Stakeholders gave MISO strong marks in this year’s annual customer opinion survey, but they still see room for improvement, especially with the interconnection queue, outage planning and transmission cost allocation.
MISO sent surveys to more than 457 companies and reported 24% participation, better than its historic 16 to 17% response rate.
“This is the best response rate we’ve ever gotten,” MISO Executive Director of External Affairs Kari Bennett said during an Oct. 24 call hosted by the Human Resource Committee of the Board of Directors.
Nearly 90% of respondents reported an overall satisfaction with MISO, the highest percentage in five years, while 83% said the RTO’s market rules and processes are transparent, the highest rating in four years. MISO has commissioned a survey since 2005 and scored an average 80% or better since 2012.
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Bennett said stakeholders identified four areas of concern: MISO’s generation and transmission outage coordination process, transmission cost allocation, the lengthy interconnection process and quality of the search function on the website.
Bennett said the areas singled out for improvement were “not surprising,” as all the stakeholder-flagged issues have been discussed before in MISO public meetings.
Last month, outage-related congestion, combined with hot temperatures, drove real-time revenue sufficiency guarantee payments above $13 million, nearly doubling last year’s monthly total. Stakeholders and MISO officials in September agreed with the Independent Market Monitor that outages need to be more carefully scheduled. (See MISO in Harmony with IMM State of the Market Report.)
MISO is beta testing a new website design that will launch in December, Bennett said. “People right now say it’s easier to search Google [to find MISO information] than use our search function.”
Bennett also expressed in interest in how MISO’s new interconnection queue process will fare in next year’s survey, after being in place longer than a year. This year, stakeholders viewed the interconnection process as too long to be effective.
Survey respondents also asked for added benefit metrics aside from the adjusted production costs that MISO uses to mete out costs for the RTO’s market efficiency and multi-value projects, an issue the RTO and stakeholders will tackle in 2018.
MISO is developing responses and action plans based on survey responses, Bennett said.
MISO Advisory Committee members decided there was nothing amiss in the stakeholder debate that ultimately shut down the possibility of creating a cost recovery mechanism for customer-funded transmission upgrades.
But supporters of the proposal contend the idea didn’t receive fair consideration.
During an Oct. 25 Advisory Committee call, Bruce Grabow, an attorney representing EDF Renewables, argued that MISO’s Regional Expansion Criteria and Benefits Working Group (RECBWG) did not understand the proposal, nor allow full debate before rejecting it this summer after deciding that after-the-fact cost allocation would be too complex to introduce.
“There wasn’t any discussion on whether this is really needed,” he added.
Grabow said the joint proposal — which would allow simple cost recovery of customer-funded upgrades from other transmission users directly benefiting from them — from EDF and Wind on the Wires (WOW) could be a “win-win” because it would initiate construction of needed sub-345-kV projects that would be otherwise overlooked in MISO’s annual Transmission Expansion Plan. (See Participant-funded Projects Get 2nd Shot at MISO Cost Recovery.)
But Advisory Committee members held that the RECBWG performed its due diligence before voting 15-4 to deny EDF and WOW another round of presentations on the topic. Voting in favor were Adam Sokolski and Mark Volpe of MISO’s Independent Power Producers sector, as well as WOW’s Beth Soholt, of the Environmental sector, and Adam McKinnie of the State Regulatory Authorities sector. Two state regulatory representatives ― Ted Thomas and Hwikwon Ham ― abstained from the vote.
“It’s not clear at all to me what … the shortcoming of process at the RECBWG was,” Entergy’s Matt Brown said. He pointed out that EDF and WOW were granted presentation time, a feedback gathering phase and follow-up at a later RECBWG meeting.
“[They’re saying] if only we understood the points, we’d agree. I’d argue that we understand and don’t agree. I don’t think what we have here is a misunderstanding of the proposal, but a disagreement of the merits of the proposal,” Brown said.
Steering Committee Chair Tia Elliott said she didn’t want similar Advisory Committee petitions cropping up whenever stakeholders were disappointed with the reception of their proposals. She maintained that the issue received proper consideration according to MISO’s stakeholder process, even if EDF and WOW didn’t like the outcome.
