Illinois is advancing toward a cleaner energy future thanks to two decades of policy and market developments, and new efforts could accelerate the trend, a Midwest environmental advocacy group said Thursday.
Speaking during a May 23 webinar on the evolution of Illinois’ energy market, Brad Klein, senior attorney for the Environmental Law and Policy Center, said last year’s Future Energy Jobs Act, coupled with increasingly competitive renewable generation prices, will continue to sway the state toward clean energy. The law set renewable and energy savings goals for utilities, created community solar programs and restructured the state’s renewable target process and $200 million annual budget.
The ELPC predicts that by 2020, the FEJA will boost Illinois’ solar capacity from 84 MW today to 2.8 GW by 2022, and also add 1.3 GW to its current 4.3-GW wind portfolio.
However, Klein said he predicted “growing pains and bottlenecks” in the interconnection process to get the projected amounts of solar generation online.
Klein said although he expects Illinois will be able to meet its minimum new build targets for renewable resources by about 2020, the state will probably need to continue building renewables to meet its 25% use target in the Commonwealth Edison and Ameren territories by 2025.
“We think we’re going to hit the minimum thresholds for new wind and solar build-out in the early 2020s … but we’re not on track yet to meet that 25% by 2025. We expect that this will be a long-term and sustainable effort over time,” Klein said.
He also forecasts more future bailout attempts by nuclear and coal generation operators, particularly Dynegy, which is now owned by Vistra Energy.
Klein said the FEJA favors energy efficiency, renewable energy and nuclear generation, and the final version of the law excluded draft provisions for coal bailouts, demand charges and support for microgrids. He also said FEJA notably lacked any provisions on EV and energy storage, markets he’d like to see developed in Illinois.
There are opportunities for Illinois to develop municipal aggregation programs, which are currently “stagnant,” he said. “I’m hoping we’ll see a new wave of aggregation.”
The Path to FEJA
Klein said the ELPC expects more renewable and decarbonization policies to take hold incrementally in Illinois, as other energy-related state policies have in the past.
“It seems to follow a pattern: Every 10 years or so, there’s major legislation,” he said.
He noted that Illinois began to restructure its market with 1997’s Illinois Electric Service Customer Choice and Rate Relief Law, which cut rates by up to 20% and froze them for 10 years while introducing retail competition in the state.
Klein said the state’s next wave of change came in response to the 2006 reverse power auction that saw residential prices jump 20 to 50% after the decade-long price caps expired. The auction sparked a public backlash against utilities and power marketers.
“It led to a political situation that created the next major piece of legislation,” he said, referring to the 2007 creation of the Illinois Power Agency, an independent state agency that procures power for utilities, and the state’s first renewable portfolio standard.
The 2007 RPS fell short of the state’s goals, and utilities became “increasingly hostile” to distributed resources, Klein said, leading to 2017’s FEJA.
The IPA said last year that Illinois’ first RPS, combined with retail choice, meant customers could toggle between utility service and alternative suppliers, “leading to budget and target uncertainties.” As a result of the FEJA, Illinois today uses a single RPS, rather than administering separate rules for customers using alternative suppliers.
Massachusetts and Rhode Island on Wednesday awarded procurements for 1,200 MW of offshore wind energy from what will become the two largest offshore projects in the U.S.
| Vinyard Wind
Vineyard Wind, a partnership between Avangrid Renewables and Copenhagen Infrastructure Partners, won the contract to supply Massachusetts with 800 MW of offshore wind energy, while Rhode Island selected Deepwater Wind to build the 400-MW version of the company’s Revolution Wind proposal.
Financial details for the fixed-price bids have not been disclosed.
“With today’s landmark decisions, Massachusetts and Rhode Island are ready to pioneer large-scale offshore wind development that will light the way for our industry and nation,” American Wind Energy Association CEO Tom Kiernan said in a statement. “With world-class wind resources, infrastructure and offshore energy expertise, the U.S. is primed to scale up this industry and lead it.”
Also on Wednesday, New Jersey Gov. Phil Murphy signed legislation codifying his commitment to build 3,500 MW of offshore wind by 2030, surpassing New York’s target of 2,400 MW. (See related story, Gov. Signs NJ Nuke Subsidy, Renewables Bills.)
Fast Start
“Vineyard Wind is proud to be selected to lead the new Massachusetts offshore wind industry into the future,” company CEO Lars Thaaning Pedersen said Wednesday. “Today’s announcement reflects the strong commitment to clean energy by Gov. [Charlie] Baker and the Massachusetts legislature.”
The Vineyard project will lie about 15 miles south of Martha’s Vineyard and include a transmission component linking back to the ISO-NE grid.
The company plans to begin construction in 2019 and start operating the first 400-MW section of the project by 2021, with the second half slated for completion in 2022. It got a head start on its rivals in the solicitation by beginning state and federal permitting processes in December and submitting the project’s draft environmental impact statement with state regulators on May 1.
Vineyard has said its project would generate 3,600 jobs, including 1,500 coming with the start of onsite construction. The company has also promised the project will yield significant CO2 reductions, displacing 1.25 million metric tons per year upon full operation in 2022.
Massachusetts Sierra Club Director Emily Norton called Wednesday’s announcement “terrific news” but said it is only the beginning.
“With the cost of offshore wind falling precipitously, we can transition much more quickly to 100% clean energy than anyone thought possible, and there is no time to lose,” Norton said.
“This is such an important milestone. Rather than drilling for oil and gas off of the New England coast, we will find our energy future blowing in the wind,” U.S. Sen. Ed Markey (D) said on Twitter.
In December, three developers — Vineyard, Deepwater and Bay State Wind — submitted bids in the request for proposals (83C), which called for a minimum of 400 MW but said the state would consider bids of up to 800 MW if it determined that a larger proposal was both superior to other proposals and “likely to produce significantly more economic net benefits to ratepayers.”
All three developers purchased renewable energy leases off the coast from the U.S. Bureau of Ocean Energy Management.
Massachusetts’ 2016 Act to Promote Energy Diversity mandated the Department of Energy Resources and the state’s distribution utilities — Eversource Energy, National Grid and Unitil — to sign long-term contracts for 1,600 MW of offshore wind by June 30, 2027. All three utilities had a hand in the selection, and an independent evaluator monitored and assisted the bid evaluation process.
