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. — 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.
