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Power Generated by Natural Gas Set a New Record in July, EIA Says

August 29, 2022

by Peter Maloney
APPA News
August 29, 2022

Electric power generated by natural gas-fired plants hit a record in July, beating the record set in July 2020, according to the Energy Information Administration (EIA).

Gas-fired generation in the lower 48 states hit 6.37 million megawatt hours (MWh) on July 21, 2022, despite relatively high natural gas prices, according to the EIA’s Hourly Electric Grid Monitor.

The previous record, set on July 27, 2020, was reached when natural gas prices were historically low.

Demand for natural gas for electricity generation has been strong throughout July as a result of above-normal temperatures, reduced coal-fired electricity generation, and recent natural gas-fired capacity additions, the EIA said.

Electricity demand usually peaks in the summer because of demand for air conditioning, and this July was especially hot, ranking as the third hottest on record in the United States.

Despite higher prices, electric sector demand for natural gas remains high. This July, the Henry Hub natural gas price averaged $7.28 per million British thermal units (MMBtu). In July 2020, the natural gas at Henry Hub price averaged $1.77/MMBtu.

In June, the EIA said natural gas spot prices would remain high throughout 2022 with a forecast of the Henry Hub price to average $8.71/MMBtu through August.

Higher gas prices usually push electric generators to turn to other fuels, such a coal, but this summer coal-fired plants have not been used as much as in prior summers because of continued retirements of coal-fired plants, relatively high coal prices, and lower-than-average coal stocks at power plants.

In May, coal inventories at power plants averaged 20 percent lower than prior year levels, the EIA said. In December the EIA said coal stockpiles at electric power plants reached their lowest levels since 1978.

Earlier this month, the EIA said increased economic activity and hot summer weather would increase electricity consumption this year by 2.4 percent over 2021 levels, according to the agency’s Short-Term Energy Outlook (STEO).

Possible Extension Of California Nuclear Power Plant’s Operation Gets Closer Look

August 29, 2022

by Paul Ciampoli
APPA News Director
August 29, 2022

A California Senate Committee on Aug. 25 held a hearing on the possible extension of the operation of the Diablo Canyon Power Plant (DCPP), California’s only remaining operating nuclear power plant.

The hearing was held by the California Senate’s Committee on Energy, Utilities and Communications.

In June 2016, California investor-owned utility PG&E said it planned to retire Diablo Canyon nuclear power plant in California under a joint proposal with labor and environmental groups. The California Public Utilities Commission in 2018 signed off on a request by PG&E that it be allowed to retire the Diablo Canyon nuclear plant by 2025. The two units at Diablo Canyon together produce approximately 2,300 net megawatts of power.

A background memo prepared for the hearing by the California Senate Committee noted that in late April of this year, California Governor Gavin Newsom commented on the possibility of extending operations of the DCPP, as well as natural gas plants that like DCPP are subject to retirement due to State Water Board regulations regarding once-through-cooling facilities that impacts ocean water and marine life.

“Since then, there have been a number of news reports and a Joint Agency Workshop as recent as two weeks ago to discuss the need, option, and hurdles to extending operation of DCPP,” the memo noted. “The Newsom Administration has noted the opportunity to secure federal funding from the U.S. Department of Energy’s implementation of the Infrastructure Investment and Jobs Act, specifically a pending September 6th application deadline for currently operating nuclear facilities.”

Newsom recently proposed to extend operations of the DCPP.

In a presentation at the hearing, Ana Matosantos, cabinet secretary to Newsom, said that the DCPP proposal creates the conditions for an extension of Diablo Canyon “for the shortest amount of time necessary to be able to maintain the goal of reliability and continuing to move forward on our transition.” She said that proposed extension is for a five-year period with the possibility of revisiting that duration.

Maureen Zawalick, Vice President of Decommissioning and Technical Services at Pacific Gas and Electric Company (PG&E), said at the hearing that an extension of the nuclear plant would require a number of federal and state regulatory approvals.

“There are also some critical near-term activities we would have to quickly undertake to make a viable option for the state including funding, fuel purchasing and used fuel management,” she said. “The fuel purchasing and used fuel management take about an 18 month to two-year lead time. And we also need to be ramping up a project team to support the NRC license renewal application.”