Transmission Backbone
Deepwater Wind’s 400-MW project will connect to land at the Brayton Point substation in Somerset, Mass., and the company partnered with National Grid Ventures to propose an offshore transmission “backbone” scalable to 1,600 MW that would be open to other wind developers. (See Offshore Wind Developers Ponder Tx Options.)
The Revolution project will firm its output through an agreement with the largest hydroelectric pumped storage facility in New England, the 1,200-MW Northfield Mountain station operated by FirstLight Power Resources.
Interior of Northfield Mountain pumped storage facility | Northfield Mountain
The company’s bid said its grid-scale storage and expandable transmission system would “result in energy market savings of $75 million annually for Massachusetts ratepayers, without counting the benefits of economic development or emissions reductions.”
Deepwater developed the first offshore wind farm in the U.S., the 30-MW Block Island project in Rhode Island, which began commercial operation in December 2016.
“Rhode Island pioneered American offshore wind energy, and it’s only fitting that the Ocean State continues to be the vanguard of this growing industry,” said Deepwater Wind CEO Jeffrey Grybowski. “We applaud Gov. [Gina] Raimondo for her bold commitment to a clean energy future.”
New York’s adoption of a carbon charge will likely increase the state’s wholesale energy prices, decrease prices for zero-emission credits and boost energy revenues for new “Tier 1” renewable resources supported by renewable energy credits, industry stakeholders heard Monday.
NYISO is aiming for its carbon charge to be “reasonably transparent and predictable,” ISO staffer Nathaniel Gilbraith told a May 21 meeting of the Integrating Public Policy Task Force, which is examining the impact of carbon pricing on New York’s wholesale market. The charge should also “avoid distorting dispatch decisions away from grid power that can create emissions leakage,” he said.
The ISO earlier this month proposed to incorporate the carbon costs into its market by deducting a uniform carbon emissions charge from each energy supplier. (See NYISO Floats Carbon Pricing Straw Proposal.) Resources with zero point-of-production carbon emissions — including nuclear, conventional hydro, wind and solar generation — would not be assessed a carbon charge.
Existing Policy Interaction
A Brattle Group analysis, released at the meeting, shows that NYISO’s proposal would increase wholesale energy prices but decrease ZEC prices “on a dollar-for-dollar basis.”
Brattle also concluded the charge would increase energy revenues for new Tier 1 renewables (resources supported by RECs), thereby driving down REC prices on an equivalent basis, although it cautioned that the offset could be lower because RECs are solidified in contracts while the carbon charge is subject to revision. But the proposal would not reduce prices for fixed-price REC contracts already in place, the group said.
The report also speculated that the Regional Greenhouse Gas Initiative may already be causing a leakage of allowances and emissions to other states not under the mandatory program. To combat leaks from a future New York program, Brattle suggested the state impose border charges and reduce the number of allowances it offers.
NYISO staff acknowledged that potential changes to RGGI make it difficult to predict exactly how New York’s carbon pricing will interact with the program. A new RGGI cap is set to take effect in 2020, and New Jersey and Virginia are both contemplating joining the program.
Consumer Impacts
The impact of a carbon charge on consumers is even less clear at this point.
NYISO Manager of Economic Planning Timothy Duffy said the ISO is working with Brattle on a consumer impact analysis that will study 2020, 2025 and 2030 using a reference case scenario from its annual Congestion Assessment and Resource Integration Study. The study assumes the existence of 250 MW of offshore wind and attainment of New York’s Clean Energy Standard by 2030, and also incorporates the latest large-scale renewable procurements issued by the New York State Energy Research and Development Authority.
The ISO will also study impacts on locational-based marginal pricing and other metrics in 2030 using a model assuming 2,400 MW of offshore wind coming online by 2030, and another scenario in which the R.E. Ginna nuclear plant and Unit 1 of the Nine Mile Point Nuclear Station retire by 2029. The NYISO/Brattle study will use NYMEX futures and prices in the U.S. Energy Information Administration’s Annual Energy Outlook to project natural gas price estimates.
Duffy said more assumptions for the analysis will be presented in early June.
Weekly Reporting
NYISO is also considering requiring generators to self-report emissions data on a weekly basis for billing, with true-ups occurring against reported emissions in a trusted database, such as those maintained by EIA or EPA.
Gilbrath pointed out that the “vast majority” of New York’s fossil-fuel suppliers are already subject to emissions reporting through RGGI. NYISO’s 140 generators over 25 MW and 18 cogeneration plants are required to report under the program, leaving 114 generators representing 98 GWh of net generation in 2017 without existing reporting obligations.
NYISO’s carbon pricing would cover “burner tip” carbon emissions directly attributable to wholesale energy and ancillary services, including start-up times and no-load levels, GIlbraith said, but he asked stakeholders for other suggestions about how the ISO should manage emissions reporting.
Gilbrath said NYISO will not charge upstream carbon emissions, emissions associated with compressing natural gas for use in power plants or other greenhouse gasses, including methane and nitrous oxide. He said excluding those emissions would help keep carbon pricing predictable and gives suppliers certainty.
An Indiana appeals court ruled Monday that Duke Energy can recover from its ratepayers the cost of damages associated with not fulfilling the terms of a wind energy purchase agreement.
The court said it found sufficient evidence to let stand the Indiana Utility Regulatory Commission’s (IURC) original approval of the recovery plan (93A02-1710-EX-2468).
In 2006, Duke and Benton County Wind Farm in Indiana entered into a power purchase agreement for which the IURC authorized full cost recovery from Duke ratepayers. However, in 2013 Benton sued Duke in federal court over what it claimed was a breach of contract when Duke failed to purchase energy from the facility. Benton interpreted the agreement to mean that Duke was responsible for lost production costs in addition to the power Benton delivered.
Benton County wind turbines | Huw Williams
The U.S. 7th Circuit Court of Appeals ruled that Duke was obligated under the PPA to “pay for power not taken,” and the parties settled for $29 million, with the IURC deciding last year that the money should be recovered from Duke’s ratepayers over a 12-month period.
The IURC “recognized that Duke would be incurring significant costs in connection with the PPA,” the U.S. appeals court found. “Consequently, in order to further the commission’s policy of encouraging the development of renewable resources, the commission authorized Duke to recover all of its PPA costs from ratepayers for the entire 20-year term.”
Two ratepayers, Michael Mullett and Patricia March, appealed the IURC’s decision, arguing that its order was “contrary to law because the damages are ‘liquidated’ and ‘hypothetical’ and amount to impermissible retroactive ratemaking.”
