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. — The rapid growth of community choice aggregators in California has sparked criticism that they are “boutique” green energy options catering to wealthier communities such as the San Francisco Bay Area.
But Jessica Tovar, organizer of the Local Clean Energy Alliance of the Bay Area, told Infocast’s California Energy Summit last week she was inspired to pursue a CCA because she grew up in an East Los Angeles neighborhood with fossil fuel generating plants and other industrial facilities that affected the health of herself and family members. Her group sees its role as “addressing climate change, advancing social and racial justice, and building sustainable and resilient communities.”
“Our current energy structure is problematic,” Tovar said. “We affect the entire world based on our energy choices.” Tovar said CCAs allow communities to make the best choices regarding their energy, which she referred to as “energy democracy.” Her CCA’s goal is to reduce consumption, and integrate local generation and new, cleaner technology.
Through CCAs, “we can win economic and environmental justice in our communities,” she said.
Redondo Beach Council Member Christian Horvath said he was seeking lower rates and green power when he ran for office, a campaign based partially on the intent to join or create a CCA. A lot of people aren’t familiar with how CCAs work, but “to me it was a path forward for moving into renewables” and local distributed energy, he said.
The council eventually joined Los Angeles Community Choice Energy (now merged into Clean Power Alliance of Southern California), founded in spring of 2017 by the Los Angeles County Board of Supervisors. The initiative required educating the community about the increased choice a CCA offers and overriding a mayoral veto, he said.
“A lot of people down here just aren’t familiar with what a CCA is or what that means,” Horvath said. “The concerns on the other side didn’t make a whole lot of sense to me. To me, it was the responsible thing to do.”
The CCA concept largely sat dormant after the legislature approved their creation in 2002, but their growth has spiked dramatically in the last five years. Investor-owned utilities say they could lose up to 85% of their loads to CCAs within a decade. But that expansion doesn’t come without growing pains.
“It’s a challenge every day,” said Ted Bardacke, executive director of the Clean Power Alliance. He said the growing number of CCAs is a comfort, adding that creating a CCA requires building a brand, allowing customers to take a larger role in their consumption and gaining consumers’ trust to co-manage their energy usage. It is also vital to build strong management teams with experience in the energy sector, he said.
“One of the things that keeps us going is the business model seems to work,” Bardacke said.
CCAs were bolstered by news earlier this month that Moody’s assigned a first-time Baa2 issuer rating to Marin Clean Energy, reflecting the strength of the CCA’s business model.
“That’s a big step, to actually have a CCA in California with a credit rating,” which shows the market is maturing, Bardacke said. He noted that some in the industry doubt whether local officials have the expertise needed handle electricity procurement (“We hear that a lot down at the [California Public Utilities Commission].”), but community-owned electricity organizations are nothing new. About 25% of California’s load is served by municipal or publicly owned utilities run by elected officials.
“They tend to have very good reliability and pretty darn low rates,” Bardacke said. “There is a model out there in California that has worked for over 100 years of municipal utilities and public power.”
One issue that could impede CCA growth: Beginning in 2021, state law will mandate that CCAs meet 65% of their renewable requirements through long-term contracts of at least 10 years. The longer terms will require more scrutiny of CCA credit ratings and the transition to a direct customer relationship with power suppliers is a major shift compared with how procurement has been done by traditional utilities.
“I think it’s still an ongoing discussion” around CCA credit ratings and finances, said Cathy DeFalco, executive director of Lancaster Choice Energy. “I think both parties have to have a little bit of flexibility” regarding contracts with suppliers, she said, adding that “as CCAs mature … we get more history and people become more comfortable.”
The discussion got testy when it turned to the IOUs’ request last month that the CPUC restructure the Power Charge Indifference Adjustment (PCIA) for customers departing for CCAs, a mechanism designed to prevent utilities from shouldering all the costs for legacy procurements. The IOUs noted that areas served by CCAs are wealthier than average. (See California Utilities Propose New CCA Rules.)
When Marin Clean Energy Director of Power Resources Greg Brehm said “there is cooperation in the works” on the indifference adjustment, Independent Energy Producers Association CEO Jan Smutny-Jones repeated a refrain that utilities are holding hundreds of millions of dollars in renewable energy contracts signed years ago when renewables were much more expensive, and that the departure of customers to CCAs have left remaining utility customers with the stranded costs. Smutny-Jones and a representative from Pacific Gas and Electric last summer raised the alarm with the State Legislature over the legacy contracts. (See California CCAs Spur Worry of Regulatory Crisis.)
