Salt River Project To Study Low-Carbon Replacement Options For Coal-Fired Plant

May 3, 2022

by Paul Ciampoli
APPA News Director
May 3, 2022

With the coal-fired Coronado Generating Station (CGS) scheduled to close no later than 2032, Arizona’s Salt River Project (SRP) is launching several studies, and working with the local St. Johns community, to investigate possible low- or no-carbon reuses of the plant site.

CGS has a capacity of 773 megawatts (MW), from one 389 MW-unit and one 384 MW-unit.

SRP’s Coal Communities Transition Team has already begun work on a community engagement plan in coordination with the CGS community which consists of four stages, including conducting preliminary assessments of the community, developing economic and workforce plans, executing on the plans and determining post-plant support.

The initial studies into potential sustainable energy options at CGS will help SRP determine what, if any, technologies are viable. Some of the technologies that SRP anticipates researching could include hydrogen generation, solar with battery storage or other storage variations.

In addition, the City of St. Johns, Ariz., has shown an interest in studying the feasibility of transitioning CGS from coal to advanced reactor generation.

Leading these study efforts will be Gateway for Accelerated Innovation in Nuclear (GAIN), a U.S. Department of Energy initiative led by Idaho National Laboratory (INL).

SRP will coordinate with GAIN, which will work with experts at INL and other national laboratories to determine whether advanced nuclear reactors would be feasible at CGS. The findings will be a part of SRP’s study to evaluate options at the site.

The deployment of this technology, if proven viable, would likely have a long-time horizon of 20 to 30 years.

In the years leading up to the full operational shutdown of CGS in 2032, as well as in the years following, SRP will continue engaging with St. Johns and Apache County stakeholders and keep them informed of the results of these studies as they become available, SRP said on April 26.

Washington State Governor Tours Seattle City Light Microgrid Site

May 3, 2022

by Paul Ciampoli
APPA News Director
May 3, 2022

Washington State Gov. Jay Inslee and Seattle Mayor Bruce Harrell recently toured Seattle City Light’s recently completed Miller Community Center Microgrid.

They were guided on the tour by Seattle City Light Energy Innovation and Resources Officer Emeka Anywanwu. 

The tour included a stop inside the center to discuss its importance to the neighborhood and view the artwork installed as part of the project. The group then moved outdoors to the secured area that houses the microgrid control system and battery storage for an in-depth look at the technology behind the project.

The project is a collaborative effort between Seattle City Light and Seattle Parks and Recreation. It was funded in part by a $1.5 million Clean Energy Fund grant from the Washington State Department of Commerce.

The Miller Community Center microgrid brings higher power reliability to the surrounding community by keeping the facility energized during a power outage. It also helps to meet the City of Seattle’s goals by reducing greenhouse gas emissions through renewable (solar) energy and enhances the resiliency of Seattle’s electricity grid.

The project includes the installation of 132 solar panels on the Miller Community Center’s roof, which send energy to a battery storage system. This system provides backup power storage for the community center during emergency events, such as a windstorm or unplanned power outage.

When the electric grid is down, the microgrid generates and supplies power to the community center to keep the center’s services and communications operational. Other energy conservation measures included in the project were improved LED lighting, sensors, and an energy-efficient boiler.

The microgrid’s battery storage system has a total capacity of 200 kilowatts/ 800 kilowatt hours to provide at least 16 hours of backup power for 100% of the loads at Miller Community Center when fully charged. City Light expects the batteries to provide at least 24 hours of power during an outage. Additional power can be captured as the panels will continue generating energy when the sun is up.

Included in the project was a new interior art piece installed through a partnership with the Seattle Office of Arts & Culture and City Light’s 1% for Art Fund. Artist Julia Harrison commissioned the piece with input from the Miller Park community. The artwork combines and celebrates solar energy and community.

Texas City Says Its City Government Is First In The Nation To Mine Bitcoin

May 3, 2022

by Paul Ciampoli
APPA News Director
May 3, 2022

Fort Worth, Texas, on April 26 said it became the first city government in the U.S. to mine Bitcoin.