The discussion was a follow-up of one that took place at the last Advisory Committee meeting Sept. 20. “Although I think the proposal has some merits, the question is whether the stakeholder process was followed,” Kevin Murray, executive director of Industrial Energy Users-Ohio, had said then.
Soholt said EDF does not believe it was given sufficient time for stakeholders to explore the cost recovery proposal. “Going to the heart of the issue, it really goes to heavily congested areas and bringing in transmission,” said Soholt, who added that MISO has a problem in some cases luring transmission developers to build lines where they are most needed. She said the “narrow focus” of the proposal provides a solution.
“It looks like there’s just some dissatisfaction with the outcome of the process rather than any failure of the process,” Brown said. He also added that he disagreed with EDF’s assertion that MISO lacks a process for in identifying sub-345-kV projects.
Xcel Energy’s Carolyn Wetterlin, chair of the RECBWG, said the issue was given a fair hearing in the working group.
“I know there are times I have to work the agenda and cut discussion short, but I don’t recall that that was the case with this presentation,” Wetterlin said.
Murray said EDF and WOW are still free to lobby their case in front of MISO officials or file a complaint at FERC.
Avangrid third-quarter earnings fell 9% to $99 million on weaker-than-expected wind production, which the company said was partially offset with improved operations elsewhere. Year-to-date profits were still up 8%.
Avangrid CEO James P. Torgerson
“The third quarter historically sees the least amount of production from wind resources, and this third quarter was even below that,” CEO James P. Torgerson said during an Oct. 24 earnings call. “We have been implementing best practices and cost management across all of our business, so the new rate plans in Networks and the cost management we’ve implemented helped to offset the low wind resource, which was really 5% below our normal.”
The company’s two primary lines of business are Avangrid Networks, comprising eight electric and natural gas utilities in New York and New England, and Avangrid Renewables, which operates nearly 7 GW of mostly wind power in 23 states.
State Regulatory Update
During the call, Torgerson addressed a recent move by Connecticut regulators to investigate Avangrid and Eversource Energy for potentially manipulating natural gas prices in the state between 2013 and 2016 (17-10-31). The state’s Public Utilities Regulatory Authority (PURA) is working off allegations set out in a report issued earlier this month by university researchers and the Environmental Defense Fund, who contended the companies unjustly reaped gains of about $3.6 billion over the period.
In Connecticut, “we have an obligation to supply gas, and we also have a very strict code of conduct for our employees,” Torgerson said. “We will be looking to make sure we’re following all the rules, which I believe we are, and we’ll cooperate with PURA in their review.”
In New York, Avangrid subsidiaries New York State Electric and Gas and Rochester Gas & Electric next year expect to implement a collaborative earnings adjustment mechanism designed to facilitate interconnection of distributed energy resources, which Torgerson said “provides incentives that would actually increase the [return on equity] if targets are achieved.” Regulatory discussions on the two utilities’ joint proposals for advanced metering infrastructure and a distributed system implementation plan have been deferred to late this year, with decisions expected by June 2018.
Federal Scene
Torgerson noted that FERC earlier this month rejected a bid by New England transmission owners — including Avangrid’s Central Maine Power — to increase their ROEs to the previous level of 11.14% after a federal appeals court earlier this year temporarily vacated a 2014 commission order that reduced the ROE to 10.57%. The commission said it would address the actual rate in a later remand order (ER15-414, EL11-66). (See FERC Rejects New England Tx Owners on ROE.)
“[FERC] really didn’t, in my mind, get to the merits of the ROE,” Torgerson said, contending the commission seemed more concerned about the “whiplash” of moving the rates back and forth.
Transmission Projects, Wind and PPAs
Three-year rate plans in Connecticut and New York, along with the FERC formula rate, are giving Avangrid better than 80% certainty, Torgerson said.
Avangrid looks to continue developing onshore renewables and transmission projects for long-term growth, “some of it through the Massachusetts Clean Energy [request for proposals] and the New York transmission renewables solicitations, but also with the offshore wind RFP that will be in Massachusetts,” he said.
