Peninsula Clean Energy Enters First Solar-Plus-Storage Power Purchase Agreement
October 1, 2021
by Paul Ciampoli
APPA News Director
October 1, 2021
California community choice aggregator (CCA) Peninsula Clean Energy and Leeward Renewable Energy have entered into a 15-year solar-plus-storage power purchase agreement (PPA) tied to Leeward’s 102-megawatt (MW) Chaparral Solar Facility in Kern County, California.
As part of the agreement, Redwood, Calif.-based Peninsula Clean Energy will also purchase the energy and capacity from Chaparral’s 52 MW (208 megawatt-hour) battery storage system.
Peninsula Clean Energy’s board of directors on September 25 approved the PPA, which is the organization’s first to involve a solar-plus-storage project. The CCA said that the Chaparral project will allow Peninsula Clean Energy to take another step toward its goal of delivering 100 percent renewable energy generation to its customers across San Mateo County and the City of Los Banos, Calif.
Construction of the facility will begin in December 2021 and the project is expected to begin delivering energy to Peninsula Clean Energy by December 2023. Leeward will own and operate the facility.
Peninsula Clean Energy is the official electricity provider for San Mateo County and, beginning in 2022, for the City of Los Banos. Founded in 2016, the agency serves 295,000 customers.
Peninsula Clean Energy is on track to deliver electricity that is 100 percent renewable by 2025 and has earned investment grade credit ratings from Moody’s and Fitch.
The American Public Power Association has initiated a new category of membership for community choice aggregation programs.
Additional information about Leeward is available here.
TVA Plays Key Role In Drawing New Ford EV And Battery Manufacturing Plant To Tennessee
October 1, 2021
by Paul Ciampoli
APPA News Director
October 1, 2021
Ford Motor Company recently announced that it will be locating an electric vehicle (EV) and battery manufacturing plant in West Tennessee at a site certified through the Tennessee Valley Authority (TVA) in Haywood County, Tenn.
This is a $5.6 billion investment — the largest in the state’s history — and will create nearly 6,000 jobs in the area. “TVA is proud to partner with the state of Tennessee, the Tennessee Department of Economic and Community Development and others to bring these jobs to Tennessee,” TVA said.
“Reliable, low-cost, clean energy attracts world-class companies like Ford to the Tennessee Valley,” said TVA CEO Jeff Lyash in a statement. “Bringing jobs and capital investment to this region is what we do at TVA — it’s a fundamental part of our mission — and by helping to bring companies like Ford to this region, we are creating the jobs of the future.”
In an episode of the American Public Power Association’s Public Power Now podcast earlier this year, Lyash discussed TVA’s economic development activities.
TVA said that Ford set high standards in its search for a location for the new production facility and was looking for an energy provider committed to supplying low-cost, low-carbon energy from a reliable, resilient power system. “Tennessee checked those boxes because of TVA, which has one of the nation’s largest, most diverse, and cleanest generation portfolios,” TVA said.
TVA noted that it has been working with the state and others on this effort for more than year to ensure the site is suitable and to show that reliable, clean and low-cost TVA energy will support plant operations.
“TVA Economic Development works to attract new jobs and investment to the Valley, engages with existing industries, and serves with its partners to help foster economic growth,” said Ashton Davies, a spokesperson for TVA.
“To that end, the Economic Development team partners with state, regional and local economic development partners to facilitate site-selection services for companies looking to locate or expand in the seven-state Valley region,” she said.
TVA worked with Ford to provide solutions to meet the company’s sustainability and project needs, Davies said, adding that TVA’s carbon strategy goals align with Ford’s and in partnership with TVA’s local power companies, “we are able to deliver reliable low-cost, sustainable energy.”
TVA has already helped to attract more than $8.2 billion to the Tennessee Valley region for EV and battery manufacturing, which has helped create almost 4,600 EV-related jobs.
TVA is also partnering with the Tennessee Department of Environment and Conservation, local power companies and third parties to begin building a fast-charging network across Tennessee and it has partnered with other utilities to be a founding member of the National Electric Highway Coalition.
In August, TVA announced a plan to convert its entire fleet of passenger cars and at least half of its own pickup and light cargo trucks to EVs by 2030.
OUC Completes Purchase Of 510-Megawatt Power Plant
September 30, 2021
by Paul Ciampoli
APPA News Director
September 30, 2021
Florida public power utility Orlando Utilities Commission (OUC) on Sept. 28 completed its purchase of the Osceola Generating Station, a 510-megawatt (MW) single-cycle natural gas-fired power plant located near Harmony in Osceola County.
