New Vermont law offers flexible ratemaking structure for public power utilities
April 30, 2021
by Paul Ciampoli
APPA News Director
April 30, 2021
Vermont Gov. Phil Scott, a Republican, recently signed a bill into law that provides cooperative and community-owned public power utilities with the ability to make minor adjustments to electric rates and provide customers with new, innovative services, the Vermont Public Power Supply Authority (VPPSA) reported on April 30.
The legislation, S.60, which was sponsored by Vermont Sen. Ann Cummings, a Democrat, is the result of collaboration among electric utilities, state utility regulators, and Vermont legislators, VPPSA noted.
Prior to the passage of S.60, all electric utility rate adjustments and pilot programs were subject to formal reviews by state utility regulators. “Often lengthy and expensive, this review process also presents a hurdle to utility innovation,” VPPSA said in a news release.
The new law gives public power utilities the authority to implement rate changes up to 2% each year without undergoing the traditional reviews. It also allows utilities to pilot new services that advance Vermont’s climate requirements without being subject to a formal tariff review.
Utility regulators will maintain oversight under the new flexible ratemaking structure. Utilities must provide written notice to the Vermont Department of Public Service and Public Utility Commission 45 days prior to implementing a new rate or pilot offering.
The rate or pilot will only proceed if regulators do not raise an objection. A full, traditional review of utility rates will be triggered for individual rate increases over 2% or after a utility’s cumulative rate increases reach 10% since the last state review or if a decade has passed since the last state review.
Regulators also have the authority to implement the full review process any time an objection is raised against a utility proposal, VPPSA said.
The law goes into effect July 1, 2021.
VPPSA provides municipal electric utility members with a wide range of services and solutions, including regulatory assistance, financial planning, and power supply.
VPPSA members include Barton Village, Village of Enosburg Falls, Hardwick Electric Department, Village of Jacksonville Electric Company, Village of Johnson Electric Department, Ludlow Electric Light Department, Lyndonville Electric Department, Morrisville Water & Light Department, Town of Northfield Electric Department, Village of Orleans, and Swanton Village Electric Department.
SMUD board of directors approves 2030 zero carbon plan
April 30, 2021
by Paul Ciampoli
APPA News Director
April 30, 2021
The Board of Directors for California public power utility SMUD on April 28 approved a 2030 zero carbon plan for the utility.
The action comes after the board adopted a climate emergency declaration in July 2020 and asked staff to develop a plan to expedite carbon reductions due to the growing threats of climate change, SMUD noted.
SMUD said that over the past eight months, its staff has worked with customers and a variety of stakeholders to develop a plan that relies on:
- Proven renewable technologies like wind, solar, hydroelectric, geothermal and biomass energy, and customer demand response. The plan triples renewable resources and battery storage and expands customer-owned resources such as rooftop solar and battery storage. Today, these resources help SMUD deliver power that is about 50 percent carbon free;
- Exploring and pursuing new and emerging technologies like biofuels, thermal/battery hybrid, pumped hydroelectric storage, carbon capture and storage, power-to-gas, hydrogen and methane, long-duration batteries and compressed air storage;
- New partnerships and business models to pursue emerging technology such as virtual power plants, vehicle-to-grid projects and more to leverage customers’ investments in clean energy to offset the need for energy from conventional gas power plants;
- Aggressively support electrifying buildings and vehicles, because these are the two largest carbon emitting sectors in the state; and
- Retiring, repurposing or repowering SMUD’s natural gas power plants, including the retirement of McClellan and Campbells gas-fired plants by 2025. The 2030 Zero Carbon Plan includes a road map for retiring or refueling SMUD’s remaining plants by 2030, and SMUD will complete a robust reliability study to finalize the schedule.
The plan provides 90 percent of SMUD’s power from renewable sources, including up to an additional:
- 1,500 megawatts (MW) new local utility solar
- 700 to 1,100 MW local batteries
- 300 to 500 MW wind
- 100 to 220 MW geothermal
- 100 MW regional solar
SMUD said that customers will play an important role in the region’s path to zero carbon. Over the next nine years, forecasts show customers will invest extensively in carbon-free energy resources, including 500 to 750 MW of rooftop solar and 50 to 250 MW of customer-owned battery storage, it noted.
“To pay for new technologies and make them available to customers in an equitable manner, SMUD will pursue partnerships, investors and grant funding, while keeping rates below inflation,” it said in a news release.
Paul Lau, SMUD’s CEO and general manager, recently discussed the zero carbon plan in an episode of the American Public Power Association’s Public Power Now podcast.