The pilot program, launched by the Office of Fort Worth Mayor Mattie Parker and the City of Fort Worth in partnership with Texas Blockchain Council, “recognizes the exponential growth of the blockchain and cryptocurrency industries while advancing Fort Worth’s goal of becoming a leading center of tech and innovation,” the city said in a news release.

The Bitcoin mining machines will run 24/7 in a climate-controlled data center located at Fort Worth City Hall, where they will be housed on a private network to minimize security risk, the city said.

Bitcoin mining is the process by which new bitcoins are entered into circulation. “Mining” is performed using sophisticated hardware that solves an extremely complex computational math problem. The first computer to find the solution to the problem receives the next block of bitcoins and the process begins again.

By limiting the pilot program’s focus to three machines, the city said it will achieve the goals of responsibly assessing and executing a municipal Bitcoin mining program at a manageable scale. After six months, the city will evaluate the program.

Based on the number and type of machines being used, the city estimates each will consume the same amount of energy as a household vacuum cleaner.

The nominal amount of energy needed for the program is expected to be offset by the value of Bitcoin mined. Keeping the pilot program small enables the city to learn the potential impact and opportunities for Bitcoin.

The City of Chandler, Ariz., recently began offering cryptocurrency as a payment option for Chandler residents to pay their utility bills.

Berkeley Lab Report Examines Growth Of Hybrid Power Plants

May 3, 2022

by Peter Maloney
APPA News
May 3, 2022

Generation projects that combine solar or wind generation with energy storage are poised to grow exponentially, but the success of those projects will require careful attention to factors such as project configuration and operational strategy, according to a new report from Lawrence Berkeley National Laboratory (LBNL).

At the end of 2021, there were more than 8,000 megawatts (MW) of wind or solar generation connected to storage in the United States, but a much larger number of hybrid projects — 280,000 MW of solar and 208,000 MW of storage – have applied for grid connections, the report, Batteries Included: Top 10 Findings from Berkeley Lab Research on the Growth of Hybrid Power Plants in the United States, said. The report noted that most of the proposals pair energy storage with solar photovoltaic projects.

Even if only a quarter of those projects are able to progress to commercial operation, “they will have big impacts on grid operations,” the authors of the report said in a statement. “While hybridization helps to ease the challenge of balancing variable supply and demand, its relative novelty means that research is needed to facilitate integration and promote innovation.”

In the new report, LBNL summarizes articles it published over the past two years in support of private- and public-sector decision-making about hybrid plants and presents its top ten findings.

Among the findings, LBNL noted that the growth in hybrid projects is being driven by a combination of factors, most notably falling prices and the incentives and synergies of co-locating energy storage with variable generation projects.

The report noted that power purchase agreement prices have fallen from $40-$95 per megawatt hour-photovoltaic (MWh-PV) in 2017 to $30-$75 per MWh-PV in 2021, and while the cost of adding storage to a solar project is around $10/MWh-PV for a battery sized to 50 percent of a project’s solar power capacity, the combination yields gains between $8/MWh-PV and $21/MWh-PV, depending on region and dispatch assumptions.

The authors also noted that hybrid projects can benefit from tax credits, construction cost savings, and more flexible generator dispatch, but suffer from siting constraints that make them “sensitive to local market conditions and configuration choices.”

For instance, LBNL found that, in some instances, the capacity contribution of hybrid plant is “less than the sum of its parts,” as the shared infrastructure of a hybrid project can reduce its capacity value.

Likewise, while hybrid plants can gain value from participation in ancillary service markets, at least in some markets, that value can be “fleeting” because those markets are thin and could become saturated by energy storage projects already in the interconnection queue. Expecting additional ancillary service revenues to offset declining energy and capacity value “may be a risky strategy for wind and solar hybrid project owners,” the report said.

Overall, “while hybridization of power plants provides opportunities to ease the challenge of balancing intermittent renewable resources, its relative novelty means that research is needed to facilitate integration and promote innovation,” the report’s authors said.

LBNL has scheduled a free webinar on May 5 for a closer look at its findings.

House Bill Aims To Address Increasing Electricity Demand Of EV Charging Infrastructure

May 3, 2022

by Paul Ciampoli
APPA News Director
May 3, 2022

U.S. Representatives Sean Casten, D-Ill., and Paul Tonko, D-N.Y., recently introduced the Electric Vehicle Grid Readiness, Improvement, and Development Act (EV GRID Act) to meet the increasing electricity demand of electric vehicle charging infrastructure.