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For the Massachusetts solicitation, CMP in July partnered with Hydro-Québec to bid the New England Clean Energy Connect, a 145-mile, 320-kV HVDC line that would carry 1,200 MW of hydro and wind energy from Canada to Maine. The company also teamed with NextEra Energy on the Maine Clean Power Connection, a new 345-kV connection from western Maine to the New England grid with capacity options of 460 to 1,110 MW, allowing varying combinations of wind, solar and storage facilities in eastern Canada and western Maine. (See Tx Developers Pitch Mass. Clean Energy Bids.)
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Avangrid continued to sign on new wholesale customers during the third quarter, executing a power purchase agreement for 86 MW, “adding to the 401 MW of PPAs previously secured and announced in 2017 — all with 100% production tax credits,” added Torgerson. “Construction on approximately 800 MW of wind and solar projects is well underway, of which 590 MW will be operational by year-end 2017.”
He added that the market for PPAs has become more competitive this year as customers look not only for renewable energy, but renewables at a low cost.
Wrapping up a three-year effort, the Illinois Commerce Commission last week issued strengthened consumer protections against the marketing practices of alternative retail electric suppliers.
The commission’s Oct. 19 order (15-0512) requires retail suppliers to provide customers with a disclosure statement that details whether electricity rates are fixed or variable; the price per kilowatt-hour and the number of months that price is guaranteed; all monthly fees and any early termination fees; and whether the contract renews automatically.
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The ICC also ordered suppliers to send customers identical disclosure statements about automatic renewals via mail and one other form of communication. Termination fees cannot exceed $50 for residential customers and $150 for small commercial retail customers under the new provisions.
The new rules also require retail suppliers to retain for two years any copies of customer contracts and a recording of telemarketing solicitations that result in enrollment. Suppliers must also make more detailed disclosures about renewable energy offers and cannot describe plans as “green” unless they go beyond Illinois’ renewable portfolio standard.
Retail suppliers are also prohibited from using the name and logo of any Illinois public utilities in their electric power and energy service offers. Any supplier that is an affiliate of a public utility and starting doing business as of Jan. 1, 2016, can continue to use that utility’s name and identifying information in marketing offers outside the utility’s service territory.
Under the rules, all customers now have the right to cancel a contract with a retail supplier within 10 business days of their first bill.
The ICC said it was prompted to tighten the rules following the spike in electricity prices during the 2013-2014 “polar vortex” winter, when its consumer services division received “a sharp increase in public complaints about the marketing practices of certain retail electric suppliers.”
“The rules will ensure that consumers have information about electricity supplier options that enable them to compare offers and utility plans, and make better-informed decisions. The new marketing guidelines also provide regulators with improved enforcement mechanisms, and require suppliers to take improved verification and quality control measures,” the ICC said.
Chairman Brien Sheahan said the changes are “a major victory for the public interest and all stakeholders by ensuring consumers have clear information to make good choices regarding their energy needs.”
Executive Director Cholly Smith said the new rules will protect customers from “bad actors” while “fostering a robust competitive market.” He added that the ICC will now work with stakeholders and industry officials to implement the rules uniformly.
While reducing greenhouse gas emissions and increasing the use of renewable resources will remain top priorities for California for the foreseeable future, a biennial policy report by state energy planners has some environmentalists calling for even more aggressive pivots — such as phasing out utility-scale renewable projects.
The California Energy Commission is taking comments on its 2017 Integrated Energy Policy Report (IEPR) through Nov. 10. The current version released earlier this month lists many policy goals, including doubling energy efficiency savings, achieving 50% renewables by 2030, advancing the electrification of the transportation system and addressing barriers for low-income consumers in reaping the benefits of cleaner energy. The nearly 500-page document also discusses new technologies, transmission-scale planning, natural gas and climate issues, among other topics.
Another key element in the state’s grid planning process is Renewable Energy Transmission Initiative (RETI) 2.0, which recognizes that greater reliance on renewable energy may require additional transmission or infrastructure improvements to achieve renewable energy goals and reduce emissions. The initiative is meant to facilitate electric transmission coordination and planning, and involves the CEC, the California Public Utilities Commission and CAISO.