OUC announced plans to purchase the facility last month.
OUC noted that the nearly $100 million deal to purchase and upgrade the inactive plant from Genova, a Texas-based private ownership group, does not change OUC’s commitment to net zero CO2 emissions as outlined in its Electric Integrated Resource Plan (EIRP), the utility’s 30-year energy roadmap.
The acquisition enables OUC to retire its oldest coal-fired power plant, Stanton Unit 1, which went into operation in 1987 at the Stanton Energy Center in east Orange County, instead of converting it to natural gas as stated in the EIRP.
Unit 1’s retirement date has not been determined, but OUC remains committed to significantly reducing coal fired generation no later than 2025 and eliminating it no later than 2027, the utility said.
The 20-year-old Osceola plant is comprised of three separate turbines, known in the industry as “peakers,” which can be powered up or down in just minutes. This capability will be used to mitigate fluctuations in solar energy production.
OUC is aggressively increasing its reliance on solar energy, with plans to boost capacity to power 50,000 typical residential homes by late 2023.
“Acquiring the Osceola Generating Station provides OUC with an extra layer of resiliency because it’s equipped with emergency backup fuel, a critical resource to have on hand in case of fuel supply disruptions and is more cost effective for OUC’s customers than converting and operating Stanton Unit 1,” OUC said.
“As we move forward with our clean energy transition, ensuring operational flexibility is essential to maintaining reliability, resiliency, and affordability for our customers,” OUC General Manager & CEO Clint Bullock said in a statement. “We are also committed to continued investments in solar and energy storage. This purchase of peaker generator units positions us to better manage the solar production fluctuations caused by cloud cover in Florida.”
Under the EIRP, OUC plans to increase the use of renewable energy resources and encourage conservation to reach net zero CO2 emissions by 2050, with interim carbon emissions reductions of 50% and 75% by 2030 and 2040, respectively.
APPA To Assist Public Power Utilities With Energy Storage Under DOE Funding
September 29, 2021
by Paul Ciampoli
APPA News Director
September 29, 2021
The American Public Power Association (APPA) will bring together public power utilities to facilitate discussion, evaluate opportunities, and define barriers to integrating energy storage technologies with power plants thanks to funding it has received from the Department of Energy’s (DOE) Office of Fossil Energy and Carbon Management (FECM). APPA will also work with DOE and other stakeholders to mitigate these barriers.
The cooperative agreement issued with the award “will support the development of tools, educational resources and training in long-term planning and policy analysis to improve the conditions of frontline communities impacted by the legacy of fossil fuel use and support a healthy transition to a clean energy economy,” DOE said.
APPA will also develop educational resources, publications and technical tools for public power utilities that will enhance their ability to explore and implement energy storage projects. “This work will directly benefit public power utilities, as well as the customers and communities that rely on them to ensure regional grid stability,” DOE noted.
“Integration of new resources can be leveraged to enhance the resilience of a public power utility,” said Nathan Mitchell, Senior Director of Operations Programs at APPA. “Being knowledgeable and prepared for this energy transition will help position public power utilities to meet the needs of their customers with high resilience and low emission energy delivery systems.”
He noted that energy storage is a developing technology and some public power utilities have utilized it for the benefit of their city and customers.
For example, Sterling Municipal Light Department (SMLD) in Massachusetts in 2019 marked a major milestone related to the department’s two energy storage systems. In March of that year, SMLD celebrated over $1 million in avoided costs to the light department, thanks to the two systems.
APPA plans to utilize the lessons learned from these and other energy storage installations to inform the work of a new energy storage working group to analyze the feasibility of energy storage at fossil fuel plants to enhance resiliency and lower emissions. DOE will provide $100,000 per year for five years, while APPA will provide $25,000 of in-kind cost share per year for five years, for a total value of $625,000.
DOE’s National Energy Technology Laboratory (NETL) will serve as the contracting authority for the cooperative agreement.
NYPA Selects Developer for Solar Arrays To Supply To Empire State Plaza
September 29, 2021
by Vanessa Nikolic
APPA News
September 29, 2021
New York State’s Office of General Services (OGS) and the New York Power Authority (NYPA) recently selected a developer for several remote solar arrays that will help power the Empire State Plaza, a complex of several state government buildings in downtown Albany.
The solar arrays, which will be located in central New York’s Oneida County, are part of an extensive energy efficiency plan for the Empire State Plaza. The plaza plans to follow the state’s goal of reaching 100% renewable energy by 2040.