The $7.5 billion for EV charging infrastructure in the Infrastructure Investment and Jobs Act was “a major step for EV investments and grid preparedness, but significant questions remain unanswered on how to ensure chargers can be interconnected with the grid,” Casten’s office said in a news release, noting that, for example, a Level 3 charger needs 350-kilowatts of electricity, “and in rural areas this would be a huge undertaking.”

The EV Grid Act would direct the Department of Energy to conduct a study and develop a plan related to the ability of the electric system to meet the electricity demand of new electric vehicle charging infrastructure.

The study would anticipate the growth in the use of electric vehicles necessary to meet President Biden’s climate goals, and would assess how much additional electrical generation, transmission, and distribution capacity will need to be added to the electric system to meet demand.

Through assessing various demand scenarios, DOE would then identify geographic areas in which greater investment in the electric system would be necessary to ensure chargers could be prevalent and connected to the grid.

After the study is published, the DOE would then work in coordination with the Building a Better Grid Initiative of the Office of Electricity and the Vehicle Technologies Office of the Office of Energy Efficiency and Renewable Technology to develop a plan on how DOE can assist the electric system in meeting the anticipated increase in demand. Congress would then be provided with recommendations on how these goals can be supported legislatively.

Tonko is Chair of the House Energy and Commerce Subcommittee on Environment and Climate Change.

Click here for resources and opportunities for public power tied to the infrastructure law curated by the American Public Power Association.

TVA, Canada’s Ontario Power Generation Partner On Small Modular Reactors

May 2, 2022

by Paul Ciampoli
APPA News Director
May 2, 2022

Canada’s Ontario Power Generation (OPG) and the Tennessee Valley Authority (TVA) will jointly work to help develop small modular reactors (SMRs), TVA recently announced.

The agreement allows TVA and OPG to coordinate their explorations into the design, licensing, construction and operation of small modular reactors.

Both are also actively exploring SMR technologies. OPG is moving forward with plans to deploy an SMR at its Darlington nuclear facility in Clarington, Ontario. The Darlington site is the only location in Canada licensed for new nuclear with a completed and accepted Environmental Assessment.

TVA currently holds the only Nuclear Regulatory Commission Early Site Permit in the U.S. for small modular reactor deployment at its Clinch River site near Oak Ridge, Tenn.

No exchange of funding is involved. However, the collaboration agreement will help OPG and TVA reduce the financial risk that comes from development of innovative technology, as well as future deployment costs.

Other Public Power Utilities Also Pursuing SMRs

Carbon Free Power Project, LLC (CFPP), a wholly owned subsidiary of Utah Associated Municipal Power Systems, continues to advance the development and deployment of its first-of-a-kind SMR nuclear plant at the U.S. Department of Energy’s Idaho National Laboratory near Idaho Falls, Idaho. 

CFPP successfully and safely completed field investigation activities at the site in January 2022, a major milestone for the project.  

In May 2021, NuScale Power and Washington State’s Grant County Public Utility District on May 26 announced the signing of a memorandum of understanding to evaluate the deployment of NuScale’s SMR technology in Central Washington State.

Public Power Utilities Well Positioned To Weather Cyberattacks: Fitch Ratings

May 2, 2022

by Paul Ciampoli
APPA News Director
May 2, 2022

Public power utilities are well positioned to weather cyberattacks “due to the electric sector’s years of attention to cyber threat mitigation and regulatory requirements, which offers a heightened level of protection relative to other infrastructure assets,” Fitch Ratings recently said.

The rating agency on April 21 noted that federal warnings of cyberattacks targeting U.S. critical infrastructure coincide with news reports of probing of the Texas energy infrastructure, which can be used to scan and monitor networks for weaknesses. “Risks are amplified, and increased information technology investment and spending will be necessary,” Fitch said.

The rating agency noted that the Department of Energy (DOE), Cybersecurity and Infrastructure Security Agency, National Security Agency, and the FBI jointly released an alert in mid-April to warn that certain advanced persistent threat actors are capable of gaining full system access to multiple industrial control systems (ICS) and supervisory control and data acquisition (SCADA) devices using custom-made tools that target ICS/SCADA.

“Electric utilities are exposed to these threats as they use ICS to connect into the electric grid and SCADA to gather and process data from substations. Events caused by operating technology (OT) breaches can threaten human safety and the availability of essential assets and are much more severe than IT breaches,” Fitch said.

The costs to maintain and update cybersecurity will rapidly increase to keep pace with elevated ICS threats amid geopolitical tension, the rating agency said. “System lifecycles are decreasing along with rapid evolution of technology and sophistication of cyber intrusions. Strengthening of cyber hygiene culture through investment in human capital and technology is critical to continue effective mitigation of fast-evolving” threats from advanced persistent threat actors.

Fitch also said that electric utility critical assets have been hardened by over a decade of compliance with the North American Electric Reliability Corporation’s critical infrastructure protection mandatory cyber security standards.

Moreover, the renewed emphasis on partnerships as threats increase “is supported by platforms allowing utility operators to share cyber threats in real time without compromising competitive or sensitive information,” Fitch said.

Public power groups such as the American Public Power Association and the Large Public Power Council provide their members with cybersecurity support programs, the rating agency noted, and CISA and the FBI updated the CISA Shields Up program in March 2022, providing best practices, technical guidance, free tools and resources that are available to all organizations.

APPA is helping member utilities across the country create a more resilient and secure electric grid that is prepared for both cyber and physical threats. Public power utilities are working with their communities, states, and the federal government to ensure compliance with stringent security standards and to manage risk. For additional details on how APPA is helping members with cybersecurity, click here.

Fitch said that the ability to protect infrastructure from attacks is considered under Fitch’s U.S. public power rating criteria as part of its assessment of management quality and governance, which is an asymmetric credit factor where weaker characteristics may constrain a rating.

Fitch assesses utilities’ cyber security policies, investment and training, their maintenance of insurance against cyberattacks and their protocols to address cyber incidents.

“No public power ratings are currently constrained by concerns regarding a utility management’s lack of preparation. In the event of a cyberattack, Fitch would assess the effect on financial metrics and performance of halts in service, delays in revenue generation, ransomware payments or unexpected capital costs,” the rating agency said.

DOE Offers Hydrogen Production And Storage Facility $504.4 Million Conditional Commitment

May 2, 2022

by Darrell Proctor
POWER Magazine
May Issue, 2022

Equipment from both renewable and thermal energy power plants is finding new life in the recycling market.

Read complete article here: https://www.nxtbook.com/accessintelligence/POWER/power-may-2022/index.php#/p/22

Groups Urge FERC To Hold Off On Dynamic Line Ratings Requirement Consideration

May 2, 2022

by Paul Ciampoli
APPA News Director
May 2, 2022

The Federal Energy Regulatory Commission (FERC) should hold off on considering a requirement to utilize dynamic line ratings (DLRs) while the power industry implements a closely related ambient adjusted line ratings requirement, the American Public Power Association (APPA) and the Large Public Power Council (LPPC) recently said in joint comments filed at FERC.

The April 25 comments were submitted in response to a notice of inquiry (NOI) issued by FERC earlier this year (Docket No. AD22-5).

The NOI sought comment on whether DLR is needed to ensure just and reasonable wholesale rates.  The Commission also sought comments on (1) whether the lack of DLR requirements renders current wholesale rates unjust and unreasonable; (2) potential criteria for DLR requirements; (3) the benefits, costs, and challenges of implementing DLRs; (4) the nature of potential DLR requirements; and (5) potential time frames for implementing DLR requirements.

APPA and LPPC said that they agree that cost-effective deployment of DLR technology has the potential to improve the economic efficiency and reliability of the grid.

But they strongly recommended that the Commission hold off on considering a requirement to utilize DLRs while the industry implements the ambient adjusted line ratings requirement that was just mandated in FERC Order No. 881.

Issued in late 2021, the final rule reforms both the pro forma Open Access Transmission Tariff and the Commission’s regulations to improve the accuracy and transparency of transmission line ratings, which represent the maximum transfer capability of each transmission line. 

The trade groups said that ambient adjusted line ratings are an element of a DLR system that will test grid operations in similar if less complex ways and promises to capture a significant portion of the benefits offered by substantially more involved and costly DLR systems.   

APPA and LPPC said that the experience their members have had with DLR systems suggests that implementation will be complicated and costly, while incremental benefits vis-à-vis ambient adjusted line ratings are not fully understood.  

“Implementation will involve a complex set of sensors, monitoring systems, communications links and analytics engines, in addition to personnel expert in the administration of these systems. Further, the automation of these systems and the necessary communications links offer new vectors for cybersecurity attacks,” the groups said.

They said that if FERC should decide to proceed with deployment of DLRs, it would be wise to limit the implementation of DLR to congested transmission facilities, with a focus on lines of 100 kV or higher, where consequential benefits are likeliest to materialize.

DOE Offers Hydrogen Production And Storage Facility $504.4 Million Conditional Commitment

April 29, 2022

by Paul Ciampoli
APPA News Director
April 29, 2022

The Department of Energy’s (DOE) Loan Program Office on April 26 offered a conditional commitment for a $504.4 million loan guarantee to the Advanced Clean Energy Storage Project, which would be a first-of-its-kind clean hydrogen production and storage facility capable of providing long-term seasonal energy storage located in Delta, Utah.

The facility will combine alkaline electrolysis with salt cavern storage for grid scale energy conversion and storage using hydrogen as the energy carrier, DOE noted.

The Advanced Clean Energy Storage hydrogen hub was announced in May 2019, and within three years is in the final stages of debt and equity closing.

Currently, the hub has secured all major contracts including offtake; engineer, procure and construct contractors; major equipment suppliers, and operations and maintenance providers.

DOE said that the Advanced Clean Energy Storage project could accelerate the commercial deployment of the clean hydrogen sector as the 220-megawatt electrolyzer bank would be one the largest deployments in the world.

The project could also help reduce curtailment of renewable energy in the Western U.S. by providing long-term energy storage that is currently not available, supporting DOE’s Long-Duration Storage Shot, DOE went on to say.

Participants in the existing Intermountain Power Project (IPP) in Utah have excess supplies of renewable energy, particularly in the spring. This results in the curtailment of renewable energy during those months and a shortage of renewable energy during subsequent months, DOE said.

Advanced Clean Energy Storage would convert that excess renewable energy to hydrogen that can be stored and until needed. This will help to seasonally balance supply with demand and further stabilize the grid, DOE noted.

Utah’s Intermountain Power Agency (IPA), a separate legal entity and a political subdivision of the State of Utah, was organized in June 1977 for the purposes of undertaking and financing a facility to generate electricity — the IPP.

DOE further said that Advanced Clean Energy Storage will convert and store excess electricity to provide the hydrogen fuel to the IPA’s IPP Renewed Project, replacing a coal-fired power plant with a hybrid combined cycle gas turbine capable of operating on hydrogen fuel.

By converting and storing excess electricity via hydrogen to fuel the IPP Renewed Project, Advanced Clean Energy Storage will be able to provide long duration, seasonal storage necessary to support the increasing penetration of intermittent renewable electricity generation.

The IPP Renewed Project is scheduled for start-up in 2025 when existing coal-fueled generating units at the site shut down and will be operating on a 30% hydrogen blended fuel (provided by Advanced Clean Energy Storage). The IPP Renewed Project will use increasing amounts of hydrogen as feedstock, eventually transitioning to 100% hydrogen by 2045.

“While this conditional commitment demonstrates the Department’s intent to finance the project, several steps remain, and certain conditions must be satisfied before the Department issues a final loan guarantee,” DOE said.

DOE noted that it is working to implement the Infrastructure Investment and Jobs Act’s hydrogen initiatives, which includes $8 billion for Regional Clean Hydrogen Hubs.

According to DOE’s Hydrogen and Fuel Cell Technology Office, hydrogen from renewable energy costs about $5 per kilogram. Achieving the DOE Hydrogen Shot’s 80% cost reduction goal can unlock new markets for hydrogen, including energy storage, DOE said.    

A report available to members of the American Public Power Association offers details on where the emerging hydrogen market is in the U.S. and globally, what is driving the growing interest in hydrogen and what obstacles are preventing hydrogen technology from being able to scale-up. The report is available here.