Other witnesses at the hearing included Hunter Stern, Business Representative, International Brotherhood of Electrical Workers, Local 1245; Ralph Cavanagh, energy Program Co-Director, Natural Resources Defense Council; Bruce Gibson, Supervisor, Chair of the Board, County of San Luis Obispo; Kim Delfino, Representative, Defenders of Wildlife and the California Coastal Protection Network and Mark Toney, Executive Director, The Utility Reform Network.

Meanwhile, a group of California lawmakers this month unveiled a proposal that “would reject Gov. Gavin Newsom’s plan to extend the lifespan of the state’s last operating nuclear power plant — and instead spend over $1 billion to speed up the development of renewable energy, new transmission lines and storage to maintain reliable power in the climate change era,” the Associated Press reported.

California mayors send letter to Newsom

Also this month, the mayors representing nine cities on California’s Central Coast sent a joint letter to Newsom on Monday sharing policies that they are requesting Newsom include in any legislation that explores the extension of Diablo Canyon Power Plant’s operations.

Officials said that the goal of the letter is to help shape the legislation with a set of guiding principles that include, among other things, ensuring the safe operation of the power plant, limiting the term of the extension and tying it to making sure the state has enough renewable energy and battery storage to replace the power plant when the license extension expires and finding a safe solution for the long-term storage of the spent fuel that is currently being stored at DCPP.

The letter is available here.

Ariz. Public Power And Cooperative Groups Urge PG&E To Extend Nuclear Plant’s Operating Life

In a June 2022 letter to Patricia Poppe, CEO of PG&E, officials with the Irrigation & Electrical Districts’ Association of Arizona (IEDA), the Arizona Municipal Power Users’ Association (AMPUA) and the Grand Canyon State Electric Cooperative Association (GCSECA) made the case for extending the life of the California nuclear power plant Diablo Canyon Power Plant past its existing license.

The letter was signed by Ed Gerak, executive director of IEDA, AMPUA’s Russell Smoldon, and Dave Lock, CEO of GCSECA.

“While we understand that the history of the plant is long and complicated, we hope that you will agree that the benefits of extending the operating license outweighs the cons,” they wrote.

California Approves Rules Requiring All New Cars To Be Zero Emission By 2035

August 28, 2022

by Peter Maloney
APPA News
August 28, 2022

The California Air Resources Board last week approved a rule that requires all new cars and light trucks sold in California will be zero-emission vehicles (ZEVs), including plug-in hybrid electric vehicles, by 2035.

The Advanced Clean Cars II (ACCII) rule establishes a year-by-year roadmap that codifies the light-duty vehicle goals set out in Governor Gavin Newsom’s Executive Order N-79-20.

The ACC II rule is the second phase of California’s Advanced Clean Cars Program adopted by CARB in 2012 that was designed to bring together CARB’s passenger vehicle requirements to meet federal air quality standards and to support AB 32, the law that called for greenhouse gas emissions to be reduced to 1990 levels by 2020, which was achieved in 2016. ACC II is also “a major tool” in the effort to reach the SB 32 target of reducing greenhouse gases an additional 40% below 1990 levels by 2030. SB 32, ratified in 2016, amended the goals of AB 32, which was passed in 2006.

ACC II applies to automakers, not dealers, and covers only new vehicle sales. It does not affect existing vehicles on the road, which will still be legal to own and drive.

The rule accelerates requirements that automakers deliver an increasing number of zero-emission light-duty vehicles each year beginning in model year 2026. Sales of new ZEVs and plug-in hybrid electric vehicles will start with 35 percent that year, build to 68 percent in 2030, and reach 100 percent in 2035.

ACC II specifies that plug-in hybrid, full battery-electric, and hydrogen fuel cell vehicles count toward an automaker’s requirement under the rule, but further specifies that plug-in hybrid electric vehicles must have an all-electric range of at least 50 miles under real-world driving conditions. Automakers will be allowed to meet no more than 20 percent of their overall ZEV requirement with plug-in hybrid electric vehicles.

Battery-electric and fuel cell vehicles will need a minimum range of 150 miles to qualify under the ACC II rules, as well as fast-charging ability and must come equipped with a charging cord to facilitate charging and meet new warranty and durability requirements.

By model year 2030, the rules require vehicles to maintain at least 80 percent of electric range for 10 years or 150,000 miles. That goal is phased in from 70 percent for 2026 through 2029 model year vehicles.