RETI’s “landscape-scale” planning approach, included as a component of the IEPR, considers environmental conservation and other land uses, tribal cultural resources and stakeholder concerns to help identify the best areas for potential electric infrastructure development.
But some environmentalists calling into a Monday CEC workshop questioned the landscape-scale approach, saying that utility-scale generation, even for renewables, is an outdated concept. Planning agencies are “clinging to the outmoded notion that thousands of acres of desert land are needed for utility-scale projects,” with landscape-level planning leading the way, said Steve Mills, of the environmental group Alliance for Desert Preservation.
“Why do the energy agencies continue to reach for this old, familiar tool, which is a vestige of the outmoded centralized planning regime, when the IEPR makes it clear that it is time to throw away the whole toolbox?” Mills asked. He said the focus should be on energy efficiency, storage, distributed generation and other new technologies, not new utility-scale projects.
But Kate Kelly of Defenders of Wildlife said that the landscape-scale approach is the best one, and is “the tool to make informed decisions as when, where and how to site large-scale renewable energy development.”
Kelly said that while a move to distributed resources is desired, “That is not going to happen today, tomorrow or next week, and meanwhile we have to plan intelligently for renewable energy in a variety of places.”
Reducing GHG emissions is not a new policy in California, but rapid changes in technology and resources are changing the way state planners must approach the electricity grid. The report notes the customer load currently served by investor-owned utilities could drop by 85% in the next 10 years. Chief among the new technological issues are renewable resource variability, the effect of DG on grid operations, and the impact of energy storage and electric vehicles.
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The state reduced its CO2 output by 1.5 million metric tons between 2004 and 2014, a 10% decline. The electricity sector produces about 19% of California’s GHG, while the transportation sector emits 40%. The state accounts for about 1% of global GHG emissions.
The CEC is the primary policy-setting and planning energy agency in the state, and is responsible for certification and compliance of thermal power plants 50 MW and larger, including all project-related facilities.
NRG Energy recently indicated it will pull plans for a proposed 262-MW natural gas plant in Oxnard after Commissioners Janea Scott and Karen Douglas recommended the project not be approved. (See NRG Signals Pull-out on Proposed Puente Plant.) Distributed energy resources are alternatively planned to deal with the expected loss of generation in the area due to state rules prohibiting the use of once-through cooling at power plants.
Earlier this year, CEC Chair Robert Weisenmiller, who is quoted in the IEPR as desiring “a portfolio of solutions,” recommended permanent closure of the Aliso Canyon natural gas storage facility, saying it could be replaced with renewable energy, energy efficiency, electric storage and other tools. (See California Officials: Aliso Canyon Safe to Open.)
A federal appellate judge Friday stayed a New York Public Service Commission order that prohibits most energy service companies (ESCOs) from serving low-income customers (17-3361).
Judge José A. Cabranes, of the 2nd U.S. Circuit Court of Appeals, issued the stay while the court considers an appeal in a lawsuit filed by an anonymous ESCO customer who participates in New York’s energy assistance program. A federal district court had previously denied a stay and injunction in that suit, which alleges that the PSC’s order denies energy assistance program participants equal protection under the law and interferes with their right to contract. Cabranes referred the plaintiff’s motion to the next available three-judge panel.
In its brief with the court, the PSC opposed the appeal, contending that it was exercising its authority to set just and reasonable electricity rates and protect customers from overcharges.
Thurgood Marshall U.S. Courthouse | elec / 123RF Stock Photo
While the commission’s December 2016 order banned most ESCOs from serving low-income customers, it left open the possibility of issuing waivers for any ESCO that promised to offer bill savings or guarantee benefits to those customers. A state appellate court earlier this year issued a temporary restraining order on the ESCO ban, which was subsequently lifted by the Albany County Supreme Court. (See Court Blocks NYPSC Order Barring ESCO Contracts.)
Right to Choose?
The plaintiff’s attorney, William J. Dreyer, argued in his brief that his client would be harmed by being forcibly “enrolled in energy programs they do not want and de-enrolled from programs they voluntarily chose.” Furthermore, the suit alleged that the ESCO restrictions could put “low-income New Yorkers in a position where they may no longer be able to pay their electric and gas bills,” and that disclosure of customers’ income levels would violate their privacy rights.
The National Energy Marketers Association reacted to news of the stay with a statement applauding “the 2nd Circuit for stopping the PSC from discriminating against low-income New Yorkers until the facts can be properly litigated before a federal three-judge panel.”
Cabranes’ ruling came one day after the commission acted on allegations of deceptive sales and marketing practices by Brooklyn-based MPower Energy, giving the company seven days to show why it should be allowed to serve low-income customers. The commission on Thursday also allowed three ESCOs to continue serving low-income customers while denying waiver requests for four other ESCOs. (See New York PSC Adopts DER Rules, Sanctions ESCOs.)
MISO is confronting a pair of conflicting motions as some stakeholders push back on including a Texas project in the RTO’s 2017 transmission plan.
One motion — backed by MISO itself — asks the RTO’s Planning Advisory Committee to recommend that the Board of Directors approve the current draft of the 2017 Transmission Expansion Plan, which includes a new $129.7 million, 500-kV line and substation in southeastern Texas. The motion requires PAC sectors to acknowledge that they “have provided written comments and suggestions for improvement of MISO’s planning activities to be included in future planning processes” and be willing to present their stances at a future PAC or board meeting.
But MISO’s Transmission Owners sector submitted an alternative motion calling into question the decision process and cost estimate behind the Texas project, MTEP 17’s only market efficiency project, which is meant to alleviate constraints in the West of the Atchafalaya Basin area straddling Texas and Louisiana. (See Late Changes to Texas Project Frustrate MISO Participants.) The motion recommends the plan’s project list but delays the Texas project “until the time that MISO can adequately address the cost estimation and other concerns that have been raised.”
A number of TOs declined to sign on to the sector motion, including Ameren, East Texas Electric Cooperative, Indianapolis Power and Light, ITC Holdings, MidAmerican Energy, Northern Indiana Public Service Co., Prairie Power, Wabash Valley Power Association and City Water Light & Power.
Vote Looming
PAC sectors will vote on the measures in an email ballot after having to temporarily suspend Robert’s Rules of Order during an Oct. 18 conference in order to simultaneously consider the conflicting motions. Chair Cynthia Crane said that a tie vote would likely prompt the committee to hold an emergency meeting to further discuss its MTEP recommendation.
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The System Planning Committee of the Board of Directors will review MISO’s final MTEP 17 draft report in November regardless of whether the PAC recommends the plan in full. The RTO has added 10 projects valued at an additional $1 million since a first draft of the project list was released last month. (See MTEP 17 Proposal: 343 New Transmission Projects at $2.6B.) MTEP 17 now contains 353 recommended transmission projects at $2.7 billion. Of those, 70% are projects driven by local needs and not subject to cost allocation, and 22% are projects needed to maintain baseline reliability.
Back and Forth
At Wednesday’s PAC meeting, MISO project manager David Lucian said the RTO stands by its recommendation of the Texas project, which currently shows a 1.35:1 benefit-cost ratio. He also noted the RTO does not think Hurricane Harvey reconstruction efforts will hamper construction as Xcel Energy has suggested.
In written comments to MISO, Xcel said it had “concerns that have not been, or haven’t had adequate time to be addressed before recommendation,” including a company cost estimate that aligns with MISO’s estimate under minimum project requirements. Xcel concluded that it made sense to delay project approval until the June board meeting in order to give the RTO time to double-check its estimate.
The company said that while it didn’t doubt the Texas project’s economic benefits, it had lingering concerns that MISO had changed the original project scope and MTEP futures weighting midway through the MTEP 17 process, moves that could be perceived as “favoritism.” MISO adjusted the futures weighting for a MISO South study after region’s transmission owners and state regulators asked for less emphasis on a carbon-regulated future. (See MISO Changes MTEP Futures Weighting for South.)
NRG Energy’s Tia Elliott asked why concerns with the projects weren’t brought up sooner. “To delay this project would set very dangerous precedent,” she said.
Texas Public Utility Commissioner Ken Anderson warned against holding up transmission construction when the state clearly needs the project.
“I will say this now: Texas has been waiting five years for any tangible benefit out of the MISO planning process,” Anderson said. “A delay won’t be viewed favorably by the stakeholders here. It will call into question the value proposition. This is a very important project for the state and southeastern Texas.”
Some stakeholders argued that endorsing MTEP 17 in its current form would allow MISO to recommend a flawed project the board. Other stakeholders said the possible market efficiency project, whether competitively bid or not, would be subject to cost reporting to MISO, another safety mechanism in the cost estimate process.
“Notably, I think the cost estimate has changed with each presentation,” Entergy’s Yarrow Etheredge said. She added that the PAC has not been able to provide feedback on the final project estimate.
Counting the Cost Estimates
MISO staff have said the $129.7 million estimate has not changed since early August. In July, the RTO provided a $137.6 million estimate, which included an expansion of two existing substations instead of construction of a new substation. But the project and cost estimate changed after local TO Entergy increased a flowgate rating in March, putting the project below the required 1.25:1 benefit-cost ratio, a detail MISO revealed to stakeholders in July when it was forced to alter the project. At the time, MISO presented stakeholders with possible project alternatives and collected stakeholder opinion before settling on the most recent iteration of the project. (See Late Changes to Texas Project Frustrate MISO Participants.)
GridLiance’s Paul Jett said MISO “clearly followed the process.” He pointed out the altered project’s cost benefit has been consistently above the required 1.25:1 ratio, and that differences between scoping-level and final cost estimates are natural.
“It isn’t new to use scoping-level cost estimates,” he said. “If this really is an issue, MISO’s board will decide in their approval,” he said.
Jett also said it isn’t within MISO’s purview to delay projects based on the possibility of states enacting right of first refusal (ROFR) laws, another argument raised by Xcel. “Ultimately, if there’s a ROFR in Texas, then the project won’t be completely bid,” he said.
Brian Pederson, MISO senior manager of competitive transmission administration, said that next year the RTO will continue to host discussions on how to improve planning-level and scoping-level cost estimates.
MISO on Wednesday revealed plans to rely more heavily on its own load forecasting to support long-term transmission planning, instead of primarily drawing on a combination of forecasts provided by load-serving entities.
Stakeholders were unenthusiastic about the idea, which would elevate the role of an independent long-term forecast provided by Purdue University’s State Utility Forecasting Group. MISO says stakeholder input will influence a second version of the proposal presented in December.
Under its existing planning process, MISO draws on an aggregate of about 150 LSE resource adequacy forecasts submitted under Tariff Module E to inform economic studies for its annual Transmission Expansion Plan. The LSEs currently provide 24 months of load forecasts and produce additional predictions for eight seasonal peaks to create a 10-year forecast. The RTO uses the data to extrapolate another 10 years into the future to fit its 20-year planning horizon.
MISO planning horizon with use of an independent load forecast | MISO
MISO also consults the Purdue forecast — which relies on 20-year forecasts produced by states — but only to draw comparisons with the LSEs’ predicted growth rates. The RTO earlier this year said it was investigating ways to improve that independent forecast. (See Dynegy: MISO LSE Load Forecasts Require Tune-up.)
Blending Forecasts
Konidena | MISO
MISO is now proposing to blend the LSE and Purdue forecasts, adviser Rao Konidena said during an Oct. 18 Planning Advisory Committee meeting. Under the new approach, it would no longer extrapolate the LSEs’ predictions, instead relying on Purdue’s forecasts to predict growth rates for the second half of the planning horizon.
The RTO said it planned to use the independent forecast in part because it does not know what economic drivers underpin the LSEs’ forecasts or whether the LSEs include state renewable or efficiency mandates and emissions goals. Use of both forecasting methods will lead to “better evaluation of impacts of variations in assumed penetration levels of demand response resources, energy efficiency, and distributed energy resources,” it said.
Adam McKinnie, an economist with the Missouri Public Service Commission, asked whether MISO had faith that utilities were making thoroughly researched predictions of future load growth with their state-submitted resource adequacy plans.
“Do you ask utilities for the drivers of economic growth behind their load forecasts?” McKinnie asked. “You seem to be taking shots at the Module E forecasting,” he added.
“All I’m saying is that I don’t know what goes into the economic drivers,” Konidena responded.
Minnesota Public Utilities Commission staff member Hwikwon Ham wondered if MISO thinks it’s overbuilding or underbuilding transmission based on the use of its existing Module E process. “You have to show that there is a better process,” he said.
Konidena stressed that MISO only wants to use a forecast that’s designed with the next 20 years in mind, rather than simply extrapolating a 10-year forecast. Use of two separate forecasts for the same planning studies will lower the risk of load forecast miscalculations being compounded into “poor year-out projections,” he said. MISO has also noted that Applied Energy Group predicts that demand-side management programs will hit a saturation point in a decade, something the RTO will fail to include in its growth rate if it simply extrapolates aggregated utility forecasts.
Real Projects, Real Money
Indianapolis Power and Light’s Lin Franks said that the sample coincident peak produced by the blend is too aggressively high: It results in a 150-GW summer coincident peak by 2035, about 5 GW higher than if MISO relied on a Module E extrapolation alone.
“I’m worried about this. This is real money. These are real projects that people are going to want to build, and when we get there, those transmission lines are going to be empty,” Franks said.
WPPI Energy’s Steve Leovy says his company already forecasts 20 years in advance and said he’d be happy to share the longer forecasts with MISO.
Konidena asked stakeholders to submit suggestions on the blended approach by Nov. 17. He said MISO would continue discussing possible expanded used of the independent load forecast at the December PAC meeting.
“You’ve asked if stakeholders have ideas on how to blend the forecasts, to provide them. If we have ideas about not blending them, are you open to that too?” asked Entergy’s Yarrow Etheredge, eliciting laughter.
Konidena said he was open to such suggestions if stakeholders could make a business case for keeping the forecasts separate.
FERC last week rejected a request to rehear its October 2016 ruling requiring MISO to revise its interconnection fees, saying the treatment of external generator Manitoba Hydro was beyond the scope of the order (EL16-12-002, et al.).
The commission had ordered MISO to apply milestone payments equally across all classes of customers, prompting the American Wind Energy Association (AWEA) and Wind on the Wires (WOW) to question how the RTO is processing 3,500 MW of external generation from Manitoba Hydro. The wind advocates claimed sales of Manitoba Hydro’s generation were allowed onto the system under a firm transmission service right, thus circumventing milestone payments.
| Manitoba Hydro
The arrangement equated to preferential treatment, the two said, and asked FERC to determine under what Tariff provision MISO allows Manitoba Hydro sales. They said Exelon’s 3,500 MW of external generation is processed under interconnection service and external network resource interconnection service (E-NRIS), which now requires milestone payments.
In rejecting the rehearing request Thursday, FERC said AWEA and WOW could raise their concerns in MISO’s stakeholder process or submit a fresh complaint to the commission.
The commission said last year’s order centered on which classes of interconnection customers must make milestone payments and is not focused on an “overbroad interpretation” of the “terms and conditions of transmission service in specific transactions involving MISO and Manitoba Hydro, which are outside the scope of this proceeding.”
The October 2016 order stemmed from a complaint by a group of internal MISO generators who contested the RTO’s practice of exempting external generating resources from paying a significant fee levied on any new internal resources seeking to enter the final stage of the interconnection process. (See FERC Orders MISO to Levy Interconnection Fees Equally.) At the outset of the definitive planning phase, new MISO interconnection customers within the footprint must make an M2 milestone payment to fund impact studies and cost analysis. MISO had waived the fee for both new and existing generators outside its footprint under the assumption that those resources have already established interconnection agreements within their own balancing areas.
MISO applied the new rules required by last year’s order to two service agreements: 30 MW of E-NRIS from Exelon’s Fairless Hills Power Plant in Pennsylvania and 2,300 MW of E-NRIS from Exelon’s Byron Nuclear Facility in Illinois (ER17-1000, ER17-1013). FERC accepted both on Thursday.
AWEA and WOW had protested acceptance of the service agreements, arguing that Manitoba’s large external service agreement earned a 147-page reliability study result from MISO, and an analysis of Exelon’s external generation only yielded an 18-page result. The two said the reports contained “insufficient data to confirm MISO’s conclusion that there are no reliability and deliverability violations and that no network upgrades are needed to accommodate the new 2,330 MW.” FERC said the claims were unsubstantiated.
LITTLE ROCK, Ark. — SPP said Thursday it will join the ISO/RTO Council’s (IRC) filing against the Department of Energy’s Notice of Proposed Rulemaking to support struggling coal and nuclear plants, pointing to what staff called “some pretty strong comments.”
“The council does a really good job of laying out why this doesn’t work from an RTO perspective,” SPP General Counsel Paul Suskie told the Strategic Planning Committee.
Initial comments on the NOPR (RM18-1) are due at FERC by Monday as part of a compressed 90-day timeline that has drawn industry-wide criticism. DOE’s proposal requires that generators with 90 days of on-site fuel supply receive “full recovery” of their costs. (See Perry Orders FERC Rescue of Nukes, Coal.)
Suskie told the committee the IRC’s comments contend the timeline is not practical, that FERC is already addressing many of the issues with its price-formation directives and that the DOE proposal will only make the electric markets worse.
“If you’re a plant under the rule, your costs are totally covered,” Suskie said. “Why would you do anything but bid zero into the market? It will drive costs down further and distort markets further.”
Some stakeholders expressed discomfort with signing onto the IRC comments without seeing the language.
“The basic issue here is the subsidy,” countered SPP Board Chair Jim Eckelberger, saying renewable energy tax credits had led to oversupply. “We don’t want to screw up the market even more. We should take a strong stand here.”
Staff will also file comments raising issues and seeking clarifications on the NOPR’s language. Separately, SPP’s Market Monitoring Unit will file its own comments.
In its call for comments, FERC said the NOPR’s scope applies to commission-approved ISOs and RTOs with capacity markets and day-ahead and real-time energy markets. Noting SPP’s lack of a capacity market, Suskie said while it “appears this rule is not applicable to SPP,” staff will work under the assumption that a final FERC rule could apply to the RTO.
Suskie said staff will develop further comments for the reply comments, due Nov. 7. The comments will note SPP operates in states with vertically integrated utilities, where capacity is provided by regulatory constructs, and that the 90-day timeline is “impractical.”
“Staff would recommend additional time to implement if the final rule applies to SPP,” Suskie said, noting staff would have to compile a list of eligible facilities. “Staff is very concerned. … If you read what the intent appears to be, basically any coal or nuclear plant not [rate-based] within an RTO would have to be fully compensated.”
Suskie asked who would determine a plant’s rate of return and cost of capital.
“Traditionally, those things are decided at the commissions, not RTOs,” he said. “How do you enforce a 90-day coal supply? How do you enforce whether a plant complies with environmental regulations?
“If this is applicable to SPP, it would be a big sea change,” Suskie said.
Keith Collins, executive director of SPP’s MMU, said his group agrees with much of what Suskie said, saying the NOPR is “proposing a solution to a problem that’s not well defined.”
The NOPR “doesn’t define the problem well in a way that’s actionable and measurable,” Collins said. “When you actually read the [recent DOE grid study], it says more work needs to be done to value and define resiliency before you come up with solutions. What’s included, what’s excluded … it’s hard to say.”
Like Suskie, Collins said the 90-day timeline does not allow sufficient time to properly consider the NOPR.
“If there’s a question to be raised, it can be answered over time, but we don’t support what’s going on,” he said. “Competitive forces have been part of policy in the energy and electricity markets over the last 25 years. It will provide new technologies, batteries and the like, that will improve the resiliency for the grid in ways we’re not aware of today.
“What the Energy Policy Act of 1992 did was promote competitive markets and open access,” Collins said. “If someone can provide power cheaper than someone else, they should be able to do that. If I built a plant a while ago that’s unprofitable, that’s a signal. Resources are indicating they are not being able to recover their costs. We see the consequences of a policy like this with our negative pricing.”