But state court Judge Cale J. Bradford on Monday said there was no caselaw to support the appellants’ claim that “purely hypothetical” liquidated damages prevent Duke from ratepayer recovery for the PPA.
The Indiana court also noted that the $29-million settlement “is no more than customers would have paid had a different offer been submitted to MISO from March 2013 through June 2017, and is less than what potentially could have been awarded has [sic] a settlement not been reached.”
Bradford also found no merit that the recovery would amount to retroactive ratemaking. “The fact that the damages arose from a past dispute regarding a contract interpretation does not automatically make the commission’s order contrary to law,” he wrote. He added that although the case was not a rate case, even rates “are subject to subsequent reconciliation after historical costs have become known.”
Bradford also noted that paying lost production costs under wind farm PPAs is consistent with past cases involving Indianapolis Power and Northern Indiana Public Service Co.
CAISO is proposing to quadruple the number of hours in its time horizon for short-term commitment of generation units to better address load peaks that occur later in the day when solar output drops off the grid.
Extending the “short-term unit commitment” (STUC) horizon to 18 hours from 4.5 hours will better recognize morning, afternoon and evening peaks, CAISO said when it introduced the proposal Tuesday. The ISO described the need for a longer unit commitment horizon in a May 15 issue paper/straw proposal.
Limitations in short-term unit commitment (STUC) planning horizon in relation to the “duck curve.” | CAISO
“The purpose of the STUC modifications is to provide earlier notification to resources that are needed to meet the evening peak, which increases the probability these resources will be available, and better optimize the use of resources with limited starts over the entire day,” the proposal said. These changes will increase market efficiency and reliability.”
The STUC is the procedure run about 52.5 minutes before a trading hour to commit medium-start units for delivery within a forward-looking horizon — currently 4.5 hours. The STUC produces a unit commitment solution for every 15-minute interval within the horizon and issues binding start-up instructions based on units’ start-up times.
According to a CAISO presentation, the grid operator is currently “unable to make informed commitment and optimization decisions” because the current process considers only short- or medium-start resources and has limited resources for the real-time market.
Under current rules, a resource might be committed to a morning peak when it should be used for the evening peak, CAISO said. Resources with a start-up and minimum run time greater than 4.5 hours cannot be committed by the current STUC process.
With the proposed changes, generation resources will have earlier notification regarding meeting the evening peak, leading to increased efficiency and reliability “by better equipping the real-time market to meet system needs,” the ISO said.
CAISO floated the initiative in part because it foresees below-average hydro resources this summer, contributing to a tight supply situation. CEO Steve Berberich discussed some of the issues last week at the ISO’s Board of Governors meeting. (See CAISO Board Approves Forecast Error Measures.) California mountain snowpack was at 51% of the normal April 1 average, the grid operator said. There is a 50% probability of a Stage 2 emergency for at least one hour this summer, when operating reserves drop below 5% after dispatching all resources, including demand response.
CAISO says hydro output will be below average this summer, contributing to a tight supply situation (Shasta Dam pictured). | Apaliwal / CC-BY-SA-3.0
The proposed new changes will improve the efficiency of the real-time market by optimizing resource dispatch and dealing with “the duck curve,” the load profile that shows how the system is affected by large amounts of solar output. By 2020, the ISO predicts the generation ramping need on a typical spring day will grow to about 14,000 MW (from about 12,000 MW in 2017) between early afternoon and about 9 p.m. The “belly” of the duck curve is getting deeper each year as rooftop solar proliferates during mid-day hours, requiring a steeper ramp-up of resources in evening hours as solar generation goes offline. The ISO does not have visibility into rooftop solar but still must manage its effect on the grid.
Aside from expanding the STUC to 18 hours, CAISO plans to revise real-time market bid cost recovery for long-start units and extend EIM non-financially binding base schedule and bid submission requirements to 20 hours from the current 6 hours.
CAISO management has prioritized the initiative for implementation by fall of this year. Comments on the proposal are due by May 29, with review by the Energy Imbalance Market Governing Body and CAISO Board of Governors set for July.
New Jersey Gov. Phil Murphy (D) on Wednesday signed legislation to subsidize the state’s nuclear generating fleet, raise its renewable generation targets, boost storage and offshore wind, and revamp its solar program.
In a press conference staged in front of solar panels in South Brunswick, N.J., Murphy signed Senate Bill S2313, which will create zero-emission certificates for three of Public Service Enterprise Group’s nuclear generators, and Assembly Bill 3723, which will raise the state’s renewable portfolio standard to 35% by 2025 and 50% by 2030. Murphy also signed an executive order to update the state’s Energy Master Plan with a goal of 100% “clean” energy by 2050.
N.J. Gov. Phil Murphy, speaks at bill signing at New Jersey Resources’ New Road solar installation in South Brunswick, N.J., surrounded by New Jersey Resources’ CEO Laurence M. Downes, left, and Senate President Stephen Sweeney, right. | New Jersey Office of the Governor
The state’s previous RPS requirement targeted 24.39% renewables for the “energy year” ending May 31, 2028, according to the North Carolina Clean Energy Technology Center’s Database of State Incentives for Renewables & Efficiency.
Murphy said the new targets represent “one of the most ambitious renewable energy standards in the country.”
“Today, we’re taking another step forward in rebuilding New Jersey’s reputation as a leader in the development of clean energy sources while fulfilling a critical promise to foster our state’s energy future,” said Murphy, who took office in January. “Signing these measures represents a down payment to the people of New Jersey on the clean energy agenda I set forth at the beginning of my administration.”
Murphy replaced Republican Chris Christie, who had balked at plans to develop offshore wind and withdrew the state from the Regional Greenhouse Gas Initiative. Murphy, who has pledged to rejoin RGGI, noted that the legislation codifies his goal of 3,500 MW of offshore wind by 2030 and reinstates tax credits for offshore wind manufacturing that expired during Christie’s term.
The ZECs, which are expected to cost up to $301 million annually, will be funded by a 0.4 cents/kWh tariff on retail distribution customers.
The legislation requires the state Board of Public Utilities to issue an order implementing the ZEC program within 180 days. The BPU will award ZECs to nuclear plants licensed through at least 2030 that can demonstrate they are at risk of closure within three years.