“We expect to receive full payment for those contracts,” Smutny-Jones said.
Brehm replied that “there is no expectation that those contracts will be discounted in any way.”
“I’ll take that to the bank,” Smutny-Jones said with a skeptical tone, drawing laughter from attendees.
U.K.-based National Grid on Thursday said its yearly earnings to the end of March 2018 increased 4% (constant currency) to $4.73 billion, mainly reflecting the strong performance of the company’s U.S. business.
The earnings figure excluded the sale of the company’s U.K. gas distribution business and major storms.
“In the U.S., we faced a unique winter, with major storms across all our jurisdictions,” CEO John Pettigrew said in an analyst call May 17. “In October, we restored over 530,000 electric customers following one of the most severe storms in recent years. And in March, we were challenged again with three-back-to-back nor’easters, which is unprecedented.”
New Rates
National Grid USA now has about 80% of its distribution businesses operating under new rates following successful filings for Massachusetts Electric, Keyspan Gas East (KEDLI), Brooklyn Union Gas (KEDNY) and Niagara Mohawk, Pettigrew said.
National Grid New York Service Areas | National Grid
The Niagara Mohawk agreement approved in March allows a return on equity of 9% and $2.5 billion of capital investment over three years.
“With the KEDNY and KEDLI settlements, that means over the next three years, total investment in New York will be more than $5 billion,” Pettigrew said.
The company also has pending rate cases for Massachusetts Gas (10.5% ROE) and Rhode Island Gas & Electricity (10.1% ROE), which it expects to have in place by October, he said. Combined, it’s asked for $81 million in additional revenue and $800 million in annual capital allowances.
Pettigrew said both filings are “progressing well,” with the Massachusetts hearing due to conclude later this month and the Rhode Island hearings set to begin in June.
National Grid Rate Base | National Grid
“With the completion of these rate filings, we’ll have new rates for our entire U.S. distribution business, which will contribute to improvements in performance and allow us to achieve returns as close to the allowed level as possible,” he said.
National Grid adjusted the rate filings, as well as that for Niagara Mohawk, to reflect the lower corporate tax rate passed by Congress in late December. Finance Director Andrew Bonfield said the tax cut will be significantly beneficial to consumers and economically neutral to utilities.
Renewables
National Grid U.S. Headquarters in Brooklyn, NY
Pettigrew said the U.S. and U.K. both continue to decarbonize at a fast pace, driving National Grid to increase its engagement in renewable energy.
The economics for solar, wind and storage are becoming increasingly attractive, with further demand for clean energy coming directly from U.S. corporates through power purchase agreements, he said.
“There is no doubt that the ongoing significant growth in large-scale renewables is set to continue into the long term,” Pettigrew said. “In addition, utility-scale renewables also offer attractive opportunities.” He cited the first offshore wind farm in the U.S. off Block Island and a 6-MW battery the company is installing on Nantucket.
The transition to renewables is likely to be closely followed by the electrification of transportation, with many forecasters now predicting price parity with gasoline and diesel cars by the early to mid-2020s, he said.
The U.S. business has installed more than 150 public charging stations for electric vehicles and has submitted proposals to regulators in each of its operating states for EV investments, Pettigrew said.
Bonfield said the company expects “to invest at least $10 billion over the next three years in our U.S. business.”
RENSSELAER, N.Y. — NYISO power prices averaged $35/MWh in April, up from $29.91/MWh in March and $31.06/MWh the same month a year ago, Rana Mukerji, ISO senior vice president for market structures, told the Business Issues Committee on Wednesday.
The ISO’s year-to-date monthly energy prices averaged $54.82/MWh in April, a 48% increase from a year earlier. April’s average sendout was 390 GWh/day, compared with 413 GWh/day in March and 377 GWh/day a year earlier.
Transco Z6 hub natural gas prices averaged $2.79/MMBtu for the month, down less than 1% compared with last month and the same period last year.
Distillate prices gained 8 to 9% compared to the previous month but were up 32.6% year over year. Jet Kerosene Gulf Coast and Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $14.94/MMBtu and $14.85/MMBtu, respectively.