By model year 2031, individual vehicle battery packs must be warranted to maintain 75 percent of their energy for eight years or 100,000 miles with a phase-in schedule of 70 percent for 2026 through 2030 model years.

The rule also calls for ZEV powertrain components to be warranted for at least three years or 50,000 miles.

ACC II also updates regulations for light- and medium-duty internal combustion engine vehicles with lower emission standards that CARB says will “complement more significant emission reductions gained by wider ZEV deployment” and help to “prevent potential emission backsliding by removing ZEVs from the emissions baseline used to calculate new vehicle fleet-average emissions.”

California’s budget includes $2.7 billion in fiscal year 2022-23 and $3.9 billion over three years, for investment in ZEV adoption.

The ZEV budget includes $400 million over three years for the statewide expansion of Clean Cars 4 All, which provides up to $9,500 to low-income drivers who scrap older vehicles to purchase cleaner running vehicles.

The budget also includes $525 million for the Clean Vehicles Rebate Project, which provides up to $7,000 for income-qualified drivers to buy or lease a ZEV.

And the ZEV budget provides $300 million for more charging infrastructure, especially for consumers who do not have a garage.

CARB says its analysis indicates that battery-electric vehicles are likely to reach cost parity with conventional vehicles by 2030 and that by 2035 consumers are likely to realize as much as $7,900 in maintenance and operational savings over the first 10 years of ownership.

CARB said that states that follow California’s vehicle rules are expected to adopt similar regulations. Those states constitute about 40 percent of the nation’s new car sales, CARB said.

Those states are Colorado, Connecticut, Delaware, Maine, Maryland, Massachusetts, Minnesota, New Jersey, New York, Oregon, Pennsylvania, Rhode Island, Vermont, Washington.

APPA Weighs In On National Electric Vehicle Infrastructure Formula Program

August 23, 2022

by Paul Ciampoli
APPA News Director
August 23, 2022

The American Public Power Association (APPA) recently responded to a request for comments from the Federal Highway Administration (FHA) on a notice of proposed rulemaking for the National Electric Vehicle Infrastructure (NEVI) Formula Program. Among other things, APPA commented on the need for flexibility on the number of ports and charging capacity for Electric Vehicle Supply Equipment (EVSE).

A section of the proposed rule includes requirements for the installation, operation, and maintenance of NEVI Formula Program funded chargers. Specifically, this section proposes to require four Combined Charging System charging ports capable of simultaneously charging four electric vehicles, with each port being capable of charging at least 150 kW. This means a NEVI-compliant charging station would be required to serve at least 600 kW at any given time. 

APPA noted in its Aug. 22 comments that public power utilities are already actively working with their communities to advance transportation electrification. However, “this level of new load could be a challenge depending on the unique circumstances of the local utility and grid. For some APPA members this additional load could double their current overall load and, even for utilities serving a larger load, charging stations at this capacity level will still require significant and costly utility upgrades to support.”

To address this challenge, APPA offered two recommendations. 

First, APPA recommended providing the maximum possible flexibility in implementing the requirement that NEVI-compliant charging stations include four, 150 kW minimum, charging ports.

It noted that in certain areas with low utilization levels, EV drivers may be fully served by two 150 kW ports in the near-term and additional ports could be added subsequently during the five-year NEVI program. “Additionally, states should be strongly encouraged to include the cost of necessary electric infrastructure upgrades when providing grants to fund NEVI stations.”

Additionally, grant recipients should also be able to futureproof stations and upsize design (lot sizes, transformers, conduit, wire/cable/etc.) to enable rapid deployments of additional chargers at the sites as demand grows, APPA said.

APPA also recommended that stakeholders, including NEVI station owners, operators, and site hosts, talk to utilities early about connecting to the grid. “This engagement will allow public power utilities to plan for future load and any upgrades as well as provide crucial advice on how to deploy this infrastructure.”

The program also that “states must ensure that EVSE is maintained in compliance with NEVI standards for a period of not less than 5 years from the date of installation.” 

APPA “encourages states to require clear, comprehensive, and detailed contractual agreements for any maintenance and operation requirements. For example, contracts should specify turnaround timeframes for maintenance and describe if the scope includes maintenance for operational issues due to theft and vandalism. This is vital to ensuring a positive customer experience, but ongoing and proactive maintenance is also needed to support charger reliability.”  