PSEG’s Salem Unit 1 (licensed to operate through Aug. 13, 2036) and Unit 2 (licensed through April 18, 2040) and Hope Creek (licensed through April 11, 2046) are eligible. Exelon’s Oyster Creek nuclear plant, scheduled to be retired in October 2018 under a prior agreement with the state, is not eligible. Exelon also is part owner of the Salem plant.
Salem & Hope Creek Nuclear Power Plants | Green Delaware
The plants selected will initially receive ZECs for three years and the balance of the first energy year following selection. They will be subject to review by the BPU for additional three-year periods.
Out-of-state nuclear plants also could seek ZECs, but their approval may be dependent on a premature retirement of one of the remaining in-state plants because the bill caps ZEC eligibility at 40% of the state’s total electric usage. In 2016, according to the U.S. Energy Information Administration, the combined generation of the Salem and Hope Creek plants was 25.3 million MWh, 33.6% of the state’s 75.4 million MWh usage.
The state’s Office of Legislative Services calculated that the 0.4 cents/kWh tariff would generate $301.4 million based on 2016 consumption, translating to a ZEC cost of about $10/MWh.
Storage, Renewable Provisions
The Assembly bill requires the BPU to adopt energy efficiency and peak demand reduction programs and a community solar pilot program, and to revise the solar renewable energy certificate (SREC) program.
By Jan. 1, 2020, 21% of the state’s electricity must come from Class I renewable sources. The bill requires the BPU to begin a proceeding to reach the 2025 and 2030 RPS goals and caps the cost of the RPS program — excluding the costs of the offshore wind — at 9% of total costs to consumers in 2019 and 7% afterward.
This bill also requires the BPU, in consultation with PJM, to conduct an analysis determining the amount of energy storage to be added in the state over the next five years to provide the maximum benefit to ratepayers. The analysis will identify the optimum points of entry into the electric distribution system for distributed energy resources and include recommendations for financial incentives that may be required.
The BPU must submit a report on the storage findings within one year; six months after that, it must initiate a proceeding to add 600 MW of storage by 2021 and 2,000 MW by 2030.
The bill also requires electric power suppliers and basic generation service providers to increase the share of solar power in their portfolios to 5.1% by energy year 2021 before gradually reducing the percentage through 2033. The bill also reduces the solar alternative compliance payments beginning in energy year 2019 through 2033. Future solar RECs will be for 10 years, down from the current 15.
Electric customers would be able to participate in solar energy projects remotely located from their properties under the “Community Solar Energy Pilot Program,” which is to be converted to a permanent program within 36 months.
Utilities will be required to adopt energy efficiency measures to reduce electric usage by 2% and natural gas consumption by 0.75%.
The bill provides a tax credits for qualified wind energy projects in an eligible wind energy zone and requires the state to establish job training programs to develop a workforce for the manufacture and servicing of offshore wind equipment.
Reaction
The NJ Coalition for Fair Energy — funded by the Electric Power Supply Association and independent power producers Calpine and NRG Energy — criticized the nuclear subsidies and hinted it will seek to overturn them in court. Challenges by EPSA and others to ZEC programs in Illinois and New York are pending in the 7th and 2nd U.S. Circuit Courts of Appeals.
“While PSEG shareholders just became more prosperous, the reality is New Jersey consumers now have to confront higher electric bills for no reason other than to bail out PSEG management’s bad business decisions,” spokesman Matt Fossen said. “We wish officials would’ve waited to make a decision until after the results of PJM’s capacity auction were announced, which will be literally only hours after the governor’s signing. But this issue is not over — and it’s unfortunate the courts may be necessary to bring a dose of reason to the debate.”
Environmental activists and solar energy industry groups celebrated the renewable and DER provisions.
“It has never been more important for leaders to stand up for clean energy jobs, local investments, and clean air and climate progress in our communities. We are encouraged that in the face of rollbacks in Washington, Gov. Murphy is stepping up with bold action,” said Pari Kasotia, Mid-Atlantic director for Vote Solar.
The Energy Storage Association said the storage mandates put New Jersey in league with California, New York, Massachusetts, Oregon, Nevada and Arizona as states encouraging the technology.
Sean Gallagher, the Solar Energy Industries Association vice president of state affairs, said the bill will give “many more New Jersey residents, businesses and communities … access to solar energy.”
“If properly implemented, this legislation will create access to solar energy for consumers and businesses across New Jersey for the first time,” said Brandon Smithwood, policy director for the Coalition for Community Solar Access.
“Thanks to this important legislation, New Jersey residents who rent, live in apartments or can’t afford the upfront cost to install solar panels will now be better able to get their power from the sun,” said Luis Torres, senior legislative representative for Earthjustice.
REDONDO BEACH, Calif. — California’s grid reliability will be increasingly at risk if the state doesn’t soon address its unfocused approach to resource adequacy planning, industry experts said last week.
Panelists at Infocast’s California Energy Summit criticized the policy drift leading to an increasing reliance on reliability-must-run contracts for gas-fired units. They called for a more focused effort to address RA needs as the state brings on a growing volume of renewable resources.
The consensus among the panelists: that RA has become extremely complicated, and commenters during the conference several times touched on a recent “greenbook” report issued by the California Public Utilities Commission that warns that the state’s fragmented decision-making around capacity risks a return to the conditions preceding the Western energy crisis of 2000/01. (See CPUC Cautions of Return to Bad Old Days.)
Jan Smutny-Jones, CEO of the Independent Energy Producers Association, was blunt in his assessment of the situation, saying he has “some very real concerns about the direction the state is currently headed.”
“My job today it to bring you tales of fear and loathing,” he said. “I think that we are short of the RA market for a really long time.” He added that “I don’t think Calpine is responsible for this RA problem,” and that the RMRs are a consequence of the state failing to adequately deal with RA.
“This is insurance. This is very boring except when it isn’t, and when it isn’t, we run into big problems,” Smutny-Jones said. He cautioned that while the momentum for decarbonizing the California grid is not going to abate, it must not compromise reliability and affordability.
Last November, CAISO said California’s investor-owned utilities were about 2,000 MW short of local RA requirements for 2018. The ISO joined with utilities in asking the CPUC to reform the RA program because the state’s resource fleet is quickly shifting to more renewables, which create a need for RMRs. The ISO acknowledged that the situation is not the fault of companies threatening the retirement of gas-fired units, but rather the result of deficiencies in the RA program. (See California Utilities Short on Local RA Capacity.)