The ISO’s local reliability share was 12 cents/MWh in April, compared with 19 cents/MWh the previous month, while the statewide share fell from -51 cents/MWh to -57 cents/MWh. Total uplift costs were lower than in March.
Broader Regional Markets
Reviewing the Broader Regional Markets report, Mukerji highlighted two items.
The first concerned NYISO’s effort to clarify the minimum requirements for delivering external capacity from PJM into the installed capacity (ICAP) market. The ISO will continue to evaluate whether it needs to impose additional performance requirements and obligations for deliverability to the New York Control Area border, and it will work to ensure that external capacity resources provide a comparable reliability value for consumers as internal resources. At a combined Installed Capacity/Market Issues Working Group meeting April 24, the ISO discussed the current Supplemental Resource Evaluation process for external resources, as well as the existing consequences for external ICAP supplier nonperformance.
The second item concerned possible refinements to locality exchange factors (LEFs). At an August 2017 ICAPWG meeting, Atlantic Economics presented an alternative approach for calculating LEFs, prompting the ISO to engage GE Energy Consulting to investigate the viability of potential refinements to its current methodology.
GE presented a review of its assessment of three potential alternative approaches for calculating LEFs at the May 9 ICAPWG/MIWG meeting, developed by GE, the New York Transmission Owners and Consoldiated Edison.
The ISO on Wednesday delivered to the BIC a position statement that it “has become convinced that the stability and transparency of the current [deterministic] approach is preferable to a probabilistic approach and, therefore, recommends that we terminate further evaluation … [and] recommends not spending any additional resources on exploring LEF probabilistic techniques at this time.”
Con Ed also delivered a statement that it “has performed a ‘proof of concept’ of a [probabilistic] LEF that would save customers tens of millions of additional dollars beyond the savings resulting from the use of the [deterministic] LEF.”
The utility added that it was “disappointed that the proposal is being rejected and the project terminated without a full vetting of the proposal through the stakeholder process.”
The ISO said stakeholders are free to make their own presentations to market participants through the stakeholder process.
Potomac Economics 2017 State of the Market Report
The BIC on May 16 heard the first of three planned presentations to NYISO stakeholders this month from Potomac Economics, the ISO’s Market Monitoring Unit, on its 2017 State of the Market Report, including recommendations to improve performance.
NY 2017 Energy Prices and Congestion | Potomac Economics
Wednesday’s presentation pointed to a notable divergence in energy prices and congestion between NYISO’s Central and East, “and of course that’s driven by the Central-East Interface, which limits flows from the central part of the state to the capital region,” Potomac’s Pallas LeeVanSchaick said. The same interface was highlighted earlier this month in the ISO’s 2017 Congestion Assessment and Resource Integration Study (CARIS). (See NYISO Study Identifies Key Areas of Tx Congestion.)
The price discrepancies were largely driven by differences in regional natural gas prices, which averaged $2.06/MMBtu on the Millennium Pipeline in the West and $3.39/MWh on the Iroquois Pipeline Zone 2 in the East.
“In 2017 we saw about an average of a $7/MWh price spread between those two regions, and that was driven principally by the large difference in gas prices,” LeeVanSchaick said.
Congestion also exists between the northern and central areas of the state, with an average price spread last year of $6/MWh, he said.
Long Island had the highest energy prices last year (with a $6/MWh price spread between it and the Lower Hudson Valley), in part because of “the higher heat rates of thermal resources there as well as somewhat higher gas prices for the Iroquois Pipeline,” LeeVanSchaick said.
NY Performance Incentive Recommendations | Potomac Economics
He noted that the report carries over several criticisms and recommendations from last year, such as its assertion that the ISO’s markets do not provide incentives for efficient transmission investment.
Priority on Market Efficiency
“You may get congestion in New York City or in eastern New York because you’re using [phase angle regulators] in the eastern part of the state to manage congestion in the western part, [which is] why it’s important to use the market models so it can be done as efficiently as possible,” he said.
To address transmission constraints, the MMU recommends compensating merchant investors for the capacity value of transmission upgrades and reforming CARIS to better identify potential economic transmission.
Benefits would include cost savings achieved by lowering barriers to entry, which favor generation and demand response over transmission, and by substantially reducing the need for out-of-market public policy investment, the report said.
“NYISO has made a lot of progress on this issue this year, so I’m crossing my fingers that by the end of the year, the ISO will be modeling these 115-kV constraints, or at least the vast majority of them,” LeeVanSchaick said.