The FHA also proposes requirements for the workforce installing, maintaining, and operating NEVI-funded EV charging stations, including requirements that all electricians be either certified through the Electric Vehicle Infrastructure Training Program or a graduate from a Registered Apprenticeship Program that includes EVSE-specific training and is developed as part of a national guideline standard approved by the Department of Labor in consultation with the Department of Transportation. 

APPA voiced concerns about this requirement, particularly given the size and scope of the NEVI Formula Program, which aims to deploy 500,000 EV chargers around the country. “This effort will absolutely require an appropriately trained and qualified workforce; however, additional flexibility regarding training specifics will allow more workers to qualify in a timely manner.”

Meanwhile, APPA also expressed concerns about the program’s proposal that NEVI-funding charging stations be required to display and base the price for charging in $/kWh. 

“APPA has concerns with this requirement, particularly that it will limit innovation in pricing from site hosts and other stakeholders. For example, public power utilities have already utilized a variety of billing techniques including price per kWh, price per minute, subscription fees, and connection or idling fees that may be in combination with other fee types.”

APPA noted that an idling fee would encourage responsible EV charging practices and allow for the most efficient use of chargers by the most consumers. Some public power utilities are using time-of-use structures within these billing techniques. “This can help incentivize off-peak charging as well as provide drivers with a more accurate price signal for the cost to charge their vehicle. As not-for-profit entities, the main goal of public power utility rate design is to recover the cost of providing service. It is important that pricing structures for charging infrastructure allow flexibility for owners to recover costs such as installation, maintenance, and make-ready infrastructure upgrades.”

APPA also addressed the question of whether there are factors that could be considered to avoid an instance of charging the consumer too high a price for electric vehicle charging, particularly when demand is high, and supply is low.  

“APPA strongly believes that electric rate design is a state and local decision. Ratemaking at public power utilities is conducted in an open and transparent manner and is subject to approval by the utility’s governing body.”

Supply Chain And The Need For Flexibility

APPA also used its comments to highlight ongoing supply chain challenges facing the electric utility sector.

If supply chain issues persist into the long-term, “they could impact the ability for electric utilities to deploy the infrastructure necessary for the EV charging network envisioned by the NEVI program, as well as many of the other electric infrastructure projects that will be supported by the Infrastructure Investment and Jobs Act (IIJA).”

Implementing federal and state agencies “should consider what tools they can deploy to help the electric industry ensure the supplies and materials, as well as the necessary workforce, are in place to efficiently and effectively make this significant and needed infrastructure investment.”

APPA also said that NEVI grant programs should be designed with flexibility in mind, noting that every community is different and project needs will vary. “Technology is evolving and EV and charging infrastructure usage will change with higher adoption. One-size-fits-all programs will be inaccessible or unworkable for many public power utilities.”

DOE Plans To Offer Funding Opportunities For Hydro R&D

August 23, 2022

by Peter Maloney
APPA News
August 23, 2022

The Department of Energy (DOE) recently issued a Notice of Intent (NOI) for three funding opportunities totaling $28 million to support research, development, and deployment of hydropower, including pumped storage hydropower.

DOE intends to issue funding opportunities aimed at supporting the testing of innovative technologies, development approaches, or construction techniques to reduce time, cost, or risks associated with hydropower and pumped storage hydropower development; conduct studies to further the development and deployment of a permitted pumped storage hydropower project; and seek stakeholder insights to inform hydropower research.

The DOE said the activities should support new hydropower technology deployment, continued pumped storage hydropower project development, and efforts to better understand challenges facing the industry to help achieve the nation’s clean energy goals.

The three proposed funding opportunities are:

The NOI doesn’t specify when the Funding Opportunity Announcements are likely to be released or when applications are due.

Hydropower currently accounts for 31.5 percent of U.S. renewable electricity generation, about 6.3 percent of total electricity generation, and 93 percent of utility scale energy storage comes from pumped storage hydropower, according to the DOE.

U.S. hydropower capacity could expand by nearly 50 percent by 2050, according to the DOE’s Hydropower Vision report.

Florida Public Power Utility OUC Helps To Promote Ocean Conservation And Marine Life

August 23, 2022

by Paul Ciampoli
APPA News Director
August 23, 2022

Nearly 400 tons of concrete will find a new purpose in helping to revitalize marine ecosystems off the coast of eastern Florida after public power utility Orlando Utilities Commission (OUC) recently donated the material to the Starship II artificial reef project in partnership with the Coastal Conservation Association (CCA) Florida, Building Conservation Trust (BCT), Shell Inc. and Volusia County, Fla.