“We are sort of the poster child for the failure of the resource adequacy program,” Calpine Director of Market and Regulatory Analysis Matt Barmack said during a panel Wednesday, describing his company’s efforts to secure financial support for struggling generating units. The company has about 5,500 MW of gas-fired and other resources, such as the Big Geysers geothermal plant in California.
Calpine’s Yuba City, Feather River and Metcalf gas plants, totaling about 700 MW, are contracted under CAISO’s RMR program, which provides out-of-market payments to gas units that don’t make adequate revenue to stay in operation but are needed to provide reliability. (See FERC Approves CAISO-Calpine RMR Settlements.)
Barmack said Calpine saw the RMRs “as the only vehicle to get the certainty of compensation we needed just to get the maintenance on these three units that was required.” The current timeline of the state’s RA program finishes late in the year and doesn’t provide forward certainty for suppliers, he added.
James Caldwell, an adviser to the Center for Energy Efficiency and Renewable Technologies said that California’s current focus is on meeting greenhouse gas goals by a certain year but that urgent RA procurement problems should be addressed. The center is a partnership between environmental groups and renewable energy producers that advocates for the growth of renewables in California and the West.
“Let’s get on with it; let’s do what we know we need to do, and do it now,” Caldwell said. If there are significant reliability problems or blackouts, “everybody in this room will probably lose their job.
“The main thing we have to do is have a sense of urgency,” he said, and not wait until there are reliability problems. Gas plants will be needed for a while, but decarbonization of the electricity grid is incompatible with attaining reliability services from fossil fuel plants, he said.
“What it requires are some changes in thinking,” he said, including revising tariff structures, contracting and planning assumptions, rather than a focus on generation technologies. More optionality is needed in RA planning and finding a way to eventually attain reliability without gas plants, he said.
Martin Wyspianski, Pacific Gas and Electric’s senior director of renewable energy, told the forum that the key issue with RA is recognizing that the market is changing. California has brought on a great deal of renewables very quickly, he said, referring to the infamous “duck curve,” which illustrates the impact of solar growth on the state’s ramping needs.
“What CAISO was saying a few years ago was 20 years out is actually happening today,” Wyspianski said, noting that peak demand has shifted from late afternoon to evening as the transition to more renewables occurs, resulting in high pricing at certain periods.
“We are starting to see some of the effects of that shift,” which could signal a worsening situation down the road, he said.
MEXICO CITY — The Gulf Coast Power Association’s third conference on the nascent Mexican market drew almost 100 attendees to participate in discussions on market design, retail tariffs, transmission siting and generation financing. The May 16 event was interrupted for about 15 minutes by a seismic alert that required an evacuation, but conference organizers were able to keep the event on schedule.
Little more than a year ago, Jeff Pavlovic, managing director of the Bravos Energia generation consulting firm, was managing director of electric industry coordination for the Ministry of Energy (SENER), responsible for standing up the Mexican market. Now, as a member of the private sector, he delivered a painfully honest view of the market.
“When you’re not representing the government, you don’t have to sugar-coat things,” he said.
Pavlovic pointed to a lack of transparency in the market and the continued influence of the country’s incumbent monopoly, the Federal Electricity Commission (CFE).
“For a market to work, decisions need to be made by the market participants,” he said. “Decisions should be pushed out to people who have money on the line. And for that to happen, there needs to be transparency for people who have real investments at risk and money in the market.”
Case in point: Last November, Mexico’s Energy Regulatory Commission (CRE) published the market’s first basic retail rates.
But then users in Baja California, which is isolated from much of the Mexican mainland, complained to CRE about errors in their higher rates. That led to a change in the key criteria for rates in February that affected all users, he said.
CRE “changed the way [it] assigned load demand among different users and rate classes. This led to big drops, 30 to 40% drops, across all rate classes,” he said. “It no longer made any sense. It was completely impossible to reproduce. The CRE spreadsheets that were meant to show the math started 80% through the calculations.”
Pavlovic said the original methodology was fundamentally sound and that he hoped CRE would fix the calculations. He said the commission gave up last month and published a new, transitory methodology that appears to phase in rate increases over the rest of 2018.
CRE “seems to be on a trajectory to keep raising rates,” he said. “But the level of transparency and logic is even less than before.”
Pavlovic said distribution losses, or theft — a serious problem in Mexico — are a looming problem in the rates structure. Costs are currently assigned to paying consumers at the lower voltage levels where the losses occur. To compensate, the rates include a mechanism for the cheapest generation to be assigned to the smallest users.
In addition, he said, CFE continues to combine the accounting for its various subsidiaries, which have yet to be unbundled.
“It continues to lose money as a whole, but we can’t tell where they’re losing money because they haven’t separated their results by companies,” Pavlovic said. “They’re starting to make a lot of money from fuel sales and ‘other income,’ which we have no idea what it is.
“CFE is required to publish contracts for energy and fuel,” he said. “That would solve problems where market participants suspect there are deals between CFE companies at either too low or too high a price compared to market conditions, but CFE has resisted this. This is an opportunity for SENER to step in and enforce the transparency requirements established in the law.”
On the bright side, Pavlovic said the market’s capacity auctions have been successful and market participation continues to grow.
“There is a new wave that will come in,” he said. “I think the market will continue to get deeper and help us exercise influence over the policy. But we need CFE to show leadership in its own separation of its businesses.”
Ammper Energia CEO Juan Guichard said he has a “more optimistic view” of the market than Pavlovic, reminding attendees that it was only written into the Mexican Constitution in 2014.
“We’re starting to see a light on the road. Hopefully, it’s not a train,” said Guichard, whose company represents generators. “That’s a market reality … the prices for the new rate and tariff, are not all complete. This is part of the evolution in the market. … We need to reach a middle point between supplier and end customer. We are not used to having choices, so suddenly there is a market, a complicated market with power. There are risks.”
Guichard said the market’s low liquidity limits hedging opportunities, which presents a challenge when meeting customers’ demands.
“Some users have said there’s less liquidity for the operator to cover peak hours or just at night. We need to provide a new solution to customers. We have agreed with the customers, because they’re the first customers going in to a new market,” he said.
Patricio Gamboa, energy director for steel manufacturer Deacero, shared Guichard’s optimism, but noted that the country’s July 1 national election could slow progress. Leftist populist Andres Manuel Lopez Obrador, a two-time mayor of Mexico City, currently has an 18-point lead over the National Action Party’s Ricardo Anaya and a 27-point lead over the Industrial Revolutionary Party’s Jose Antonio Meade of PRI, whose two parties have ruled Mexico for the past 89 years.