The MMU designates a recommendation as high priority by assessing how much the change would likely enhance market efficiency.
“To the extent we are able to quantify the benefits that would result from the enhancement, we do so by estimating the production cost savings and/or investment cost savings that would result because these represent the accurate measures of economic efficiency,” LeeVanSchaick said.
Modeling NYC Local Reserve Requirements
One of the MMU’s new performance incentive-related recommendations is for the ISO to model local reserve requirements in New York City load pockets.
The ISO is required to maintain sufficient energy and operating reserves to satisfy N-1-1 local reliability criteria in the city. However, these local requirements are not satisfied through market-based scheduling and pricing, making it necessary to satisfy them with out-of-market commitments in the majority of hours, the report said.
The costs of out-of-market commitments are recouped through make-whole payments, the routine use of which distorts short-term performance incentives, as well as incentives for new investment that can satisfy the local requirements, LeeVanSchaick said.
Wednesday’s presentation provided just an overview of the MMU report. Capacity results and related recommendations will be presented at the May 23 ICAPWG/MIWG meeting, with energy and ancillary services results and recommendations to be presented May 31.
Triple-digit temperatures in parts of Texas last week sent energy demand into record territory and electricity prices soaring to nearly $1,500/MWh.
ERCOT, which manages the energy flow for about 90% of the state’s electric load, set multiple records for May peak demand. The first came May 16, when the ISO topped out at 61.5 GW between 5 and 6 p.m., after having reached 61.1 GW the hour before. It upped that mark to 63.7 GW the next day, a 7.5% increase over the previous record of 59.3 GW set last May.
Demand on May 18 peaked at 63.1 GW during the 4-5 p.m. hour.
ERCOT had predicted a May peak demand of 59.6 GW. Demand peaked at 47.9 GW in April, 9.9% below expectations.
The ISO has projected a summer peak of 72.8 GW in August, which would break the 2016 record of 71.1 GW. It says it has 78.2 GW of capacity available, with a planning reserve margin of 11%. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)
Operating reserves dipped to 3 GW on May 16, just above ERCOT’s emergency level of 2.3 GW, but spokesperson Leslie Sopko said the ISO hasn’t issued any emergency alerts or had any issues with reserves or reliability.
“While load has been high, we have had sufficient generation to meet the demand,” she said. “We expect that will continue through the weekend.”
Average prices jumped to $1,488.86/MWh in the interval ending at 4:45 p.m. on May 16. Prices dropped down below $100/MWh by 6 p.m. and did not crack triple digits the rest of the week.
Temperatures approached 100 degrees Fahrenheit in much of the state Friday. They were forecast to drop into the lower 90s and upper 80s over the weekend, before crawling back up to 100 next weekend.
Small Munis File Appeal with Texas PUC
The Small Public Power Group (SPPG) of Texas, comprising eight small municipally owned utilities with peak loads of 1 to 21 MW, filed an appeal on May 14 with the Public Utility Commission over ERCOT’s definition of transmission owner.
It’s the last resort for the SPPG, which has failed to secure approval through ERCOT’s stakeholder process of a revision request that would exempt municipal distribution service providers without transmission or generation facilities from having to procure designated transmission owner (DTO) services from a third-party provider if their annual peak load is less than 25 MW. (See “Small Public Power Group’s Appeal Again Meets Defeat,” ERCOT Board of Directors Briefs: April 10, 2018.)
The PUC has opened a docket in the proceeding (No. 48366) and directed the group, ERCOT, commission staff and market participants to attempt to reach an agreement. The SPPG must file a report on the discussions by July 9.
The group said none of its members have ever been included in the ERCOT load-shed table, and that their load is “so miniscule that it would not materially change anyone else’s load relief share.” Clark Hill Strasburger’s Tom Anson, who represents the SPPG, wrote in the appeal that several members are physically limited in their ability to comply with relevant ERCOT requirements and that the proposed revision “will not, in any way, affect ERCOT’s system reliability.”
“The commission should recognize that ERCOT’s rules do not fit all circumstances, that there is no reliability issue at stake in this special circumstance and that it is appropriate to modify ERCOT’s rules in this special instance,” Anson said.
The proposed change was developed in 2015 to settle the noncompliant status of municipally owned utilities as PUC staff began to look into the issue.
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.