New Jersey utility regulators approve certificates to support nuclear plants
April 29, 2021
by Paul Ciampoli
APPA News Director
April 29, 2021
The New Jersey Board of Public Utilities (NJBPU) on April 27 approved three-year zero emission certificates (ZECs) for the Hope Creek, Salem One and Salem Two nuclear power plants in the state.
The NJBPU said that the certificates ensure that the plants, which supply the state with over 90 percent of in-state generation and 37.5 percent of its overall in-state energy supply, will remain operational.
Operated by PSEG Nuclear, a subsidiary of investor-owned Public Service Enterprise Group, Salem is located along with Hope Creek Generating Station on a 740-acre site in Salem County, N.J.
PSEG owns 57% of Salem, while Exelon Corporation owns the remaining 43%. Hope Creek is entirely owned by PSEG.
The collection of funds to pay for the credits the NJBPU approved on April 27 will begin immediately and will amount to approximately $100 million in annual subsidies for each plant for three years, at the rate of $0.004 per kilowatt hour.
At the end of three years, the board will reevaluate the program and if more money is collected than needed, those funds will be returned to ratepayers, the NJBPU noted in a news release.
In addition, if the companies receive funding via other state or federal subsidies in the future, those funds will be reconciled against the ZECs and returned to ratepayers, it said.
The NJBPU in November 2019 approved a ZEC program and application process for nuclear power plants.
The creation of the ZEC program was a requirement of legislation signed by New Jersey Gov. Phil Murphy in May 2018. Murphy signed a bill (S-2313) that created a ZEC program to support nuclear generation in the state — the 2,468-MW Salem plant and the 1,240-MW Hope Creek facility.
The application process for the second three-year ZEC eligibility period opened in August 2020. In October 2020, the NJBPU received applications for the Hope Creek, Salem One, and Salem Two plants. NJBPU Staff evaluated the applications for eligibility and ranked the applications.
As part of the evaluation process, the Board published a redacted version of all applications on its website, held public meetings and an evidentiary hearing, opened a public comment period, and provided an independent market monitor and New Jersey Division of Rate Counsel access to confidential financial information in order to assess each application. The public also had access to a redacted analysis completed by Levitan, a consulting firm.
Prior to this, the NJBPU held a public stakeholder input process in July 2020 on the ZEC application form, which was revised from the version used in 2018 during the first three-year eligibility period.
CAISO launches initiative to explore market reforms tied to grid-scale storage growth
April 29, 2021
by Paul Ciampoli
APPA News Director
April 29, 2021
The California Independent System Operator (CAISO) on April 28 launched an initiative to explore market reforms in anticipation of a surge of grid-scale energy storage on its system in the next few years.
CAISO in a news release noted that it is projecting a four-fold increase in the amount of battery storage on its system from late last year to this summer.
At the end of 2020, the ISO had about 250 megawatts (MW) of storage resources — primarily 4-hour batteries — connected to the grid. It currently has about 500 MW on its system and expects to have a total of 2,000 MW by August 1. This rapid pace of growth is expected to continue in the years ahead, the grid operator said.
“Unlocking the full value of energy storage resources requires changes to the ISO market to better align price signals and cost recovery mechanisms with the reliability and operational needs of the grid,” CAISO said.
The ISO said it intends to leverage expertise from across the storage industry and to share its findings through such initiatives as the Global Power System Transformation Consortium that was formally launched in April with the U.S. Department of Energy and utilities.
CAISO publishes issue paper
CAISO on April 28 published an issue paper on possible energy storage enhancements, outlining the current challenges and seeking input on new market mechanisms to fully integrate storage and maximize its use on California’s electricity system.
The grid operator said that the issue paper effectively launches the energy storage enhancements stakeholder initiative process, which will invite feedback from all industry sectors, particularly the storage resource community, on the market redesigns and their effects.
Deadline to register for APPA national conference fast approaching as spots fill up
April 28, 2021
by Paul Ciampoli
APPA News Director
April 28, 2021
The deadline to register for the American Public Power Association’s 2021 National Conference is fast approaching, with available spots filling up quickly.
This year, the National Conference will be held in Orlando, Fla., from June 20-23, followed by a virtual event on July 13-14.
Participants can choose to register for the full conference (including both the in-person event and the virtual event), or just the virtual event.
Registration for the in-person event (full access) is limited to 700 attendees to accommodate social distancing measures. Early registrations are encouraged to ensure a spot. There is no cap on virtual meeting participation.
For the in-person conference, Admiral James Stavridis, USN (Ret.) on June 21 will share how two factors — a new emerging global security environment and the coronavirus — affect geopolitics for the U.S., China, Russia, Europe, and other areas.