OGS and NYPA have selected DG Development & Acquisitions, an Albany-based subsidiary of NextEra—a leader in wind and solar energy production—to develop more than 30 megawatts of solar generation near the former Oneida County Airport in Oriskany, with the power benefiting the plaza in Albany.
Officials said the land near the former airport was selected due to its size of about 1,100 acres.
NYPA president and CEO Gil Quiniones said the project is a key component of OGS’ and NYPA’s plan to improve reliability and sustainability at the plaza.
“The development of this massive solar project in Oriskany will be the largest concentration of distributed-scale solar generation in New York State, providing a significant benefit to the state and the Empire State Plaza in Albany,” Quiniones said.
In 2019, NYPA and OGS completed a thorough evaluation of energy options for the Empire State Plaza. The two entities worked together to conduct a series of technical reviews, several community listening sessions, and meetings with neighborhood associations.
The solar array development is currently in the design phase. The installation of the arrays is expected to begin in 2022 and end in 2023.
In addition, more than $16 million in LED lighting fixtures will be installed throughout the complex to reduce energy use.
OGS and NYPA have additional plans to conduct a comprehensive energy audit of the plaza to determine what further projects need to be taken into consideration, and continue to align operations with the state’s long-term environmental goals.
FERC And NERC Offer Recommendations In Preliminary Report On Cold Weather Event
September 29, 2021
by Paul Ciampoli
APPA News Director
September 29, 2021
Staff from the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) recently provided a report that includes preliminary findings and recommendations related to the February 2021 cold weather event that impacted the Electric Reliability Council of Texas (ERCOT), Southwest Power Pool (SPP), Midcontinent Independent System Operator (MISO), and other regions.
FERC and NERC staff offered details on the report at FERC’s monthly meeting on Sept. 23.
The report reviews what happened during the freeze and outlines a series of recommendations, including mandatory electric reliability standards, to prevent its recurrence.
Following the staff presentation, FERC Chairman Richard Glick noted that 2011 FERC/NERC report released after a prior cold weather event that recommended mandatory weatherization requirements for electric generation facilities.
“But somehow that recommendation was eventually watered down to guidelines that few generators actually followed,” he said.
“Today’s report again recommends that generation facilities be required to winterize with a number of specific related recommendations,” Glick noted.
“I guarantee you that this time FERC will not permit these recommendations to be ignored or watered down,” he said.
Glick also said that it is “becoming increasingly apparent that electric grid reliability depends heavily on the reliability of natural gas production and delivery systems.”
Noting that the electric sector has been operating under a mandatory reliability regime since 2005, Glick said that “it is worth exploring whether additional actions may be necessary to enhance the reliability of the natural gas sector to address threats posed by both extreme weather and cyber or physical attacks to pipelines and other gas facilities.”
The February freeze triggered the loss of 61,800 megawatts of electric generation, as 1,045 individual generating units experienced 4,124 outages, derates or failures to start. It severely reduced natural gas production, with the largest effects felt in Texas, Oklahoma and Louisiana, where combined daily production declined to an estimated 20 billion cubic feet per day, FERC noted. That is a reduction of more than 50 percent compared to average production from February 1-5.
The FERC/NERC assessment points to freezing of generator components and fuel issues as the top two major causes of generator outages, derates or failures to start.
The identified causes in the preliminary report affected generating units across all fuel types. Of the 1,045 generating units affected, 57 percent were natural gas-fired units that primarily faced fuel-supply challenges.
What Went Right
In terms of what went right during the event, the preliminary report said that SPP, MISO and ERCOT reliability coordinators (RCs) coordinated and communicated well with each other.
It noted that beginning February 8, SPP and MISO begin management-level discussions about the upcoming severe cold weather forecast and natural gas fuel restrictions expected, and beginning February 14, they kept an open communication channel between control rooms throughout the event.
On Feb. 12, SPP began coordinating with ERCOT about which balancing authority would rely on switchable generation that both BAs depend on as capacity resources, the preliminary report went on to say.
“The RCs recognized that all three footprints were simultaneously having emergencies and cooperated to alleviate the most critical conditions first.”
Recommendations
The report offers 28 preliminary recommendations including nine key recommendations. Those key recommendations include changes to mandatory reliability standards that build upon the recently approved standards developed in the wake of a 2019 joint inquiry into a prior cold weather event.
The report also includes five preliminary recommendation areas for further study:
- Black start unit reliability;
- Additional ERCOT connections;
- Potential measures to address natural gas supply shortfalls;
- Potential effect of low-frequency events on generators in the Western and Eastern Interconnections; and
- Guidelines for identifying critical natural gas infrastructure loads
The recommendations also include proposed timeframes for implementation, most of which are either prior to Winter 2022/2023 or Winter 2023/2024.