“The election year is a lost year, so we have a lot of years to go,” Gamboa said. “When we started this market, we compared it to others. It took them 10 years [to run efficiently], and we are at four years.
“If we compare to other markets, we realize there are many areas of opportunity as far as transparency,” he said. “If the concern is collusion, I agree that to not be transparent is a very high risk. The level of information we have from CENACE is less than other markets.”
A panel focused on regulated transmission rates warned that the transitory rate scheme for 2018 is not helping matters and said changes must be made. Gerardo Cervantes, director of energy marketing for Enel Mexico, said the rate design is inconsistent with the market’s public policies and doesn’t send accurate price signals.
“They designed a market that claims the policy of public power is the recovery of cost. The basic supplier is not recovering costs and is doing poorly,” he said. “When you start implementing [rates] in such a random way, when you put in caps, that means your rate doesn’t have anything to do with what’s happening in the market.”
“We don’t even know clearly which is public policy,” agreed Antonio Noyola, chief development officer for Houston-based energy consultant Avant Energy. “The market is to provide a competitive market, but the design of these supply rates is not real. Reform … is not happening at the right pace. It should happen right away, so they can make the right decision. We need to acknowledge that at the end of the day, [the supplier is] taking a risk.”
“We have to work on providing information to the authorities, so that next January, it’s not challenging,” Cervantes said. “It’s necessary to know the cost of everything, the transmission, the distribution. We need to raise awareness of … the transparency of regulation. If we don’t do it now, or because we are being subsidized, eventually we will have to pay the price — and it’s going to be a very high price.”
Keynote speaker Severo Lopez Mestre Arana, a partner with Galo Energy Consulting, suggested the Mexican market will benefit from continued interaction with other markets. Mexico has five DC ties with the U.S. — three across the Texas border with ERCOT and two with CAISO — with a total capacity of 1,086 MW. Another eight interconnections provide an additional 788 MW of capacity of emergency power.
“We believe with minimal adjustments to regulation, we can move forward,” Mestre said. “You cannot stop the strengths that are pushing to integrate the markets. The strengths are so strong, the power of efficiency and the power of sustainability. The regulation needs to adjust to the reality.”
He said Mexico is interested in extending its interconnections with the U.S., although it has not yet expressed its official intentions. Three additional interconnections between the two countries are in various stages of development. (See Regulators Fear Cross-Border Tx Risks ERCOT’s FERC Exemption.)
| Mexico Ministry of Energy
The key, Mestre said, is completing Mexico’s proposed financial transmission rights market. He used CAISO, ERCOT, PJM and international exchanges such as the EU’s Joint Allocation Office, Inelfe (a DC link between Spain and France) and Energinet DK (Denmark with Germany) as examples of markets with successful exchange capabilities.
“We found that in many markets, that’s a constant that allows for transporting long-term energy or transmission rights,” he said. “We need to extend our assumptions. It seems only minimal changes can lead to a more dynamic model of export exchanges. The model is not that far away. That’s the trend, in most markets.”
Do Low Prices Equate to Successful Auction Prices?
Que Advisors Managing Director Peter Nance, moderating a panel discussion on the market’s recent long- and medium-term auctions, noted the long-term energy auction’s prices were very low at slightly more than $15/MWh. He asked, “Does this mean the process is work well?”
“The cost for the system should also be one of the [measures] of how successful the process is,” said Casiopea Ramirez, regulatory affairs chief for Spain’s Gas Natural Fenosa. “We are increasing the system capacity, but this could also trigger a different process, if we continue introducing capacity with a grid that has not been extended. Demand is low. Logic would say we don’t need additional capacity.”
Ramirez reminded her audience that one of market reform’s goals “is to obtain cheap energy, and we have attained that.”
Veronica Irastorza, an associate director in NERA’s Mexico office, cautiously agreed.
“These low prices are due to natural resources, but also, high risks are assumed in the long-term auctions. All these risks are being assumed by the supplier,” she said. “I’d prefer to see bilateral contracts and CFE to start shrinking over time. You need to have more transparency.
“I do think the auction is really complex and different from other auctions around the world.”
Room for Both Commercial, Development Banks in Mexico
During a panel discussion on financing new generation capacity, Acciona Energia CEO Miguel Angel Alonso recalled his arrival in Mexico in 2006 and the global financial crash two years later.
“I came from Europe, where private banking was covering all the renewable development, but then there was a crisis,” he said, referring to the Lehman Brothers collapse. “It was like watching a love story, and you go … and get some popcorn, and then [return to find] everybody’s dead. The butler killed everybody.
“This is a market that is hard to finance,” Alonso said. “I don’t really see how you can be offering energy at $17. They don’t want to finance. They don’t need it. The ones on top take the cherry. They go with the commercial bank, and there’s no room for the development bank.”
Nacional Financiera’s Arturo Gochicoa Acosta has shown there is still room for development banks. He has helped the government institution finance energy projects with an installed capacity of more than 3.5 GW since 2013.
“We’re not trying to finance projects all around Mexico. We’re definitely doing our analysis,” Gochicoa said. “There’s always the risk of how the energy portfolio changes over the years. What will the infrastructure look like in the next 20 years? You have to look at good projects that are possible and that are able to repay in the long term.”
FERC last week affirmed an administrative law judge’s 2017 decision that SPP’s proposed Tariff revisions to incorporate Tri-State Generation and Transmission Cooperative as a new transmission owner in an existing pricing zone are just and reasonable (ER16-204).
Nebraska Public Power District, the dominant TO in the affected zone, objected to SPP’s decision to incorporate certain Tri-State transmission facilities and the annual transmission revenue requirement (ATRR) into its zone.
Tri-State’s service territory | Tri-State G&T
The commission denied NPPD’s request to reopen the record, saying it failed to demonstrate the existence of “extraordinary circumstances” and that a change in circumstances was “more than just material.”
“NPPD’s motion relies on a change in the criteria that SPP applies to determine zonal placements and additional information” regarding another potential SPP member (Western Area Power Administration-Rocky Mountain Region) joining the RTO, the commission said. “Neither of these arguments demonstrate extraordinary circumstances or changes that go to the heart of the case.”
