the West and by the West,” said PJM’s Stu Bresler, who also serves as board chair for PJM Connext. “They can determine what they want on their own, including a potential pathway or roadmap to an RTO, if that’s what they want.”
Bresler and Jordan proclaimed PJM Connext to be a perfect fit. Bresler pointed to Peak’s expertise in the West and its existing infrastructure as presenting the “fundamental foundation” in establishing a market, while Jordan noted PJM’s market has a 20-year history and low costs.
“They’re the largest market in world, but also the lowest cost,” Jordan said.
“We think leveraging the expertise of Peak with PJM’s expertise in markets represents a true value proposition,” Bresler said. “We believe we can deliver a market the stakeholders in the West want. We’re not plopping down PJM’s market design in the West. The idea is that the stakeholders will determine the market that is implemented, as opposed to joining one that already exists.”
Peak and PJM hope to complete a business case for PJM Connext by March 30 that “sets expectations for Day 1” and projects the cost of standing up the market and ongoing operations.
CAISO is taking a similar approach, saying it will work with Western companies to determine what level of market or RTO services to offer. The ISO has begun a rate design project with its stakeholders as it works at getting WECC RC certification by August 2019. It also is continuing development of its Energy Imbalance Market (EIM).
“Out of the gate, we think there is value in leveraging the EIM market,” said Stacey Crowley, CAISO’s vice president of regional and federal affairs. “Is there potential to expand that authority into certain day-ahead rules? We want to find out if that’s enough, or if that’s the right way to go.”
Koncilja asked what she called the “ultimate question” — “Why do you think your proposed services are the best option for Colorado utilities and their ratepayers?”
Mark Rothleder, CAISO’s vice president of market quality and renewable integration, responded that his organization is offering an incremental way of developing a market.
“From that perspective, we can structure our proposal so maybe you start with an energy imbalance market, then move to a day-ahead market,” he said. “Then, we’ll see if there’s a need, a value, to full RTO participation.”
Koncilja then asked SPP COO Carl Monroe what Colorado would lose out on “if we say we want to ease into this?”
Monroe said that question was better suited for the Mountain West entities, who first began looking at RTO membership in 2013 to collapse their multiple rates into one system tariff. They also will realize additional benefits through the efficient exchange of energy over the DC ties, regional transmission planning and SPP’s other RTO services, he said.
“You would give up the benefits that you could get by going the full length with a RTO,” Monroe said. “The EIM is just part of the CAISO proposal. They haven’t solved all the issues. You still see them trying to plan that. In some regards, you’re leaving money on the table.”
Koncilja has emerged as the PUC’s most vocal skeptic of Mountain West’s move into SPP. She opened the meeting by questioning the integration’s value to her state.
“Is this the best fit for Colorado? Is now the best time to do it, and what will it cost?” she said. “There are allegedly millions of dollars in savings, but I haven’t seen a cost-benefit study since Brattle, which is almost a year old.”
She was referring to a 2016 Brattle Group study, which indicated that Mountain West participants would see an $88 million annual reduction in production costs by moving to a regional market without must-run generation.
Mountain West and SPP also commissioned The Glarus Group to conduct a second study on the economic benefits from scheduling power over the four DC ties. Glarus said Mountain West and SPP could expect to see net production cost savings ranging from $11.7 million to $28.8 million yearly.
“That’s not a big number, in light of what we’re talking about,” Koncilja said of the Glarus study. She said she would like to see the studies supplemented, “because they don’t give me the information I want.”
“You’re talking about two studies that I think have holes in them,” Koncilja said.
Monroe said the Glarus study doesn’t consider the benefits that members get from participating in the market and its diverse resources. Glarus said its results did not reflect real-time market optimization, ancillary services or regional through-and-out transmission revenues that may be available because of better use of the ties.
“Our transmission planning reduces the cost of transmission, because we can do it more effectively regionally, and find projects that reduce the cost of energy to our customers,” Monroe said.
SPP has conducted its own 10-year cost-benefit analysis of the integration, which indicates its existing members could see benefits as high as $548 million in net present value from 2020 through 2029. Members will see a phased-in, reduced administrative fee that drops from 48 cents/MWh to 43 cents for 2020.
FERC Filings to Begin in August-September
Monroe said Friday that SPP intends to bring a “whole package” of proposed Tariff changes to the RTO’s July leadership meetings, with FERC filings beginning as soon as August or September. He said the changes will be batched together as appropriate.
“It will rely on us keeping FERC involved throughout this process,” Monroe said. “We will spend more time with FERC than we would normally do at this point in the process.”
Monroe said FERC is revising its filing processes following the D.C. Circuit Court of Appeals’ ruling last year that the commission had overstepped its authority in undoing a PJM compromise on its minimum offer price rule. (See On Remand, FERC Rejects PJM MOPR Compromise.)
“We anticipate multiple filings, but we want them treated together,” Monroe said.
His comments came during a webinar reviewing the recently approved 18 policy statements that will guide Mountain West’s pending membership into SPP. The RTO’s Board of Directors approved the statements during a March 13 executive session, and directed staff and stakeholders to begin revising SPP’s Tariff, bylaws, membership agreement and other governing documents. (See SPP Begins Work of Integrating Mountain West.)
The first Tariff changes related to Mountain West’s integration have already begun bubbling up through the stakeholder process, with a revision request updating day-ahead make-whole payment charge types going out for comment.
Stakeholders were a little taken aback by an offhand comment during a discussion about the possibility of a Mountain West member pulling out of the integration.
“We’ve talked about how intertwined [Mountain West’s members] are. That’s why they are working together on this. If one wanted to [withdraw], and it was a small enough entity, and it didn’t affect the others,” it might not hurt the effort, Monroe said. “But we won’t know until we get to that point.”
“That would affect the entire analysis we have been working on,” Oklahoma Gas & Electric’s Greg McAuley said.
FOLSOM, Calif. — The CAISO Board of Governors on Thursday approved a controversial proposal on congestion revenue rights and market power mitigation, changes with major financial implications for its markets.
The changes are a result of the CAISO Department of Market Monitoring’s conclusion that the annual CRR auctions are costing retail electricity customers hundreds of millions of dollars by forcing them to be unwilling partners in losing transactions.
CAISO’s proposal limits CRR sources and sinks to only the combinations needed to hedge congestion costs associated with delivering supply. Auction participants can currently purchase CRRs at generator locations, load locations, trading hubs, pricing nodes, and import and export scheduling points.
Another change establishes a deadline to report transmission outages prior to the auctions to more accurately estimate transmission capacity available for CRR purchases.
The CRR auctions have been highly profitable for financial interests, leading to heavy debate and questioning of CAISO’s logic. That debate continued Thursday, with the broadest consensus being that the board-approved changes, which will be submitted for FERC approval, only partially addressed the situation. The ISO says further alterations to the CRR process are in the pipeline.
“This is a serious issue that has to be fixed,” Chairman David Olsen said as the board unanimously approved the proposal.
Governor Ashutosh Bhagwat said that without voluntary sellers, “it’s not a real market,” and he asked whether CRRs could be handled through bilateral transactions.
“These are not voluntary sellers,” he said of CRRs, “and it’s not working.”
There had been much discussion during development of the proposal over whether it would overly limit legitimate hedging activity. (See CAISO Urged to Take Slower CRR Approach.)
During Thursday’s discussion, CAISO CEO Steve Berberich responded to the criticism by saying that CRRs are a valid market tool. But “this is a watershed moment for this organization to send a message … and that is, we agree the current situation has to change,” he said.
By the Monitor’s calculations, the CRR auction has had a $750 million deficiency for retail ratepayers, and annual deficiencies will grow in 2018 under the current structure. The Monitor did not support the changes and said the auction should be based on “willing buyers and sellers” and that more fundamental flaws should be addressed.
CAISO Approves Bidding Rule Changes
The board also approved CAISO’s Commitment Cost and Default Energy Bid Enhancements (CCDEBE), another contentious proposal that is opposed by some investor-owned utilities.
The proposal replaces a static commitment cost bid cap with a local market power mitigation test, which identifies whether a resource needs to be committed to relieve a transmission overload or other constraints. The ISO will only mitigate bids when a generator fails the test.
The Energy Imbalance Market (EIM) Governing Body earlier this month gave advisory approval of the changes, subject to a condition that staff brief it and the CAISO board at the 12-month point following implementation of the changes. (See EIM Governing Body Approves CAISO Bidding Flexibility.) The ISO has been developing the proposal since last year to address what is said to be inadequate cost recovery for generators.
Under the current rules, bids are capped at the generator’s reference level, which is determined by multiplying costs — based on published natural gas price indices — by 125%.
CAISO recently adjusted the proposal by lowering the proposed multiplier for the first 18-month period after implementation to 150% from 200%. The ISO plans to phase in commitment cost bidding flexibility, first raising the commitment cost multiplier to 150% for the first 18 months, and then increasing it to 300% if no issues arise.
Pacific Gas and Electric wants CAISO to maintain the existing 125% cap, saying CCDEBE will have limited benefits. NRG Energy said the proposed caps are too low.
Board Approves Transmission Plan
The board on Thursday also approved the ISO’s 2017-2018 transmission plan, which cuts $2.7 billion from previously approved projects. The plan outlines the proposed design and construction of 17 new projects costing about $271 million. It recommends cancellation of 18 projects and revises 21 others in PG&E’s service area, and two in the San Diego Gas & Electric territory.
The main reasons for the reductions were changing load forecasts, energy efficiency improvements and increased residential rooftop solar systems. (See CAISO Recommends $2.7 Billion Tx Spending Cut.)
The approval will be used to launch the next planning phase, as it is plugged into the California Public Utilities Commission transmission procurement plan for utilities. The process will determine eligibility for incentive rate cost recovery from FERC by virtue of being part of a state plan.
FERC has cleared an ITC Holdings subsidiary to buy nearly a quarter million dollars’ worth of transmission assets from a Michigan municipal power agency as part of a settlement over transmission system access.
The $247,225.99 sale of transmission assets in southern Michigan from Michigan South Central Power Agency (MSCPA) to Michigan Electric Transmission Co. (METC) is consistent with public interest, FERC said on Monday (EC18-35).
The sale satisfies part of a settlement approved by the commission last year after a 2016 MSCPA complaint alleging METC was trying to restrict the agency’s ownership entitlements to the transmission system and improperly collect annual payments as high as $1.7 million for transmission use, in violation of a contract struck in 1980. METC’s change to the contract’s terms was prompted by the 2016 retirement of MSCPA’s 62-MW Endicott Generating Station.
Endicott Generating Station | MSCPA
FERC said the transmission sale will have no impact on rates or competition. METC also committed to hold customers harmless from any costs related to the sale.
FERC last week approved an uncontested settlement between SPP and several of its members to add an annual revenue requirement and implement a formula rate template and protocols for a new member (ER17-428).
The settlement resulted from SPP’s 2016 filing that amended its Tariff governing transmission facilities owned by Vermillion Light & Power (VLP). The changes concerned VLP’s base rate of return on equity, payment in lieu of taxes, plant depreciation rate, payment of refunds dating back to Feb. 1, 2017, with interest, and other related adjustments.
VLP, which is owned by the town of Vermillion, S.D., is a member of Missouri River Energy Services (MRES).
Vermillion, S.D.
MRES and VLP said the settlement included three concessions: a 10-basis-point reduction from the as-filed base ROE of 9.7% to a settlement base ROE of 9.6%; an agreement that VLP is prohibited from seeking a change in the ROE until March 1, 2020; and a provision requiring VLP to make a Section 205 filing to participate in certain regionally cost-shared projects.
SPP filed the settlement offer in December on behalf of itself; MRES; Basin Electric Power Cooperative; East River Electric Power Cooperative; Heartland Consumers Power District; Mountrail-Williams Electric Cooperative; and the Western Area Power Administration.
FERC last week also approved an uncontested settlement between NextEra Energy Transmission Southwest (NEET Southwest) and the Kansas Corporation Commission over the company’s base ROE (ER16-2720).
The Missouri River | American Rivers
FERC accepted NEET Southwest’s base ROE of 9.8% to recover costs associated with the transmission assets it develops in SPP. The company’s total ROE, including incentives and adders, will not exceed 10.8%.
NEET Southwest had requested a base ROE of 10.5% with a 50-basis-point incentive adder in 2016, but the Kansas commission protested the ROE portion of the filing.
FERC last week rejected state and local regulators’ rehearing request over MISO’s plan to include its South region in cost sharing for its new category of interregional projects with PJM.
The commission on Monday said it was not convinced by the regulators’ reasoning for rehearing MISO’s planned regional cost allocation on its targeted market efficiency projects (TMEPs), a new, smaller breed of interregional project developed with PJM that targets historical congestion along the RTOs’ seams (ER17-2246-002).
All based in MISO South, the regulators — the Arkansas, Louisiana and Mississippi public service commissions; New Orleans City Council; and the Public Utility Commission of Texas — argued that the RTO’s filing was flawed because it had not named a termination date of the TMEP regional cost-sharing proposal when Entergy’s five-year transition period that limits cost-sharing in the region ends in December.
By that time, MISO has promised to have a comprehensive post-transition period cost allocation proposal filed with FERC. The RTO has been working with stakeholders on a preliminary proposal that would make cost sharing available to 100-kV projects along the PJM and SPP seams but limit it to internal market efficiency projects of 230 kV and above. (See Stakeholders Debate MISO Cost Allocation Plan.)
The regulators wanted assurances that MISO’s TMEP regional cost-sharing plan would not apply beyond the transition period or to MISO South. When it approved the plan late last year, FERC said that if MISO does not have a cost allocation plan readied as promised, the regional TMEP cost allocation would continue to be in effect even after the transition period expires. The RTO proposed to assign its regional share of the costs of TMEPs to transmission pricing zones based on their historical contribution to the market-to-market congestion relieved by the project.
The regulators said FERC’s decision improperly modified MISO’s proposal, citing the D.C. Circuit Court of Appeals’ 2017 ruling that the commission overstepped its authority in prescribing revisions to PJM’s minimum offer price rule. (See On Remand, FERC Rejects PJM MOPR Compromise.)
However, FERC said the MISO South regulators did not have a case for rehearing because they could not prove its decision had caused a concrete injury, or “aggrievement.” TMEP costs could be assigned to MISO South once the transition period expires, FERC acknowledged, but it also said that it was not clear a “mere potential for future harm” is substantial enough to amount to aggrievement.
| MISO
FERC also said MISO has already outlined a plan for if it does not follow through on a finalized comprehensive cost allocation. In that case, certain projects included in the annual Transmission Expansion Plan, including TMEPs, will be subject to the RTO’s existing cost allocation Tariff language.
“Commission precedent is clear: In the event of a conflict between pleadings and proposed tariff language, the tariff language controls,” FERC said.
The commission also disagreed with the regulators’ contention that by specifying that MISO’s plan could continue past the transition period expiration, it “transform[ed] the proposal into an entirely new rate of FERC’s own making.” It noted that MISO has committed to filing a new regional cost-sharing method for assigning MISO’s share of the costs of TMEPs prior to the end of the transition period.
“While we understand MISO South regulators’ desire for certainty regarding future assignment of MISO’s share of the costs of TMEPs, MISO has provided no indication that it intends to deviate from the commitment in its pleadings to convene stakeholder proceedings to develop a post-transition period proposal,” FERC said.
MISO and PJM’s TMEP portfolio, approved last year, comprises five congestion-relieving interregional upgrades to existing systems in Illinois, Indiana, Michigan and Ohio. The projects, which have individual $20 million cost caps, will coincidentally cost $20 million combined. On average, the projects’ costs will be allocated 69% to PJM and 31% to MISO, based on projected benefits, which are expected to reach $100 million. (See FERC Conditionally OKs MISO-PJM Targeted Project Plan.)
Three top generators in Maine have asked the state’s Public Utilities Commission to allow them to intervene late as full parties in the proceeding on New England Clean Energy Connect (NECEC), the 1,200-MW HVDC transmission line proposed by Central Maine Power (CMP) and Hydro-Quebec.
The 145-mile project before the PUC (2017-00232) would deliver Canadian hydropower from Quebec to Lewiston, Maine, at an estimated cost of $950 million. CMP is a subsidiary of Avangrid.
Lewiston substation | Central Maine Power
Massachusetts last month selected NECEC as the alternative for the state’s 9.45-TWh clean energy solicitation after the New Hampshire Site Evaluation Committee (SEC) unanimously rejected Eversource Energy and Hydro-Quebec’s Northern Pass, the 1,090-MW transmission project that the Bay State had awarded the contract just a week earlier. (See Mass. Picks Avangrid Project as Northern Pass Backup.)
Survival Mode
Generators Calpine, Dynegy and Bucksport Generation, owners of one-third of the installed electric generating capacity in Maine, told the PUC that awarding a certificate of public convenience and necessity to NECEC would threaten their plants’ economic survival and harm the region’s competitive wholesale power market.
New England Clean Energy Connect (NECEC) shown in orange | Central Maine Power
The PUC plans to issue a decision on the proposal by September, a year after CMP filed, which is standard procedure. Maine Gov. Paul LePage and his Energy Office both wrote letters to the PUC urging it to review CMP’s petition in an “expeditious manner” and not delay or suspend the proceeding.
CMP on March 23 responded and said they did not object to the late‐filed intervention — if the PUC prohibits the intervenors from reopening phases of the case that have already closed.
The generators “seek to entirely reset the clock in this matter and introduce intervenor testimony in utter disregard of the fact that the commission and the parties are six months into a 12-month case schedule, the period for intervenor discovery on CMP’s initial petition has closed, and the deadline for intervenor testimony has passed, not once, but two times,” CMP said.
The generators argued that the developer presented reduced wholesale energy and capacity prices in the region and in Maine as the primary benefit of the project and made no case for reliability benefits.
However, CMP did just that in its September 2017 filing: “In addition to the electricity price suppression, [greenhouse gas] reductions and employment and economic development benefits discussed above, the NECEC transmission project will provide Maine resource adequacy and transmission system reliability benefits at no cost to Maine customers.”
CMP argued in its initial filing that “transmission upgrades to permit an additional 1,200 MW of generation to interconnect” ensures that NECEC’s power “will be deliverable to the New England Control Area. The addition of this non-natural gas-fired capacity (and related energy) will help ensure that ISO-NE has adequate generation resources available to meet load and reserve requirements throughout the year, including especially during periods when natural gas supplies are constrained.”
The intervening generators said “it is abundantly clear that the integration of large-scale, out-of-market (i.e., subsidized) resources within the current ISO-NE market may have profound unintended consequences, which is evidenced by the extensive and challenging stakeholder discussions during the [New England Power Pool’s Integrating Markets and Public Policy] debate and subsequent NEPOOL and FERC-related reviews of proposed capacity market reforms.” (See CASPR Filing Draws Stakeholder Support, Protests.)
Impeding Renewables
Massachusetts issued its MA 83D solicitation for hydro and Class I renewables (wind, solar or energy storage) last July. The selection committee for the clean energy request for proposals issued in July 2017 includes representatives from the state’s Department of Energy Resources and from distribution utilities Eversource, National Grid and Unitil.
Calpine owns and operates the 552 MW natural gas-fired Westbrook Energy Center power plant in Maine. | Calpine
Any contract awarded under the RFP must be negotiated by March 27 and submitted to the state’s Department of Public Utilities by April 25. The New Hampshire SEC voted March 12 to wait until its Northern Pass permit denial is published later this month before considering Eversource’s appeal of that decision, effectively killing the project’s chance to meet the Massachusetts deadline.