The presentation of the preliminary findings and recommendations is available here.
The final report will be released in November.
San Francisco Public Utilities Commission Seeks Renewable Energy Supplies
September 29, 2021
by Paul Ciampoli
APPA News Director
September 29, 2021
The San Francisco Public Utilities Commission (SFPUC) is accepting bids for renewable energy supplies that will serve low-income CleanPowerSF customers in San Francisco.
Through a request for offers (RFO), the SFPUC is looking to purchase energy and associated capacity from new renewable energy resources located within the state’s disadvantaged communities (DACs).
These resources will serve two recently announced electricity discount programs that will be offered to eligible CleanPowerSF customers: the CleanPowerSF Disadvantaged Communities Green Tariff and the CleanPowerSF Community Solar Green Tariff.
The CleanPowerSF Disadvantaged Communities Green Tariff program is expected to begin serving customers in early 2022 with renewable energy from an already operating interim resource.
CleanPowerSF plans to transition participating customers to renewable energy produced by a new project located in Northern California as a result of the solicitation.
Eligible customers must live in a state-determined DAC in CleanPowerSF’s service area and must be low-income.
CleanPowerSF expects to serve approximately 1,200 customer accounts through the CleanPowerSF Disadvantaged Communities Green Tariff.
The CleanPowerSF Community Solar program will begin to serve customers by mid-decade. Eligible projects must be solar resources and located in a DAC that is within five miles of subscribing customers.
To be eligible to subscribe, customers must live in a DAC. At least 50 percent of the project’s capacity must be subscribed to by low-income customers, while the remaining 50 percent will be open to all DAC residents.
CleanPowerSF expects to serve about 350 customer accounts with the CleanPowerSF Community Solar Green Tariff program.
More information about the RFO is available at: www.cleanpowersf.org/energyvendors.
CleanPowerSF is a not-for-profit program of the SFPUC. California law allows cities and counties like San Francisco to pool the electricity demand of their residents and businesses, and purchase electricity on behalf of those customers. These programs are called community choice aggregation programs.
CleanPowerSF began serving customers in May 2016, giving residential and commercial electricity consumers in San Francisco the option to have more of their electricity supplied from renewable sources at competitive rates.
Officers Named For APPA’s Business And Financial section, Committees
September 29, 2021
by APPA News
September 29, 2021
New officers for the American Public Power Association’s (APPA) business and financial section and planning committees were named at the closing session of APPA’s 2021 Business & Financial Conference in Denver, Colorado.
Mel Palmer, Manager, Human Resources, Lincoln Electric System, Nebraska will chair APPA’s Business & Financial Section in 2021-2022. Andrew Fusco, Vice President, Member Services and Corporate Planning, ElectriCities of North Carolina is vice chair.
Joe Daggett, Director of Risk Management, WPPI Energy, Sun Prairie, Wisconsin will chair the Accounting & Finance Planning Committee; Laura Gutteridge Años, Manager, Financial Accounting & Reporting, JEA, Jacksonville, Florida will serve as vice chair.
Andrea Simmons, Manager of HR & Administration, Oklahoma Municipal Power Authority, Edmond, Oklahoma will chair the Human Resources Planning Committee and Patricia (Trish) Waugh, Business and Customer Care Manager, Stowe Electric Department, Vermont will serve as vice chair.
Julius Aubain, Chief Information Officer, Virgin Islands Water & Power Authority, St. Thomas, Virgin Islands will chair the Information Technology Planning Committee and Robin Britton, Chief Technology and Security Officer, New Braunfels Utilities, Texas will serve as vice chair. Tony Georgis, Managing Director, Energy Practices, NewGen Strategies & Solutions will serve as an advisory officer.
Carl Baker, Senior Electric Utility Analyst, Lakeland Electric, Florida will chair the Rates & Pricing Planning Committee; Chau Nguyen, Director of Analytical Services, Electric Cities of Georgia, Atlanta, Georgia will serve as vice chair.
Toni Hoang, Enterprise Risk Manager, SMUD, Sacramento, California will chair the Risk Management & Insurance Committee; Heath Silvey, Director – Risk Management, City Utilities of Springfield, Missouri will serve as vice chair.
APPA has been assessing the conference planning committees as part of a larger effort to assess how APPA can better serve its members. APPA will be adjusting some of the conference planning committees to better reflect current issues and to provide more robust programs to its members.