When SPP adds a new TO to an existing zone, the TO’s ATRR and any of its load not already included in the zonal load are added to the existing zone’s totals, resulting in a new total zonal ATRR and a new total load. That leads to new service rates for all transmission customers within the zone.
NPPD argued that the proposed ATRR, including the proposed return on equity, was not just and reasonable. It said that because Tri-State’s average per-megawatt cost of serving load was higher than NPPD’s average cost of serving its existing load, adding Tri-State would shift more than half of the costs of the co-op’s transmission facilities to existing Zone 17 customers and increase the costs to serve them.
The commission accepted SPP’s Tariff revisions in December 2015, and established hearing and settlement judge procedures over whether the placement of Tri-State’s facilities and ATRR in NPPD’s zone was just and reasonable and whether Tri-State owed any refunds.
ALJ John P. Dring found SPP’s proposed Tariff revisions and their placement of Tri-State’s transmission facilities in NPPD’s zone just and reasonable. He also determined Tri-State owed no refunds in connection with its proposed zonal placement.
FERC agreed that the criteria SPP applied to determine whether Tri-State should be placed in NPPD’s zone “are appropriate for determining zonal placement” in this proceeding. It also sided with Dring that “what matters in this proceeding is whether the criteria render just and reasonable results,” agreeing that SPP’s criteria did so.
“We agree … that shifting cost responsibility for some degree of legacy costs is not per se unjust and reasonable, but there may be cases in which a cost shift would be unjust and unreasonable,” the commission wrote.
Fifteen SPP members joined NPPD in intervening in the docket, many of whom filed a Section 206 complaint in October alleging that SPP’s zonal placement is unjust and unreasonable (EL18-20). FERC rejected the complaint in March, but the TOs have filed a rehearing request. (See FERC Rejects TO Complaint on SPP Zonal Placements.)
Colorado-based Tri-State, a nonprofit cooperative that sells wholesale electricity to its member-owner distribution cooperatives and public power districts in Nebraska, New Mexico and Wyoming, joined SPP in January 2016.
Commission Denies Rehearing Requests on SPP’s ARR, TCR Rules
The commission denied Xcel Energy’s rehearing request of a 2017 order that rejected proposed revisions to SPP’s tariff regarding the eligibility of customers with network service subject to redispatch to receive certain financial transmission rights (ER17-1575).
The commission’s October 2017 order directed SPP to rewrite its rules on auction revenue rights and long-term congestion rights (LTCRs), saying the RTO’s proposed grandfathering provisions would “inappropriately extend practices that the commission finds unjust and unreasonable.” (See FERC Again Rejects SPP Rules on ARRs, LTCRs.)
FERC affirmed its decision to grandfather ARRs and LTCRs that have already been granted to network customers with service subject to redispatch. It had also said it was not reasonable to extend the grandfathering provisions through July 15, 2017, as SPP had proposed as a transition to new ARR/LTCR eligibility rules.
Xcel argued for a rehearing on behalf of its Southwestern Public Service subsidiary, alleging that FERC’s order disregarded SPS’ contractual rights, concluded that network service subject to redispatch is not similarly situated to network service not subject to redispatch and determined that the remedy did not have retroactive effect.
The commission responded that Xcel failed to show that SPP’s Tariff “provided [SPS] with a contractual right that was abrogated” in its Tariff order. FERC found it was reasonable to distinguish “between rights that customers already had been granted and rights that customers may have expected to be allocated.”
“Southwestern is not losing any rights that already have been granted and remains eligible to be allocated ARRs in the future” subject to the limitation in the Tariff order, the commission said.
FERC issued a related order that also addressed Xcel’s claims that the commission had “fundamentally mischaracterized the nature of redispatch service,” rejecting Enel Green Power North America and Southern Company Services’ rehearing request (EL16-110).
Both companies appealed October orders filed along with ER17-1575 (EL16-110 and EL17-69) that found SPP was not barred by its Tariff from allocating ARRs and LTCRs to network customers subject to redispatch for the amounts and periods subject to redispatch during the 2017-2018 annual allocation process. Enel and Southern filed on behalf of their Buffalo Dunes Wind Project and Alabama Power subsidiaries, respectively.
The commission said both parties failed to show that the Oct. 19, 2017, effective date set in EL16-110 for the Tariff revisions is not appropriate. It said the effective date preserved its ability to order refunds, if appropriate, “back to this date.”
FERC said that its decision that SPP’s Tariff revisions do not apply to the 2017-18 annual allocation process “was neither ‘internally inconsistent’ nor erroneous.” It pointed out that the annual ARR and LTCR allocations for 2017/18 were made in March and April 2017, prior to the Tariff revisions’ effective date.
OMPA Complaint Against OG&E Goes to Settlement
The commission set the Oklahoma Municipal Power Authority’s complaint against Oklahoma Gas and Electric for hearing and settlement judge procedures, with a refund effective date of Jan. 26, 2018 (EL18-58).
| Oklahoma Municipal Power Authority
FERC found OMPA raised “issues of material fact that cannot be resolved based upon the record before us.” The state agency filed the complaint in January, alleging that OG&E’s ROE is unjust and unreasonable and that its formula rate needs to be revised to reflect the Tax Cuts and Jobs Act.
The commissioners said OMPA’s analysis was enough to show OG&E’s cost of equity may have declined significantly below its existing 10.6% base ROE. They also said any tax-related changes to OG&E’s formula rate should ensure that its rates properly reflect the effects of the tax legislation.
OG&E said its formula rate will automatically reflect the change in the federal corporate income tax rate, but it will not automatically address the effect of the legislation on accumulated deferred income tax balances.
NATIONAL HARBOR, Md. — Consumer, small-business and environmental advocates pressed PJM’s Board of Managers on the issue of transparency at their annual meeting last week, calling on the RTO to provide more explanation of its broader plans and goals.
Advocates from several member states took turns outlining their shared perspective on what they see as the largest issues PJM is currently addressing and the obstacles the RTO faces.
Brian Lipman with the New Jersey Division of Rate Counsel set the tone during his discussion of PJM’s initiative to reform how energy prices are formed.
“Advocates are supportive of looking at proposals to improve the PJM market, but it needs to be done in the most efficient and effective manner,” he said. “So with energy price formation, one of our first questions is: What happened to LMP?”
He endorsed PJM’s current focus on revising how reserves and shortage pricing are calculated, but added that “it’s unclear to us” whether reviewing the LMP calculation will be a “next step.”
