An energy consulting firm thinks MISO has the potential for several gigawatts of demand-side energy savings by 2038, stakeholders learned Thursday.
The 20-year estimates of MISO’s future demand response, energy efficiency and distributed generation were produced by Applied Energy Group (AEG), with near final results presented to stakeholders at a special March 22 conference call. The commissioned study will inform the RTO’s 2019 Transmission Expansion Plan, with researchers using the conditions from four MTEP future predictions to project likely demand-side management.
By 2038, total demand-side management could reduce MISO peak summer demand by 22.5 GW, or about 15%, with 11.3 GW of the energy savings from energy efficiency, 7.2 GW from DR and 4 GW from distributed generation. Next year, AEG predicts MISO will save about 8.2 GW on summer peak demand from demand-side management.
Summer peak demand savings | Applied Energy Group
In two decades, energy efficiency will be responsible for a 69,899-GWh annual energy savings in MISO; distributed generation will account for a 19,566-GWh annual savings; and DR programs will yield a 539-GWh annual savings. The 89,971-GWh savings total by 2038 is a more than seven-fold increase from AEG’s expected 12,764-GWh savings in 2019.
AEG predicts that Michigan, Minnesota, Iowa and Wisconsin have the most potential for energy savings through the next 20 years.
Annual energy savings | Applied Energy Group
Some stakeholders commented that there was virtually no way to verify AEG’s forecasted values with what transpires because behind-the-meter activity is expected to remain largely undocumented.
AEG Managing Director Michael Daukoru said his firm examined both regional and state-specific customer adoption trends along with various state incentives, costs of programs, utility-provided forecasts and capacity growth rates in the study.
MISO staff have said the trickiest part of load forecasting is capturing and projecting the footprint’s unknown amount of demand-side management. (See MISO Looks to Align Load Forecasting, Tx Planning.)
The study found that energy efficiency provides the most significant magnitude of demand and energy savings resources.
“Energy efficiency in our view will continue to play a critical role in demand-side management,” Daukoru said. “EE is quite significant in terms of savings.”
Daukoru predicted that residential behavioral programs that encourage improvements in energy efficiency and home weatherization programs will continue to gain popularity within MISO. New federal lighting standards in 2020 and efficiency upgrades to existing buildings and equipment will also play a role in energy efficiency, the study found.
Distributed resources, driven by rooftop solar, will impact peak loads. MISO will continue to see rapid adoption of distributed generation with the rapidly declining cost of residential rooftop solar, Daukoru said. Distributed wind, on the other hand, is expected to remain prohibitively expensive for most residents.
Combined heat and power is already at high saturation point in parts of MISO, including Texas, Louisiana and Michigan. Expensive installation costs limit more adoption, Daukoru said.
The study found that MISO has room for “significant” DR opportunities, despite “several mature” programs in certain states. AEG expects residents in the footprint to participate in expanded direct load control programs within two decades, installing connected thermostats and smart water heaters that can be automated to turn off in response to reliability threats or energy price spikes.
AEG said utility-led dynamic pricing programs will be emerging only “from isolated pilots.”
“There is enormous potential for dynamic pricing, but it requires political will,” said AEG Senior Vice President Ingrid Rohmund.
Customized Energy Solutions’ David Sapper asked if AEG considered how the federal push to value resilience might affect the adoption of demand-side management in MISO.
“I have not given that much thought,” Daukoru said. “That was not accounted for in our analysis.”
Daukoru added that demand-side resources could be valuable to resilience given their ability to deliver energy savings and render loads more flexible.
AEG’s study will be finalized in June and included in the MTEP studies. MISO and AEG will continue to refine study assumptions for behind-the-meter participation and the potential impact of electric vehicle adoption over the next few weeks.
Moments after stakeholders approved the charter for the Energy Price Formation Senior Task Force (EPFSTF) without comment at last week’s Markets and Reliability Committee, PJM moved to revise the issue charge on which it’s based to also address concerns about insufficient secondary reserves.
“The topic of potential new reserve products has been raised in our discussion around energy price formation,” PJM’s Dave Anders explained. “We realized that it would really be beneficial for the Operating Committee to provide some input to those considerations around reserve products.”
The EPFSTF decided that the first step is for the OC to define the “reliability-related aspects” that need to be addressed so they can be incorporated into the market-structure changes the task force is contemplating. To include that, they recommended adding a “key work activity” to the task force’s issue charge and assigning it to the OC.
The initial proposal tasked the OC with identifying the factors a 30-minute real-time product should have and how it would interact with synchronized reserves. However, stakeholders — led by the Independent Market Monitor Joe Bowring — eventually replaced that with a more generalized task to analyze secondary reserves and any “interdependencies” it would have with primary reserves.
Calpine’s David “Scarp” Scarpignato asked that the discussion include any reserve requirement changes that would interact with the reliability assessment and commitment (RAC) process and the day-ahead and real-time markets. Anders said the language had been added to the EPFSTF’s charter.
PJM’s Dave Souder said the reserve considerations are an extension of the gas-electric coordination and pipeline-contingency initiative that he has been leading since late last year. He said he plans to “set aside an hour” at each monthly OC meeting to create a recommendation on the appropriate inputs and what revisions might need to happen in real time. (See “Resilience Update,” PJM Operating Committee Briefs: March 6, 2018.)
“I think it’s within our purview at the OC to see if we have reliability need, and we can recommend that the product be developed, but how that’s developed would be through the [EPFSTF],” Souder said. “There may be times where the gas contingency is larger than our largest 30-minute requirement. Under those conditions, we may need to ensure we have sufficient 30-minute reserves.”
Stakeholders endorsed the second phase of an initiative with MISO to address overlapping congestion. The first phase was filed with FERC in December, but PJM had to respond to a deficiency notice in January and it was not approved by the proposed March 1 implementation date. With the endorsement of the second phase, staff hope that both phases can be approved for implementation by June 1, PJM’s Tim Horger said.
The proposal addresses the potential for pseudo-tied resources to pay twice for congestion charges as their energy crosses the market borders. The first phase eliminated the charges, and the second phase allows hedging of potential congestion charges through day-ahead transactions, auction revenue rights and financial transmission rights. Owners will be refunded or charged for deviations between day-ahead submittals and real-time operations. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.)
Solution to congestion overlap | PJM
Generation Transfer
Concerns with PJM’s proposed deadlines for notifying the RTO of generation transfers are being ironed out, PJM’s Rebecca Stadelmeyer said. A vote on the issue was deferred at February’s MRC meeting because some generation owners felt PJM’s timeline was too onerous. (See “Generators Hesitate on Ownership Transfer Rules,” PJM Markets and Reliability Committee Briefs: Feb. 22, 2018.)
Stadelmeyer said stakeholders have sent in redlines, and a group of generation owners, coordinated by GT Power Group’s Dave Pratzon, are engaged on the issue.
“It definitely appears PJM and the generator owners are coming to a mutual understanding,” she said.
The group has another call scheduled for March 28.
Stakeholders Approve Variety of Actions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 1: Control Center and Data Exchange Requirements. The revisions were developed as part of a periodic review and encompass real-time system monitoring and communication requirements, including external resources.
Manual 14A: New Services Request Process and Manual 14E: Additional Information for Upgrade and Transmission Interconnection Projects. Revisions developed to implement previously approved revisions to PJM’s transmission service and upgrade requests. (See “Transmission Issues,” PJM PC/TEAC Briefs: Feb. 8, 2018.)
Manual 37: Reliability Coordination. Revisions developed to clarify language and simplify references to NERC standards.
Members Committee
Overlapping Congestion Endorsed Through Consent Agenda
The Tariff and OA revisions to address the overlapping congestion issue were added to the consent agenda, which stakeholders endorsed by acclamation without comment.
The issue was brought for a vote at both committees on the same day because stakeholders agreed to that arrangement when they deferred the vote at February’s MRC. The dual vote allows PJM to maintain its preferred timeline for filing and implementation.
Monitor Recommends Redrawing Market Lines
Monitor Bowring believes the lines that define regional price separations within the RTO in the capacity market are antiquated and that price separation should be dynamic based on the actual characteristics of the market. He discussed the recommendation while briefing members on the 2017 State of the Market report. (See IMM Report Says PJM Prices Sufficient.)
Bowring’s thoughts on redefining locational deliverability areas (LDAs) in the capacity market came in response to a question from Ruth Ann Price of the Delaware Division of the Public Advocate. She had asked him to expound on his recommendation that LDA definitions be dynamic and market based.
“We think that it should be based on a nodal definition so that the price separation is a function of the actual transmission characteristics of the system as well as the relative offer prices of the system,” Bowring said. “LDAs are arbitrary lines … [that are] almost without exception the old-fashioned transmission zones. There’s no reason to believe that those are the right way to have prices separate.”
He said the first step to addressing the issue is modeling every LDA to see if any prices separate. He said he hasn’t done the analysis to determine how many LDAs would price separately, but that he would investigate it.
Bowring said another “work in progress” is examining the nature of the competition to provide transmission upgrades and expansions.
FERC on Friday accepted ISO-NE’s request to terminate 11 MW of the capacity supply obligations (CSOs) for a Maine wind farm that delayed its commercial operation and reduced its planned output.
However, FERC said the RTO was wrong in executing the termination before commission approval, delaying the effective date to March 24 (ER18-704).
The RTO filed its termination request on Jan. 23, asserting that developer Blue Sky West had delayed its original 2015 commercial operation date multiple times before achieving partial operation in March 2017.