APPA will be combining the Customer Accounting & Services Planning Committee, which is currently part of the Business & Financial section, with the Customer Service Planning Committee, which is part of the Customer Connections section. Next year, the combined Customer Service Planning Committee will meet at the Customer Connections Conference.
For more information on the business and financial sections and committees, contact BusinessandFinance@PublicPower.org.
Salt River Project Unveils Plans For 400-MW Solar Plant
September 28, 2021
by Peter Maloney
APPA News
September 28, 2021
Arizona public power utility Salt River Project (SRP) has announced its largest standalone solar power project to date, a 400-megawatt (MW) facility scheduled to enter operation in 2024.
The CO Bar Solar project is sited on private land in Coconino County, Ariz. Clenara, a subsidiary of Enlight Renewable Energy, is contracted to build and operate the new solar plant. Construction is expected to begin in 2023 and to generate about 550 jobs, many of them local.
The project is the latest in a string of recent announcements aimed at supporting the public power utility’s long-term decarbonization goals.
In May, SRP said it would more than double its 2025 utility-scale solar commitment, raising the goal to 2,025 MW of utility-scale solar power that would be online by the end of fiscal year 2025.
In August, SRP announced three new solar energy plants capable of generating a total of 500 MW. The three projects include two 200-MW solar plants and a 100-MW solar facility. The first project is due online in fall 2022 and the other two will begin construction in 2022. Facebook has agreed to take 450 MW of the output of the projects.
With its commitment to add 2,025 MW of utility-scale solar resources by 2025 and its recent announcement of new solar projects, SRP anticipates that nearly 50 percent of the retail energy it delivers to customers will come from carbon-free resources by 2025, contributing to the utility’s goals to reduce carbon intensity by 65 percent in 2035 and by 90 percent in 2050 from 2005 levels.
SRP is also exploring the use of energy storage to help integrate intermittent solar resources into its grid with the recent announcement of a 25 MW battery storage facility at its Bolster substation as well as deals for solar-and-storage facilities scheduled to come online in June 2023.
NREL, Partners Developing Facility To Test Storage-Renewables Technologies
September 28, 2021
by APPA News
September 28, 2021
With support from the Department of Energy’s Grid Modernization Laboratory Consortium, three national laboratories are developing a variable hybrid power plant with energy storage at the National Renewable Energy Laboratory’s (NREL) Flatirons Campus in Arvada, Colo.
NREL, with its partners, Idaho National Laboratory (INL) and Sandia National Laboratories, will use the FlexPower facility to test hybrid renewable energy.
“This research will help accelerate the adoption of utility-scale variable wind and [photovoltaic] resources by demonstrating how hybridization can smooth the transition to clean energy,” Vahan Gevorgian, NREL’s chief engineer, said in a statement. “For the power grid to economically and reliably integrate large amounts of variable renewable generation, it will require robust energy storage capabilities and a rethinking of the value renewable energy assets bring to the grid.”
The researchers’ underlying thesis is that combining renewable energy sources, such as wind and solar plants, with energy storage can transform those variable resources into fully dispatchable and flexible energy sources capable of operating in day-ahead and real-time energy markets and providing essential reliability and resiliency services to the grid.
The researchers plan to test their thesis with a variety of energy storage systems, including pumped storage hydropower, battery, hydrogen, flow battery, kinetic, and ultracapacitor energy storage. They will also focus on advanced control strategies and resource forecast techniques.
The aim is to be able to use sophisticated control systems to improve the dispatchability and availability of variable generation by taking advantage of the complementary nature of wind and solar resources and increasing capacity factors for renewable projects with minimum or no additional transmission buildup.
With improved forecasting, hybrid plants also should be able to participate in energy and ancillary services markets in the same way conventional generation plants do, NREL said.
The researchers also anticipate that by combining generation, storage, advanced controls, and improved forecasting, operators will be able to achieve economies of scale by sharing infrastructure as well as siting and permitting costs.
They also envision that such hybrid plants would be able to provide a spectrum of essential reliability services as well as new, evolving grid reliability services. As examples they cited self-black starts as well as power system black starts; operation in islanded mode; and participation in power system restoration schemes.
The FlexPower project will provide a test bed for companies and researchers to validate and demonstrate hybrid plant concepts and strategies. The research results will be freely accessible to all stakeholders in the form of public domain information and other assets.
“Hybrid renewable energy plants could introduce the national and global energy sectors to a new and potentially disruptive class of power systems,” Gevorgian said. “The result could be high-value grid services and a more secure and resilient power supply.”