Conference breakout sessions on June 21 will include current issues in federal transmission policy, what’s happening in Washington, D.C., and how small utilities navigate change.
The general session on June 21 is a CEO roundtable on resilience and response.
On June 22, breakout sessions include keeping up with climate policy in the Biden Administration, microgrids and creating value from data assets.
“APPA’s National Conference is a great way for members of the public power community to learn about the latest trends and developments in the electricity sector,” said Ursula Schryver, Vice President, Strategic Member Engagement and Education at APPA.
“Having an in-person event in Orlando also provides an excellent opportunity for public power officials at all levels of responsibility to network with their peers,” she added.
Schryver discussed the national conference in a recent APPA Public Power Now podcast.
All participants in the in-person event must agree to adhere to requirements outlined in the APPA Duty of Care Agreement.
Group discounts will be available for organizations that register five or more people, regardless of the format.
Register by May 31 to lock in savings for the in-person and virtual events. Additional details are available here.
Idaho Falls Power, with Idaho National Lab, tests small hydro’s black start capabilities
April 28, 2021
by Peter Maloney
APPA News
April 28, 2021
Idaho National Laboratory (INL), working with public power utility Idaho Falls Power, has completed a series of tests designed to assess how small hydropower plants can provide startup power during outages.
The city of Idaho Falls, Idaho, owns five, small run-of-river hydro plants on the Snake River that, combined, can provide enough power to meet about one-third of the city’s power needs.
After a December 2013 outage left 3,500 residents without power in subzero weather for hours, the public power utility began to explore options that would make the city’s power system more resilient in such an emergency.
Even though Idaho Falls has its own generating plants, they are all low head, low pressure hydro plants. “We assumed the plants would be able to start up on their own in an emergency, but assuming is not knowing,” Ben Jenkins, systems engineer at Idaho Falls Power, said.
In 2016, Idaho Falls and INL began investigating the ability of its generators to start up on their own, known as black start capability, and their ability to island or operate independently of the surrounding grid.
In December 2017, the utility tested its assumptions and found that as it started adding load to its generators, they would become unstable at about 30 or 35 percent of rated capacity. The test found the limits of the utility’s system. “There was plenty of water, but low head machines need the grid to keep them stable,” Jenkins said.
Idaho Falls Power began looking for ways to fix the problem and enlisted the aid of INL, which is based in Idaho Falls and is an Idaho Falls Power customer.
“The INL folks were looking at the larger picture, the larger grid, and we were looking at the local picture,” Jenkins said. “Our needs dovetailed nicely.”
For its part, INL tested the use of ultracapacitors, which can store and discharge large amounts of energy very quickly, to provide pseudo inertia to the generating plants.
The tests demonstrated that “small hydropower plants like Idaho Falls’, combined with integrated energy storage technologies, may prove to be as nimble as natural gas when it comes to load following,” Thomas Mosier, INL’s energy systems group lead, said in a statement.
Idaho Falls Power tested two operational changes. Working with equipment provider American Governor, the utility tested variations in the gates and blade pitch of its hydro plants to find the most efficient and stable configurations.
Idaho Falls Power also tried bringing multiple plants online simultaneously, running nine tests, each with different combinations of operating parameters. “In effect, we were simulating a large plant,” Jenkins said.
“The one big thing we learned, we didn’t even know we were looking for,” Jenkins said. “If all the load is on one plant, it is unstable, but if you bring them all up simultaneously, they overperformed. We got more out of the combined plants than out of each plant individually.”
“We were pleasantly surprised; operational control can make a huge difference,” Jenkins said. If Idaho Fall Power lost power from the grid, it could implement the operational changes and restart its generators and gradually add load and operate in islanded mode.
Operational changes can also be implemented with minimal costs.
The test results have also prompted Idaho Falls Power to look at another form of energy storage, batteries. They can provide “multiple values,” Jenkins said, citing their ability to provide services such as peak shaving in addition to providing generation stability.
Idaho Falls Power is in conversation with INL about batteries, Jenkins said, and, with battery prices coming down, they could become more attractive. “What was financially unattainable two years ago is now becoming viable,” he said. “There could be value we can look at.”
With the testing portion of the collaboration concluding, there is going to be a lot of evaluation of the next few months, Jenkins said. The data collected in the tests will be fed into INL’s digital real time simulators, which can offer insight into how grids will act and react under different conditions. Then, two reports will likely be generated, one simple and another more detailed.