The New England generators told the Maine PUC that they “had good cause for delaying their intervention efforts” in that NECEC had been one of more than 40 bids competing to secure the Massachusetts contract and that “it would have been highly impractical for the [generators] to intervene in siting and/or certificate proceedings for every one.”
“At the time, it was widely believed that Eversource Energy, as a member of the state’s evaluation team, would favor its own affiliate’s project, Northern Pass Transmission in New Hampshire, as subsequently proved to be the case,” they said.
The generators also questioned the claim that NECEC will lead to lower prices.
“It is abundantly clear that [NECEC] has been proposed solely to meet a Massachusetts policy goal; it has nothing to do with meeting the needs of Maine ratepayers, and the primary long-term benefits of the project will accrue to Hydro-Quebec and CMP shareholders,” they said.
The generators further argued that, should the project go forward, “it will impede the development of alternative renewable energy projects in Maine, such as solar and onshore and offshore wind farms, for the foreseeable future. This result would be contrary to Maine’s statutory policy favoring the use of ‘renewable, efficient and indigenous resources.’”
The Conservation Law Foundation filed comments asking the PUC to wait until the Massachusetts RFP has been decided before considering the NECEC proposal.
The CLF argued that presumption of the project’s selection in the state RFP underlies CMP’s cost analysis. It also said CMP’s “calculations of benefits including greenhouse gas emission reductions, improvements in system reliability, reductions in electricity prices, and employment benefits … are premised on a baseline scenario in which there is no other project selected in the Mass. RFP.”
MISO is surveying how to get more information from load-serving entities to create a more detailed load forecast for transmission planning, though stakeholders continue to question the feasibility of the plan.
MISO Senior Policy Studies Planner Temujin Roach said the RTO wants to try “bottom-down” load forecasting, where it relies on data compiled from LSEs to form the basis of its load forecast that informs transmission buildout. For that, MISO’s 140-plus LSEs will have to annually assemble four different 20-year load forecasts to fit with each of the RTO’s four future scenarios developed for the Transmission Expansion Plan. (See MISO Looks to Align Load Forecasting, Tx Planning.)
The approach is one of two MISO is vetting to improve its load forecasts. If LSEs decide they cannot collect that level of information, the RTO will continue its practice of hiring a contractor to put together a load forecast. In that case, Roach said the level of specificity would not be as detailed, though the contractor would take any load information LSEs provide on a voluntary basis. MISO currently uses Purdue University’s State Utility Forecasting Group to create an independent load forecast; the forecast is not based on any of the MTEP future scenarios.
| Purdue University
MISO has a survey out until April 12 asking LSE owners how feasible it is to put such forecasts together and how much it may cost LSEs to assemble detailed load data.
“For some, it’s negligible so far, and for others, it may be a burden,” Roach said during a special March 21 conference call on improving MISO’s load forecast.
“What we’re looking for from load-serving entities is if this is information they already have, or if they’re willing to provide it,” Roach added.
Stakeholders asked what share of LSEs had to participate in the forecasting before MISO would pursue the new approach. Roach said he didn’t know.
“We’re looking for a feel of who has got problems with it and how feasible it is — most specifically it’s the small munis and co-ops that might not have the ability to forecast already in place. … We’d be willing to work with them and make this as painless as possible,” Roach said. “I don’t have an answer. It depends on who is struggling with it, and how big their loads are. We need more information to make … a prudent decision.”
Stakeholders Skeptical
Several stakeholders said they still weren’t convinced MISO had put enough thought into how it would align 140-plus disparate data sets into a cohesive load forecast.
Minnesota Public Utilities Commission staff member Hwikwon Ham said that LSEs don’t understand how MISO expects them to adapt their base-case loads to fit into the “limited fleet change,” “continued fleet change,” “accelerated fleet change” and “distributed and emerging technologies” MTEP futures.
Roach said MISO would most likely hold workshops and develop a Business Practices Manual to describe how to approach the data.
“I’d like to hitch onto [the] exasperation,” said WPPI Energy’s Steve Leovy. “I don’t know how to provide what MISO is asking, because I don’t think the data question is adequately specified. I don’t think multiple LSEs have the same idea about it.”