“We’re asking for clear communication on this front,” he said. “There’s much being juggled by all the stakeholders in PJM, and many problems on the table for consideration. … Each one impacts another, so it’s not possible for the consumer advocates or any stakeholder to merely take a look at one piece of the puzzle without thinking about how everything will fit together and what the complete picture is. … We need to know how PJM plans to fit energy price formation into its resilience initiative.”
John R. Evans, Pennsylvania’s small business advocate, said he stays involved because “many times, if you don’t have a seat at the table, you often find yourself on the menu.”
Evans is concerned about the potential for his state legislature to subsidize its nuclear fleet, as has happened in Illinois and New York and is on the brink of approval in New Jersey.
“Show us some benefit to small business classholders,” he said. “So far, we haven’t seen that.”
Erik Heinle of the D.C. Office of the People’s Counsel discussed advocates’ support for increasing PJM’s consideration of cost-containment guarantees in staff’s analysis of transmission construction bids. Stakeholders will consider several different proposals on the topic at a May 24 Markets and Reliability Committee meeting. Heinle’s office joined LS Power in developing a proposal that would require PJM to seek input from the Independent Market Monitor in comparing cost caps to cost estimates. PJM has developed two other proposals: one would limit cost-containment evaluation to construction costs while the other would give RTO staff authority to consider a wider range of factors at its discretion and require them to perform a feasibility evaluation on any cost commitments.
While Heinle advocated for his proposal, he acknowledged the “thorny issue” of having evaluation criteria developed by one stakeholder sector and called PJM’s proposals “a considerable upgrade form the status quo.”
He also addressed supplemental and end-of-life transmission projects, arguing that “the current process does not provide adequate transparency related to data and criteria thresholds each transmission owner uses to prioritize assets for replacement.”
Jackie Roberts, director of the West Virginia Consumer Advocate Division, questioned PJM’s filing in FERC’s resilience docket, saying it made her “uncomfortable” that the comments should have “demonstrated how reliable and resilient our system already is.”
“I don’t think clearing prices are any more artificially low now than they were artificially high several years ago,” she said.
The comments “befuddled” her until she realized they reminded her of how the Obama administration’s Clean Power Plan was developed, she said. It became clear, she said, that such proposals are developed by “someone who doesn’t have the authority to require a market solution.”
“PJM asking for more authority about the gas industry … I don’t understand that,” she said. “I do think there needs to be a gas industry ISO, but PJM is not the entity to do that. That needs to be a parallel, standalone effort.
“I really am not a fan of PJM saying anything that suggests to the public … that we are not resilient and that our fuel mix may not be resilient.”
PJM Response
PJM CEO Andy Ott said legislators have been asking him at what point the grid would become too dependent on one set of infrastructure.
“We have been very clear in our statements about the current situation, even with the current announced retirements, [that] we don’t have a fuel security problem and the system is fine,” he said. “However, 10 years from now, if we continue to see changes in the fuel mix, we have no criteria to look at fuel dependencies and fuel security. … It’s a legitimate question for us to analyze. If you’re insinuating that PJM’s activities here are trying to change certain resources from retirement … I think that’s a misguided suggestion.”
Ott and board members agreed on the importance of prioritizing issues based on significance but defended some of staff’s decisions to move quickly on topics that some stakeholders have questioned.
“In some cases, ‘do nothing’ might not be an option because of whatever drivers are out there,” Ott said. “Ignoring problems isn’t going to make them get any better.”
Board member Charles Robinson said PJM sometimes moves quickly specifically to be “responsive to a cost concern.”
“Sometimes we move quickly because we are concerned about cost impacts, because we feel the need to correct a perceived deficiency so that we can be responsive to a cost concern,” he said.
“The board does take both cost and benefit into consideration,” board member Susan Riley said.
IMM Support
Robinson also questioned a note from the advocates’ slides indicating their support for the Monitor.
“From my perspective, I feel as though we also care a great bit about getting an independent view, and I believe we take it into account,” he said.
“We think the level of cooperation between PJM and the Market Monitor is at an all-time high, so I’m interested in understanding if that bullet was there just to reaffirm or if there is a perceived issue,” Ott added.
Kristin Munsch of the Illinois Citizens Utility Board clarified that it was meant as support for the Monitor going into contract negotiations next year.
“We wanted to go publicly on record that this was important to us,” she said. “Don’t be surprised when you hear consumer advocates going forward reaffirming, making that point, because we understand the discussions that might be coming to the broader PJM community.”
Bill Fields from the Maryland Office of People’s Counsel said the Market Monitor provides information and analysis in stakeholder meetings that might not otherwise exist.
“We find a lot of value in the Market Monitor continuing to provide that assistance to advocates,” he said.
Roberts brought up another concern about PJM attempting to stop Monitor Joe Bowring from filing complaints at FERC.
“Along with PJM, he is the most knowledgeable person about all matters PJM, and we simply don’t understand why there is a problem with him filing complaints at FERC,” Roberts said. “We think that’s an important [thing] you have stifled.”
The Sierra Club’s Mark Kresowik voiced concerns about what he suggested is a common assumption: that environmentalists seek high energy prices in order to drive efficiency.
“The answer is actually ‘no’ because, in addition to clean electricity being the single most important way that we’re doing to reduce carbon pollution from the economy and ultimately combat climate disruption, clean electricity also has to power the rest of the economy … in order to achieve the levels of carbon pollution reductions that we need,” he said. “In order for clean electricity to play that role, it has to outcompete gas and oil in those sectors, which means it needs to be affordable for all.
“We are increasingly concerned that many of the decisions that are made by PJM, that are in the process of being recommended by PJM, threaten to raise costs, particularly for states and consumers that are actively choosing and preferring clean energy, often without a clear reliability benefit.”
He also expressed interest in a comment made by Robinson that the board requests cost analysis on major decisions sent to FERC, noting that no such analysis was included in PJM’s recent filing to revise its capacity construct. (See PJM Capacity Proposals Widely Panned.)
“That’s a major concern for us,” he said, “and we’re seeing similar things going forward.”
Mike Jacobs with the Union of Concerned Scientists said the current capacity construct excludes some resources on the grid and he urged PJM to consider allowing resources more flexibility to make capacity offers into annual, summer or winter auctions.
“Optimization is something this organization knows how to do … instead of being stuck with old models and old resources,” he said.