“We are very happy with what we learned from this, and if the information ca be used by other small utilities, all the better,” Jenkins said. “We feel we are part of a bigger involvement. It helps Idaho Falls, but it could have a much broader impact on the national grid.”
Steve Wright to step down as GM of Chelan PUD
April 28, 2021
by Paul Ciampoli
APPA News Director
April 28, 2021
Steve Wright plans to step down from his position as general manager of Washington State’s Chelan County PUD, the PUD said on April 27.
“After eight years it’s time for me to move on and give someone else a chance to run this great utility. My contract with the PUD to serve as the General Manager runs through the end of this year,” he said in a statement. “I have informed the board that I do not intend to serve as the General Manager beyond that.”
He said the primary reason “is simply that it’s been long enough. I’ve spent 40 years in the industry, 20 years in leadership. I want the opportunity to try something new.”
Chelan’s board “has known of my intentions and has had time to make plans. I am announcing early so the board has plenty of time to conduct a full search. Hopefully, there will be time for overlap with a new general manager before I leave,” he said.
Wright currently serves as a member of the American Public Power Association’s Board of Directors and the board’s executive committee.
Experts see cost of wind power declining by nearly 50% by 2050
April 27, 2021
by Peter Maloney
APPA News
April 27, 2021
The cost of wind energy is expected to decline by as much as 35 percent by 2035 and by almost 50 percent by 2050, according to a survey conducted by Lawrence Berkeley National Laboratory.
The experts responding to the Berkeley Lab survey estimated median reductions in the levelized cost of energy (LCOE) for wind power of 17 to 35 percent by 2035 and of 37 to 49 percent by 2050.
Participants in the survey focused on five core LCOE inputs: capital costs, operating expenditures, energy output (capacity factor), project life in years, and financing costs (after-tax, nominal weighted-average cost of capital).
The reductions are driven by larger and more efficient wind turbines, lower capital and operating costs, and other advancements, according to the survey findings, which were published in the journal Nature Energy.
The study summarized a global survey of 140 wind experts who considered three types of wind applications: onshore (land-based) wind, fixed-bottom offshore wind, and floating offshore wind. The anticipated future costs for all three types of wind energy were half of what experts predicted in a similar study Berkeley Lab conducted in 2015.
“Wind has experienced accelerated cost reductions in recent years, both onshore and offshore, making previous cost forecasts obsolete,” Ryan Wiser, senior scientist at Berkeley Lab, said in a statement. “The energy sector needs a current assessment.”
The Berkeley Lab survey complements other cost evaluation methods and sheds light on the uncertainties in those estimates, Wiser said. For instance, cost reductions could be relatively modest, as reflected in the lower end of the estimates, but there is also “substantial room for improvement” with reductions even greater than experts predict. There is a 10 percent chance that cost reductions will be in the 38 to 53 percent range by 2035 and in the 54 to 64 percent range by 2050, the study found.
The experts surveyed also anticipate greater absolute reductions – and more uncertainty – in the LCOE for offshore wind compared with onshore wind but see a narrowing gap between fixed-bottom and floating offshore wind.
The survey also revealed that one of the key drivers in cost reductions is improvements in wind turbine sizes. The average capacity ratings of onshore wind turbines are expected to rise to 5.5 megawatts [MW] in 2035 from 2.5 MW in 2019 as rotor diameters and hub heights also increase.
The experts said they expect offshore wind turbines to get even larger, rising to 17 MW on average in 2035, from 6 MW in 2019.
The experts also said they see floating offshore wind gaining market share, growing from its current pre-commercial state to capturing up to 25% of new offshore wind projects by 2035.
“All else being equal, these trends will enable wind to play a larger role in global energy supply than previously thought while facilitating energy-sector decarbonization,” Joachim Seel with Berkeley Lab and a co-author of the study, said in a statement.
Berkeley Lab took the lead in the study, which was conducted under the auspices of the IEA Wind Technology Collaboration Programme with funding from the U.S. Department of Energy’s Office of Energy Efficiency and Renewable Energy.
Biden Administration takes steps to boost deployment of EVs, chargers
April 27, 2021
by Paul Ciampoli
APPA News Director
April 27, 2021
The Biden Administration on April 22 unveiled a series of actions intended to accelerate deployment of electric vehicles (EVs) and chargers.
Department of Transportation
The Department of Transportation announced the fifth round of “Alternative Fuel Corridors” designations.
This program, created by the FAST Act in 2015, recognizes highway segments that have infrastructure plans to allow travel on alternative fuels, including electricity, a White House fact sheet noted.
The first four rounds of designations included portions of 119 Interstates and 100 U.S. highways and state roads. Round five includes nominations from 25 states for 51 interstates and 50 U.S. highways and state roads.