OUC on Aug. 21 transported the concrete from its Indian River Plant in Brevard County to Volusia County via barge.  It was subsequently deployed alongside 25 tons of granite donated by Shell at Volusia County’s newly permitted reef site, located about 2.75 miles offshore of Lighthouse Point Park in Ponce Inlet. Together, the materials were sunk to create a new habitat and refuge for marine life.

Concrete for the reef came from the site of OUC’s St. Cloud Operations & Maintenance Center, which is currently under construction.

This is the second reef created with concrete from the construction site. In 2019, 400,000 pounds of concrete were repurposed as ballast in the sinking of a cargo ship off the coast of Fort Pierce, OUC’s first partnership in an artificial reef project.

In March 2022, OUC donated 50,000 pounds of precast underground utility junction boxes to St. Cloud Fire Rescue to be used in confined-spaces training.

In a few months, the reef will create a live-bottom habitat that will attract and sustain a wide variety of fish, shrimp and crab species for decades, OUC said.

APPA Urges Adoption Of More Narrowly Tailored Approach To Promoting Joint Transmission Ownership

August 23, 2022

by Paul Ciampoli
APPA News Director
August 23, 2022

While it is gratified that a Federal Energy Regulatory Commission (FERC) Notice of Proposed Rulemaking (NOPR) includes an effort to promote joint transmission ownership arrangements, the American Public Power Association (APPA) wants FERC to adopt a more narrowly tailored conditional right of first refusal (ROFR) focused on promoting joint ownership opportunities for public power utilities and other load-serving entities (LSEs).

APPA made this and a series of other suggestions in Aug. 17 comments filed in response to the NOPR, which the Commission issued in April 2022.

BACKGROUND

The proposed reforms outlined by FERC in the NOPR are intended to remedy deficiencies in the Commission’s existing regional transmission planning and cost allocation requirements to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential (Docket No. RM21-17).

The NOPR, which was issued pursuant to Section 206 of the Federal Power Act, builds on FERC Order Nos. 888, 890, and 1000, in which the Commission incrementally developed the requirements that govern regional transmission planning and cost allocation processes to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential.

Of particular importance to many public power utilities, the NOPR seeks to promote joint ownership of transmission facilities by proposing to modify FERC Order No. 1000 to permit incumbent transmission owners to exercise a federal right of first refusal to build new transmission facilities selected in a regional transmission plan for purposes of cost allocation, conditioned on the incumbent transmission provider establishing joint ownership of those facilities.  Order No. 1000 directed public utility transmission providers to eliminate such ROFR provisions from FERC tariffs.

In late 2021, APPA urged the Commission to promote joint transmission ownership through the transmission planning process. APPA’s comments came in response to an advance notice of proposed rulemaking (ANOPR) issued by FERC in July 2021 to reform its transmission planning, cost allocation, and generator interconnection rules.

APPA COMMENTS

In its comments, APPA said it generally believes that the reforms proposed in the NOPR have the potential to improve the regional transmission planning process. 

APPA noted that the NOPR proposes to permit — but not require — the exercise of federal ROFRs “for transmission facilities selected in a regional transmission plan for purposes of cost allocation, conditioned on the incumbent transmission provider with the federal right of first refusal for such regional transmission facilities establishing joint ownership of the transmission facilities.”

APPA “is encouraged that the NOPR includes proposals to promote joint ownership and APPA appreciates the Commission’s efforts in this regard.”

While APPA had not suggested such a conditional ROFR mechanism to promote joint ownership, APPA believes that the conditional ROFR approach, with modifications outlined in the comments, “could effectively achieve the benefits described by the Commission and help ensure planning rules that are just and reasonable and not unduly discriminatory or preferential.”

The elimination of federal ROFRs in Order No. 1000 was intended to promote competition among transmission developers for new projects, and APPA agreed that such competition can be an effective way to restrain transmission costs.  APPA argued, however, that it would be reasonable for FERC to allow a conditional federal ROFR for jointly owned facilities, provided the ROFR is more narrowly tailored to promote joint ownership opportunities for LSEs, including public power utilities.