Bingham Wind Project | NovatusEnergy
In Forward Capacity Auction 6, the Bingham wind project in Somerset and Piscataquis counties won CSOs of 42.3 MW for summer and 87.3 for winter, beginning with the 2015/16 capacity commitment periods (CCP).
The company agreed to voluntarily relinquish about 20 MW of summer and 22 MW of winter CSOs based on its decision to reduce the number of turbines in the project and change the turbines to a design with a lower capacity. But the company disputed ISO-NE’s demand to reduce the summer CSO by 10.3 MW and winter by 0.79 MW following the RTO’s audits of the farm’s actual output.
The RTO filed to terminate immediately that portion of the resource’s CSOs in the 2017/18 through 2020/21 capacity years, and to adjust the facility’s qualified capacity for future capacity auctions.
Blue Sky West filed an emergency motion asking the commission to order reinstatement of the disputed CSOs, arguing the grid operator must receive commission approval before the termination could become effective. On Feb. 2, 2018, the commission granted the motion, ruling that the termination could not be made effective prior to March 24, the end of the 60-day notice period.
The RTO’s Tariff allows termination of CSOs if a new facility covers its capacity shortfalls through bilateral trades or the reconfiguration auctions for two capacity commitment periods. The developer claimed the audits should not be justification for reducing the CSOs because they are not listed as “critical path” schedule requirements in the RTO’s Tariff.
The commission disagreed, saying, “Neither achieving ‘commercial operation’ nor fulfilling ‘critical path schedule milestones’ precludes ISO-NE from terminating a resource’s CSO under” the Tariff.
The RTO said that if it did not perform terminations in advance of the FCA, a resource that is not fulfilling its CSO could obtain one for another year and potentially suppress auction clearing prices and provide the region with phantom megawatts that cannot produce energy.
FERC agreed with the grid operator’s right to manage its capacity resources but departed with it regarding its termination rights. “While the [Tariff] language is ambiguous, we find that under a sensible reading of the provision and as a practical matter, [a Federal Power Act] Section 205 filing is necessary to obtain a ‘commission ruling’ on any aspect of an involuntary termination,” the commission said.
Requiring such approval of involuntary terminations “should not impede the grid operator’s administration of the Forward Capacity Auction,” FERC said.
“Given that the [FCA] takes place in February of each year, the [RTO] usually submits termination filing in October of the prior year, giving the commission enough time to rule on the termination filing before the Forward Capacity Auction is conducted,” the commission said.
Could PJM’s Artificial Island project get any more complicated? Apparently, yes.
A Delaware demand-side group has asked the PJM Board of Managers to again suspend the project because of announcements from Exelon and Public Service Enterprise Group that that they will cancel future capital investments at the two Salem nuclear units they co-own and shut the plants down if New Jersey doesn’t provide them $300 million annually in subsidies to keep the plants open. (See NJ Lawmakers Advance Latest Nuke Subsidy Bills.)
The project was developed to address transmission stability problems at the Hope Creek and Salem nuclear units in southern New Jersey and allow them to operate at full power without a book-size compilation of operating constraints.
The Hope Creek and Salem nuclear units on Artificial Island in southern New Jersey | BHI Energy
PJM’s first competitive solicitation under Order 1000, the Artificial Island project has long been mired in controversy. In June, the RTO announced several cost allocation alternatives that would shift much of the $280 million price tag from Delaware ratepayers to those in New Jersey and Pennsylvania. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)
The Board of Managers had two months earlier restarted the project and ordered the analysis of alternative allocation methods. It also re-awarded the project to LS Power, which was selected when the board approved the project in July 2015. Complaints over mounting costs, scope changes and a cost allocation that Delaware felt was unduly burdensome caused the board to suspend it in August 2016.
But the announcements from Exelon and PSEG in February cast doubt over whether the plants are long for this world. PSEG said it might also cancel spending on the Hope Creek reactor, which shares Artificial Island with the Salem units.
“These actions call into question the long-term operational viability of the Salem and Hope Creek plants,” wrote Michael K. Messer, president of the Delaware Energy Users Group, noting that Delaware consumers stand to pay “a significant share” of the project’s cost. “The cost increase is at a level that will severely impair the competitiveness of Delaware businesses. This scenario becomes far worse should the driving reason for the transmission project, Salem and Hope Creek reliability, cease to exist.”
He asked the board to consider whether the project is necessary or if its scope changes if any or all of the plants close and whether the project’s timeline should be delayed “to minimize expenditures until a long-term commitment is established for the Salem and Hope Creek plants.” LS Power’s award has an in-service date of June 1, 2020.
PJM’s Dave Anders, who oversees stakeholder relations, said it’s unclear what the board’s response will be. “At this point, I do not have a sense for when/if there will be a formal response,” he said in an email.
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.”
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 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.)
