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.
| Illinois Commerce Commission
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.”
FERC on Thursday ordered Federal Power Act Section 206 proceedings for five SPP transmission owners seeking to develop projects under the RTO’s Order 1000 competitive solicitation process.
The commission accepted revised formula rate templates and protocols for ATX Southwest (ER15-1809-001, EL18-12); Transource Kansas (ER15-958-003, EL18-13, ER15-958-004); Midwest Power Transmission Arkansas (ER15-2236-001, EL18-14); and Kanstar Transmission (ER15-2237-001, EL18-15, ER15-2237-003). But the commission ordered 206 proceedings because the companies’ filings did not provide for inclusion in their annual updates sufficient descriptions and justifications for the allocation of costs between them and their affiliates.
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FERC also set a 206 proceeding for South Central MCN, saying its revised protocols “attempt to define the scope of future filings” under FPA Section 205 (ER15-2594-003, ER17-953, EL18-16). The commission said South Central had provided an adequate description of its cost allocation methodology as required by an order in October 2015.
FERC said Thursday it will let MISO and SPP work with their stakeholders to determine whether the RTOs should require refund commitments from their transmission-owning nonpublic utility members.
In agreeing to hold in abeyance Section 206 proceedings on the issue, FERC ordered the RTOs to file proposals by Feb. 28, 2018 (EL16-91, EL16-99). FERC additionally required them to submit reports updating the status of their endeavors by Dec. 15.
The commission, however, rejected claims by MISO, electric cooperatives and nonpublic utilities that it lacked the authority to order changes in the RTOs’ governing documents to require refund commitments. While the Federal Power Act explicitly limits FERC’s jurisdiction to public utilities — a limitation the commission had acknowledged in its July 2016 order initiating the 206 proceedings — the co-ops argued that the commission’s actions amounted to a “work around,” or an indirect order. (See Co-ops, MISO, SPP Urge FERC Restraint with Nonpublic Utilities.)
Rural Electric Cooperative line workers in Oklahoma | Rural Electric Cooperative
Citing federal court rulings, FERC reasserted that once a nonpublic utility’s transmission revenue requirement becomes a component of an RTO’s rates, the commission can “‘analyze and consider the rates of [nonpublic] utilities to the extent that those rates affect jurisdictional transactions’ through their inclusion in the RTO’s rates.”
“The proposal as laid out in the July 2016 order gives nonpublic utility transmission owning members the choice to leave SPP if SPP membership is no longer financially advantageous,” FERC said, using identical language in its order regarding MISO. “The commission is, however, under no obligation to permit nonpublic utilities that choose to become members of SPP and to recover revenues through the SPP Tariff to collect unjust and unreasonable rates through an RTO’s jurisdictional tariff without any consequence.
“We acknowledge … that we lack the statutory authority to order nonpublic utility transmission owners to make refunds. Instead, the refund commitment would serve as a condition precedent for nonpublic utility transmission-owning members to recover revenues through the SPP Tariff associated with service provided due to their status as transmission-owning RTO members and based on a choice they made to become members.”
WASHINGTON — Arnie Quinn, director of FERC’s Office of Energy Policy and Innovation, had modest hopes for reaching consensus when he moderated a panel on public policy and wholesale markets at the Energy Bar Association’s Mid-Year Energy Forum last week.
The panel included Exelon’s Kathleen Barron, a defender of zero-emission credits for nuclear plants, and NRG Energy’s Peter Fuller, whose company is a harsh critic of the subsidies.
“While I think it might be hard to come up with a consensus about what ultimate landing spot we’d like to get to … at least agreeing on what we’d like to avoid would be helpful,” Quinn said.
Quinn also invoked one unsafe word for the discussion: “MOPR” — minimum offer price rule. “Unfortunately, we’ve got a lot of pending dockets on minimum offer price rules,” Quinn explained.
MOPR was not invoked. But consensus was indeed elusive in the discussion, which included FERC’s May 1-2 technical conference on state policies and wholesale markers and Energy Secretary Rick Perry’s call for price supports for nuclear and coal plants.
Barron, Exelon’s senior vice president for competitive market policy, defended the ZECs approved in New York and Illinois, saying they had a “quite modest” impact on wholesale markets compared to state renewable energy credits and rate-based generation.
“I think we need to take a step back when we launch this conversation to just recognize that even the Eastern markets are not free of intervention,” she said. “By 2025, about 30% of the generation in PJM will either be rate-based — through state cost-of-service regulation — public power or [renewable portfolio standard] programs,” she said.
Even if all of PJM’s nuclear generation — currently 19% of the RTO’s capacity mix — were subsidized, she said, it would still have a smaller impact than state RPS goals. “How many renewable resources would they like to have?” she asked. “25%, 30%, 50% by 2030?”
Moreover, while ZECs are worth $17.54/MWh in New York, that is less than the state’s RECs, which run as high as $23.28, she said. Illinois’ ZECs are $16.50/MWh, while their solar RECs are worth more than $200/MWh. And Maryland will pay $132/MWh for offshore wind RECs. “So we’re talking about relatively small amounts compared to other clean generation programs,” she said of ZECs.
Despite his company’s opposition to ZECs, Fuller did not contest Barron’s claims. Instead he chose to discuss his company’s “four product” vision of the future: renewables, energy storage, controllable demand and fast-ramping gas.
Fuller said that the Department of Energy’s Notice of Proposed Rulemaking had sparked an “extremely important conversation” and that a role for fuel security is an “option to think about.”
But he added, “The solution set, I think, is much broader than what was in the original notice from DOE.”
In a future dominated by zero- or low-marginal cost future, the LMP markets based on fuel costs “breaks down,” he said. “Are we doing locational marginal pricing right? Are we calculating energy prices right? PJM has a proposal to really look at different eligibility for setting energy prices. That would be an important idea. Clearly we need scarcity pricing everywhere to capture the operational realities of the markets.”
Fuller was the only member of the panel — which included Rob Gramlich, of Grid Strategies, and Potomac Economics’ David Patton, whose firm performs market monitoring for MISO, NYISO, ERCOT and ISO-NE — who did not have FERC tenure on his resume.
‘Wacky’ Federal Initiatives and RTO ‘Mission Creep’
Gramlich, a former senior vice president for government and public affairs for the American Wind Energy Association who now consults for AWEA and other clean energy interests, said the DOE NOPR would “upend 25 years of progress toward competitive markets.”
“We’ve had this conversation many times,” said Gramlich who served as senior economic adviser to FERC Chairman Pat Wood III in 2001-2005. “I think there’s one major thing that’s changed from the previous [discussions]. Usually the context is the wise, well intentioned federal authorities or the RTOs trying to clean up or fix what the wacky states are doing. [Now we’re considering] not only wacky state policies but wacky federal policies and see whether we have a regulatory structure that can withstand that,” he said, sparking laughter. “You might say whether it’s resilient, whether it can withstand and bounce back rapidly from narrow political interventions.”
Gramlich said market interventions have caused “mission creep” for RTOs beyond their traditional roles of running the transmission system and wholesale markets. “I’m frankly concerned that the RTO missions are getting extended well beyond those two core things and that a lot of states and utilities will look at these RTOs and say, ‘I’m out.’ Or, ‘I’m in the West and I was thinking of joining. Now I’m not.’”
Gramlich was skeptical of Perry’s call for compensating generation units for having on-site fuel supplies or providing “essential reliability services.”
“We’re seeing all sorts of interests saying their product or their generation type provides this, that or the other thing to the grid. I’m really relying on FERC here to decide: Is that actually needed? Is that actually a service? And if so, can others provide it as well? And let’s create real competitive markets: define the service and then let any and all bidders bid to provide that service.”
Patton said policymakers face an existential question. “You either believe in markets or not. And if you don’t believe in markets then why are we doing this?” he asked.
“This just becomes a giant rent-seeking exercise. I know when I say that to a room full of lawyers, that doesn’t sound terrible,” he added to laughter.
Patton said FERC deserves blame because it has “never articulated any sort of standard on what a just and reasonable capacity market looks like. The closest they’ve ever come is in New York, saying it’s got to produce a price signal that will be sufficient to get an adequate resource mix.”
He noted that capacity markets incent generation investments that are evaluated over a lifespan of 30 or 40 years.
“If every year or two you have dramatic policy shifts that change fundamentally what people’s expectations are about the market revenues they’re going to get, then you get … the worst-case scenario.
“It’s alarming how many times … new [FERC] commissioners have come in and said, ‘I want to revisit whether capacity markets are a good idea. Let’s have a technical conference and determine whether capacity markets are delivering on their objectives.’ Basically, the subtext is we may do away with these things. And they’re delivering roughly half the revenue that the generation needs to break even on a new investment. … It’s like when Congress says, ‘We may not raise the debt ceiling.’ How do you even say that?”
Patton disputed arguments Perry and others have made in defense of price supports.
“When people tell me we’re overly gas-dependent, we don’t have markets that value fuel diversity, [I say] that’s absolutely not true. When people say we don’t have a market that motivates generators to be available and perform, that’s absolutely not true,” he said. “They’re assertions that support doing something and changing the markets. But if you think about what we’re talking about, if you have good shortage pricing and we’re short somewhere because a gas pipeline blew up, then everybody who’s got dual-fuel capability [or is] powered by something other than gas makes an enormous amount of money. Anyone who’s gas-only and didn’t make provisions to be able to run in that scenario loses a lot of money, especially under the New England [Pay-for-]Performance rules that overcompensate performance.”
Patton said the NOPR’s notion of “‘resilience’ is just reliability” for contingencies whose probabilities are so low that grid operators haven’t planned for it.
“And if it happens, our shortage pricing is going to account for it,” he said. “The overriding objective should be to maintain market signals, and there’s only a few of them: There’s energy, ancillary services and capacity. You don’t need 10 products to do that.”