This revised approach “would be designed to encourage certain joint ownership opportunities that are likely to provide the practical, economic, and public policy benefits that the Commission outlines in the NOPR (as well as other benefits), while avoiding unreasonable and discriminatory outcomes that could flow from the conditional ROFR as described in the proposed rule,” APPA said.

APPA argued that the broad conditional ROFR proposed in the NOPR is unlikely to provide the benefits described by the Commission in proposing to allow ROFRs on a conditional basis.

Under the NOPR’s proposed conditional ROFR framework, the only specific parameters for qualifying joint ownership arrangements would be that:

The Commission makes clear that qualifying joint ownership arrangements could include other incumbent transmission providers, APPA pointed out.

But such a broad approach to qualifying joint ownership arrangements is unlikely to produce the full range of benefits that the Commission describes in the NOPR, it said.

The criteria for qualifying joint ownership arrangements “are so expansive that there is no way to reasonably conclude that they would meaningfully promote the identified benefits,” APPA said.

Moreover, it is also reasonable to expect that one outcome of the Commission’s proposal, if adopted, would be proposed joint ownership arrangements between large, incumbent utility transmission owners, APPA argued. “Such structures are not likely to result in key benefits that the Commission posits would make the conditional ROFR just and reasonable.”

To address concerns that the NOPR’s proposal would not produce the benefits envisioned by the Commission, or would even prove detrimental, the Commission should adopt a more narrowly focused conditional ROFR approach limited to LSEs in the incumbent public utility transmission owner’s footprint, APPA said. 

“Specifically, this approach would be implemented by requiring incumbent public utility transmission owners wishing to invoke the conditional ROFR to offer joint ownership on reasonable terms, at a load ratio share level, to all unaffiliated LSEs in the incumbent transmission owner’s footprint.”

Qualifying LSEs would be those that fit within the definition of load-serving entity in section 217(a)(2) of the Federal Power Act, including public power joint action agencies, which historically have often participated in jointly-owned projects for their public power utility owners.

APPA did not propose to limit this approach to any particular form of joint ownership structure, and existing inclusive transmission-only companies and shared-system arrangements that include qualifying LSEs should also be eligible.

“It is likely that most of the non-affiliated LSEs located in the footprints of incumbent public utility transmission owners will be not-for-profit public power utilities and electric cooperatives,” the trade group said.

Joint ownership of regional transmission facilities by public power LSEs would provide numerous benefits, APPA argued, “including, but not limited to, the benefits discussed in the NOPR.”  These benefits would support a focused conditional ROFR limited to LSEs in the incumbent transmission owner’s footprint, it said.

Public power utilities have participated in jointly owned transmission arrangements for many years, APPA noted, “and these arrangements can provide practical, economic, and public policy benefits for all consumers in the region(s) where a regional transmission facility will be built. Indeed, the Commission has long recognized the benefits of joint ownership of transmission facilities between investor-owned utilities, public power (municipal and joint action agency) and electric cooperatives.”

Public power participation in joint ownership arrangements also provides economic benefits to the public power entities and their ratepayers that can, in turn, benefit the applicable region(s), it added.

Focusing the conditional ROFR on LSE joint ownership is consistent with the requirement in FPA section 217(b)(4) that the Commission exercise its authority “in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of load-serving entities to satisfy the service obligations of load-serving entities,” APPA pointed out. “This approach provides the opportunities the Commission intends for joint ownership arrangements, but in a manner that will ensure the benefits of joint ownership are actually realized.”

The Commission should find that limiting the conditional ROFR to offering joint ownership opportunities to LSEs in the incumbent transmission owner’s footprint is just and reasonable and not unduly discriminatory, APPA said.

APPA also weighed in on numerous other aspects of the NOPR including FERC’s proposal to require public utility transmission providers to implement a new long-term regional transmission planning process.  APPA agreed that such a long-term planning process may help identify cost-effective transmission solutions, but APPA urged the Commission to adopt a number of modifications and clarifications to the NOPR to ensure that any final rule is just and reasonable, not unduly discriminatory, and otherwise consistent with FERC’s statutory obligations.

New DOE Program Offers Cybersecurity Assistance To Public Power Utilities

August 21, 2022

by Paul Ciampoli
APPA News Director
August 21, 2022

The Department of Energy’s (DOE) Office of Cybersecurity, Energy Security, and Emergency Response (CESER) recently launched the Rural and Municipal Utility Advanced Cybersecurity Grant and Technical Assistance Program.