The cumulative designations (Rounds 1-5) for all fuel types (electric, hydrogen, propane, natural gas) include 134 Interstates and 125 U.S. highways/State roads, covering almost 166,000 miles of the national highway system in 49 States plus the District of Columbia.
Of that total, the Federal Highway Administration has designated EV corridors on approximately 59,000 miles of the NHS in 48 states plus DC.
The DOT also issued a new report clarifying how its programs can be used for EV charging infrastructure. Many existing programs have this as an eligible use and this guidance can expand how many funded entities take advantage of that, the White House noted. “This could increase the use for EV charging infrastructure of $41.9 billion in federal grant funding in 15 specific programs,” the fact sheet said.
Department of Energy
Meanwhile, the Department of Energy (DOE) announced new research funding opportunities on three EV charging related topics:
- $10 million to research, develop, and demonstrate innovative technologies and designs to significantly reduce the cost of electric vehicle supply equipment for DC Fast Charging that will be needed in large number to support high volumes of EVs;
- $20 million to accelerate the adoption of commercially-available plug-in electric vehicles (PEVs) and supporting infrastructure through community-based public-private partnerships that demonstrate PEV technologies (for cars, buses, school buses, trucks) and infrastructure in various innovative applications and share resulting data, lessons learned and best practices with a broader audience; and
- $4 million to encourage strong partnerships and new programs to increase workplace charging regionally or nationally which will help increase the feasibility of PEV ownership for consumers in underserved communities
DOE and the Electric Power Research Institute (EPRI) also announced a national EV charging technical blueprint including fast charging and grid interaction. This blueprint will assess needs in terms of connectivity, communication, protocols from utility down to vehicle, to support electrification of the full vehicle fleet.
In addition, DOE announced that the Idaho National Laboratory (INL) is partnering with global and domestic automakers to analyze anonymous vehicle charging data that describe market-level trends of operation and charging behavior for a large sample of U.S. consumer EVs.
To guide this work, DOE, INL, and automakers formed a working group to provide feedback on INL analysis and modeling efforts.
Biden American Jobs Plan includes investment in EVs
In his American Jobs Plan, President Biden proposed a $174 billion investment in EVs.
Among other things, the plan calls for establishing grant and incentive programs for state and local governments and the private sector to build a national network of 500,000 EV chargers by 2030.
APPA offers resources to members on EVs
The American Public Power Association offers a wide range of resources to its members related to EVs.
For additional information, click here.
Biden unveils new target for U.S. economy-wide net GHG emissions reductions
April 26, 2021
by Paul Ciampoli
APPA News Director
April 26, 2021
President Joseph Biden on April 22 announced a new target for the U.S. to achieve a 50 to 52 percent reduction from 2005 levels in economy-wide net greenhouse gas emissions in 2030.
The announcement was made during the Leaders Summit on Climate that was hosted by Biden and included 40 world leaders and took place over two days with eight sessions.
“America’s 2030 target picks up the pace of emissions reductions in the United States, compared to historical levels, while supporting President Biden’s existing goals to create a carbon pollution-free power sector by 2035 and net zero emissions economy by no later than 2050,” a White House fact sheet related to the announcement said.
Earlier this year, Biden directed the U.S. to rejoin the Paris Agreement. As part of re-entering the Paris Agreement, he also launched a whole-of-government process, organized through his National Climate Task Force, to establish the new 2030 emissions target – known as the “nationally determined contribution (NDC), a formal submission to the United Nations Framework Convention on Climate Change (UNFCCC).
The April 22 announcement was the product of this government-wide assessment.
The Biden administration has not provided a detailed plan on how the overall goal will be met. It seems clear that the Environmental Protection Agency (EPA) will pursue it using the legal authority it has under the Clean Air Act (CAA) and other statutes, but emission reductions are also premised on funding contained in previously announced infrastructure plans.
At present, there are enforceable GHG standards for new fossil fuel-fired electric generating units (EGUs), but it is unclear how the administration will proceed following the vacatur of the Affordable Clean Energy Rule by the U.S. Court of Appeals for the D.C. Circuit. While the D.C. Circuit vacated both the ACE Rule and EPA’s repeal of the Clean Power Plan, upon request, the court issued a partial mandate to stay the vacatur of the Clean Power Plan until EPA can engage in a new rulemaking.
Also unclear is what part of the contemplated 50-52 percent reduction can be achieved through existing statutes and regulation and what part is contingent upon new legislative authority and/or funding.
Additional details on the summit are available here.