The program will prioritize rural, municipal, and small investor-owned utilities that have limited cybersecurity resources, are critical to the reliability of the bulk-power system, and/or those that own defense critical electric infrastructure. 

CESER will develop the program in coordination with other government partners, leveraging the $250 million made available in Section 40124 of the Bipartisan Infrastructure Law.

On Aug. 18, CESER hosted the first in a series of listening sessions for eligible entities and other interested parties.

CESER will collect input from the listening sessions to create a comprehensive program plan that bolsters cybersecurity for eligible utilities based on the needs identified by session participants, DOE said.

A listening session scheduled for Sept. 29 will focus on the unique needs of electric municipal utilities and their key priorities.

Registration will open approximately two weeks before the listening session date. Additional details about this and other listening sessions are available here.

WAPA To Provide Hydropower To Kansas, Nebraska Municipalities

August 21, 2022

by APPA News
August 21, 2022

Eleven municipalities in Kansas and Nebraska and one military installation in Colorado have been approved to receive at-cost federal hydropower from Western Area Power Administration’s (WAPA) Loveland Area Projects starting Oct. 1, 2024.

 It is the largest addition of WAPA customers since the remarketing of Hoover Dam hydropower in 2017, WAPA said on Aug. 18.

Many of the new customers, like our current customers, are small rural entities. Having access to the affordable hydropower resource and transmission services can be a real benefit,” said WAPA Contracts and Energy Services Manager Parker Wicks.

The new customers join 124 existing entities who have renewed firm electric service contracts for Loveland Area Projects hydropower starting Oct. 1, 2024. Under those contracts, customers will receive allocations of energy from 20 federal Bureau of Reclamation hydroelectric facilities in Montana, Wyoming and Colorado for 30 years.

The new customers include nine Kansas municipalities, two Nebraska municipalities and a U.S. Space Force base:

Colorado

Buckley Space Force Base

Kansas

City of Alma

City of Blue Mound

City of Elwood

City of Luray

City of Montezuma

City of Morrill

City of Prescott

City of Robinson

City of Wathena

Nebraska

Village of Paxton

Village of Trenton

In total, the new customers will receive 11,302,438 kilowatt-hours (kWh) of energy in the summer season (April – September) and 9,106,151 kWh in the winter season (October – March). Each new customer will receive a proportional allocation based on their seasonal demand.

To begin receiving federal hydropower in October 2024, the new customers will need to sign a power contract by Dec. 31. Then, they will need to get transmission arrangements in place by summer 2024.

The opportunity to receive new allocations of hydropower arose from a scheduled resource pool under Loveland Area Projects’ current contract terms. The resource pool, which occurs every 10 years, withdraws up to 1% of the marketable hydropower resource from existing customers and makes it available to new customers through a public process.

Entities eligible to apply for new hydropower allocations must be a municipality, rural electric cooperative, irrigation district, public utility district, Native American Tribe or federal or state agency in the designated project area that does not currently receive a federal hydropower allocation. With the exception of Tribes, all entities must also be able to receive the power from WAPA through the power grid.

The next Loveland Area Projects resource pool is scheduled for 2034. The application process would begin 2-3 years before then and would be advertised in the Federal Register.

To learn more about this resource pool, visit the Loveland Area Projects 2025 Resource Pool webpage

DOE Report Provides Guidance On Energy Storage System Evaluations

August 21, 2022

by Peter Maloney
APPA News
August 21, 2022

A new report from the Department of Energy (DOE) provides guidance on how best to evaluate the potential of energy storage systems based on specific use-cases.

The report, Energy Storage Valuation: A Review of Use Cases and Modeling Tools, draws from publicly available tools developed by the DOE and frames their functions and capabilities in the context of three use-case “families.”

The three use-case families of the DOE’s Energy Storage Grand Challenge are:

The DOE report provides a methodology for stakeholders to determine which DOE modeling tool is best suited to value an energy storage system for a specific use-case.

“In addition to the need for cost and performance improvements for storage technologies, there is a need for robust valuation methods to enable effective policy, investment, business models, and resource planning,” the report’s authors wrote.

With respect to that goal, the report identified the high-level objectives for the report: