FERC Proposes To Reform Generator Interconnection Procedures
June 20, 2022
by Paul Ciampoli
APPA News Director
June 20, 2022
The Federal Energy Regulatory Commission (FERC) on June 16 issued a Notice of Proposed Rulemaking (NOPR) to reform its generator interconnection procedures and pro forma interconnection agreements to address interconnection queue backlogs.
Although the proposals in the NOPR are not directly applicable to public power transmission owners, public power utilities in regional transmission organization (RTO)/independent system operator (ISO) regions may be subject to the proposed requirements under RTO/ISO tariffs or other governing agreements.
Also, as FERC specifically states in the NOPR, transmission providers that are not utilities subject to FERC’s general transmission jurisdiction (such as public power utilities) would be required to adopt the requirements of the NOPR as a condition of maintaining the status of any safe harbor tariff or otherwise satisfying the reciprocity requirements of FERC Order No. 888.
FERC noted that at the end of 2021, there were more than 1,400 gigawatts of generation and storage waiting in interconnection queues throughout the country. This is more than triple the total volume just five years ago (Docket No. RM22-14-000).
“Projects now face an average timeline of more than three years to get connected to the grid. As the resource mix rapidly changes, the Commission’s policies must keep pace,” it said in a news release.
The proposed rule includes several key areas of reforms.
First, it would Implement a first-ready, first-served cluster study process: Under the proposed first-ready, first-served cluster study process, transmission providers would conduct larger interconnection studies encompassing numerous proposed generating facilities, rather than separate studies for each individual generating facility.
FERC said this approach would increase the efficiency of the interconnection process and help minimize delays. To ensure that ready projects can proceed through the queue in a timely manner, transmission providers also would impose additional financial commitments and readiness requirements on interconnection customers.
The NOPR also aims to improve interconnection queue processing speed.
The NOPR proposes to impose firm deadlines and establish penalties if transmission providers fail to complete interconnection studies on time, except in instances where force majeure is applicable.
Additionally, the NOPR proposes a more detailed affected systems study process, including a specific modeling standard and pro forma affected system agreements. The NOPR also proposes reforms to administratively simplify the process of studying interconnection requests that are all related to the same state-authorized or mandated resource solicitation.
The NOPR also incorporates technological advancements into the interconnection process. It proposes to require transmission providers to allow more than one resource to co-locate on a shared site behind a single point of interconnection and share a single interconnection request. This would create a minimum standard that would remove barriers for co-located resources by creating a more efficient standardized procedure for these types of configurations.
The NOPR also proposes to allow interconnection customers to add a generating facility to an existing interconnection request under certain circumstances without automatically losing their position in the queue. In addition, the NOPR proposes to require transmission providers to consider alternative transmission solutions if requested by the interconnection customer.
It also calls for updating modeling and performance requirements for system reliability.
Specifically, the NOPR proposes certain modeling and performance requirements for non-synchronous generating facilities to address the unique characteristics of the changing resource mix. For example, to ensure that non-synchronous resources are better able to support reliability, the NOPR proposes to require them to continue providing power and voltage support during grid disturbances.
Comments on the NOPR are due 100 days after publication of the NOPR in the Federal Register. Reply comments are due 130 days after publication in the Federal Register.
NREL Report Maps Potential For 3.5 TW Of Pumped Storage Hydropower
June 16, 2022
by Peter Maloney
APPA News
June 16, 2022
There is still the potential for as much as 3.5 terawatts (TW) of 10-hour energy pumped storage hydropower (PSH) in the United States, according to a new report from the National Renewable Energy Laboratory (NREL).
Pumped storage hydropower is “a mature and proven method of energy storage with competitive round-trip efficiency and long life spans” that will make it “crucial to bridge gaps in electricity production as variable wind and solar production continue to comprise an ever-larger portion of the United States’ energy portfolio,” according to the report, Closed-Loop Pumped Storage Hydropower Resource Assessment for the United States.
NREL said it would soon publish a second technical report that would combine the data from the first report with additional resources to “examine how hydropower’s low-cost, flexible energy could support tomorrow’s grid.” Both studies are funded by the Department of Energy’s (DOE) Water Power Technologies Office.
A DOE report last winter found hydropower can be a valuable resource in maintaining bulk power system reliability.
Pumped storage hydropower comprises 23 gigawatts (GW) of the nation’s 24 GW of energy storage capacity, nonetheless, no new large pumped storage hydropower station has been built in the United States since the 1990s, the report noted, adding that “attempts to quantify technical potential capacity from PSH project applications to the Federal Energy Regulatory Commission (FERC) suffer from inconsistent site and cost evaluation methodologies and likely are not representative of all PSH opportunities.”
The NREL study seeks to better under understand the technical potential for pumped storage hydropower development by developing a national-scale resource assessment for closed-loop pumped storage hydropower. The report identifies 14,846 potential sites that could technically support pumped storage hydropower. It also details how much a plant might cost and how much energy it could produce.
Excluding undevelopable lands such as national parks and critical habitat for endangered species, the report found that even with using a conservative minimum head height (the difference in elevation between the two reservoirs), technical potential for pumped storage hydropower sites can be found “broadly across the western United States, the Appalachian Mountains, and the Ozark Mountains, as well as in Alaska, Hawaii, and Puerto Rico.”
To create the maps in the study the NREL researchers fixed parameters like dam height and storage duration. They selected a 10-hour energy storage duration because, they said, it tends to be more cost competitive with 4-hour battery energy storage technologies. The researchers also used their geospatial algorithm to search the country for all possible sites. Users can sort and filter those sites by head height, energy capacity, and cost. NREL plans to update the map to give users more control.
“We want to build an interactive map where you can check boxes on and off to choose between 12-hour or 8-hour storage, 40-meter or 60-meter dam height. Whatever people want,” Stuart Cohen, an NREL model engineer and a co-author on both reports, said in a statement.
The study’s results demonstrate a wide cost distribution and suggest that the most cost-competitive sites could be found where the existing topography supports very high head heights, the report’s authors said. And while these results are promising for the future of PSH in the United States, continued expansion of this work will improve PSH resource characterization, and additional grid modeling will help illuminate its potential future in the U.S. energy portfolio,” they said.
DOE Closes On $504.4 Mil Loan Guarantee For Hydrogen Production And Storage Facility
June 12, 2022
by Paul Ciampoli
APPA News Director
June 12, 2022
The U.S. Department of Energy (DOE) on June 8 announced it closed on a $504.4 million loan guarantee to the Advanced Clean Energy Storage project in Utah, marking the first loan guarantee for a new renewable energy technology project from DOE’s Loan Programs Office (LPO) since 2014.
The loan guarantee will help finance construction of the largest clean hydrogen storage facility in the world, capable of providing long-term low-cost, seasonal energy storage, furthering grid stability, DOE said.
Earlier this year, LPO announced a conditional commitment for a loan guarantee for Advanced Clean Energy Storage.
The facility in Delta, Utah, will combine 220 megawatts of alkaline electrolysis with two massive 4.5-million-barrel salt caverns to store clean hydrogen.
Advanced Clean Energy Storage will capture excess renewable energy when it is most abundant, store it as hydrogen, then deploy it as fuel for the Intermountain Power Agency’s IPP Renewed Project — a hydrogen-capable gas turbine combined cycle power plant that intends to incrementally be fueled by 100% clean hydrogen by 2045.
With the closing of this loan guarantee, LPO now has $2.5 billion in remaining loan guarantee authority for Innovative Clean Energy projects.
Optimizing Power Plant Load Flexibility
June 1, 2022
by Jim Nyenhuis and Ranjit Rao
POWER Magazine
June Issue, 2022
The operating profiles of traditional generators has changed to manage the variability of renewable resources. Several critical processes were not engineered to manage these highly variable operating profiles and the associated transient conditions in an ideal manner, which has a negative impact on efficiency and reliability. Operators should consider applying field-proven advanced model-predictive control solutions to these process areas.
Read complete article here: https://www.nxtbook.com/accessintelligence/POWER/power-june-2022/index.php#/p/40
Extended Calif. Drought Could Cut Summer Generation From Hydropower Nearly In Half
May 26, 2022
by Paul Ciampoli
APPA News Director
May 26, 2022
The extended drought in California could cut the state’s summer electricity generation from hydropower nearly in half compared with normal precipitation conditions, according to an analysis by the U.S. Energy Information Administration (EIA).
EIA on May 26 said that its analysis indicates that hydropower would produce 8% of California’s electricity generation in a drought year, compared with 15% under normal precipitation conditions.
EIA expects that level of decrease in hydropower generation would lead to an 8% increase in California’s electricity generation from natural gas, a 6% increase in energy-related carbon dioxide emissions in the state, and an average 5% increase in wholesale electricity prices throughout the West given the current system configuration.
“California has a diverse electricity fuel mix and is highly interconnected with the regional electric grid, but our study shows that a significant decrease in hydropower generation this summer could lead to higher electricity prices, among other effects,” said EIA Administrator Joe DeCarolis.
Hydropower is typically the third-largest source of electricity in California, but electricity generation from hydropower is highly reliant on snowpack that forms in the winter season.
California’s snowpack was above normal as of December 2021, but it was 40% below normal levels by April 1 of this year, according to EIA.
EIA analyzed six of California’s hydropower facilities, representing 22% of the state’s hydropower capacity, to develop its supplemental outlook. The entire report is available on the EIA website.
Department of Energy Extends Application Deadline For Civilian Nuclear Credit Program
May 21, 2022
by APPA News
May 21, 2022
The U.S. Department of Energy (DOE) on May 18 extended the deadline for applications and sealed bid submissions under the $6 billion Civil Nuclear Credit (CNC) Program that is aimed at supporting the continued operation of U.S. nuclear reactors.
Owners or operators of nuclear reactors most at risk of premature closure due to economic hardship have 47 more days from May 18 to submit applications for certification and sealed bids for credits. The deadline for the first CNC award cycle is now 11:59 p.m. Mountain Time on July 5, 2022.
The first CNC award cycle is open to owners or operators of U.S. nuclear reactors that have already announced publicly their reactor is projected to close prior to September 30, 2026, due to economic factors. This ensures that the first award cycle is available to the reactors most at risk of imminent closure, DOE said. DOE published guidance on how to apply in April 2022.
DOE is simultaneously developing guidance for the second award cycle under the CNC program, which will be open to more reactors. The next opportunity to apply will be in the first quarter of fiscal year 2023.
Additional information is available here.
Public Power Weighs In On Hydropower Licensing Issues At House Hearing
May 19, 2022
by Paul Ciampoli
APPA News Director
May 19, 2022
Rich Wallen, General Manager and CEO of Washington State’s Grant County PUD, recently warned of the negative consequences that could result from the removal of the Lower Snake River Dams in testimony he gave at a House hearing that examined proposed hydropower licensing changes.
Meanwhile, the American Public Power Association (APPA) said in a statement for the record for the hearing that the process for licensing non-federal hydro projects must be streamlined and reformed.
The hearing was held on May 12 by the House Energy and Commerce Committee’s Subcommittee on Energy.
Along with Wallen, other hearing participants were Malcolm Woolf, President & CEO, National Hydropower Association, Tom Kiernan, CEO, American Rivers, Mary Pavel, Partner, Sonosky, Chambers, Sachse, Endreson & Perry LLC, and Chris Wood, President & CEO, Trout Unlimited.
The primary focus of the hearing was to examine hydropower licensing and proposed changes recently put forth by groups involved in the “Uncommon Dialogue” effort, a forum created by the Stanford Woods Institute to bring together stakeholders to develop consensus policy, technology, and investment recommendations related to hydropower, river health, and dam safety.
Grant County PUD owns and operates two Columbia River dams and two smaller hydro generators that have a combined generating capacity of more than 2,100 megawatts. Priest Rapids and Wanapum dams, collectively known as the Priest Rapids Project, are licensed by the Federal Energy Regulatory Commission (FERC).
In his testimony, Wallen noted that the PUD supports H.R. 1588, the Hydropower Clean Energy Future Act, sponsored by Rep. Cathy McMorris Rogers, R-Wash.
The recently completed Columbia River System Operation Environmental Impact Statement studied the environmental, biological, power supply and socioeconomic impacts of the entire Federal Columbia Rivers System Operations.
While one of the proposed alternatives was breeching the Lower Snake River Dams, the conclusion of the study was that the dams play a vital role in the Northwest power system and that their continued operation does not inhibit the existence of endangered or threatened salmon species.
“While we recognize some of the removal efforts contemplated under the Uncommon Dialogue are for non-powered dams, the predominance of dam removal in the dialogue at all is concerning,” Wallen told lawmakers at the hearing.
He pointed out that the Lower Snake River Dams were built to facilitate fish passage and actually achieve spring juvenile survival rates at 96% and summer migrating fish survival at 93%, meeting or exceeding performance standards.
“Nonetheless, some stakeholders push for removal of the Lower Snake River Dams even though the fish in the neighboring undammed rivers are experiencing similar stresses and the fact that only three of the listed species even migrate up the Snake,” Wallen said.
The four Lower Snake River Dams are a critically vital component of the Bonneville Power Administration’s (BPA) low cost, carbon-free power supply, he went on to say.
“To remove the dams would result in massive rate increases to regional supply costs, increases in carbon emissions and increased risk of blackouts,” he said. “Replacement carbon-free resources are not available and cannot be easily or cheaply secured and require overbuild to counteract their intermittency.”
Under this future, the Lower Snake River Dams “will grow in importance, because they can act as giant, clean energy batteries, helping fill in these gaps for wind and solar.”
Wallen said that hydropower “provides dependable and carbon-free generation, when we need it and how we need it.”
While Grant PUD owns and operates its own hydropower dams, “we are concerned about the impact losing the Lower Snake would have for the entire region.”
He noted that the Western Electric Coordinating Council in its 2021 Western Assessment of Resource Adequacy issued a warning that every region comprising the Western grid is facing an abnormal risk of blackouts.
“We are also concerned about the price impacts, as the BPA has forecasted wholesale price impacts of 50% if the dams are removed and replaced with wind or solar plus batteries,” Wallen said. “This price hike could impact Grant PUD customers,” he said, noting that the PUD has priority rights to BPA-provided generation.
“In a carbon-constrained world, hydropower is increasingly vital for its emissions-free generation, load-following capabilities, grid stability and integrating intermittent resources that keep the lights on,” Wallen said.
APPA Statement For the Record
In its Statement for the Record, APPA noted that there is a significant potential for new hydropower to be generated at non-powered dams throughout the country and to increase output at existing hydropower facilities. “But there are excessive barriers to tapping this potential,” it said.
The Federal Energy Regulatory Commission (FERC) is the primary federal agency responsible for the licensing and relicensing of such non-federal hydroelectric projects, “but the process can be lengthy, difficult, costly, and uncertain for applicants,” APPA said.
It noted that under the Federal Power Act (FPA), FERC must establish requirements in conjunction with the license that give “equal consideration” to not only power needs, but also Endangered Species Act requirements, water quality issues, marine navigation, and other public-interest concerns. FERC must carefully evaluate many aspects of a hydropower project, but at the same time, state and federal agencies can impose “mandatory conditions” that FERC cannot balance or modify in the public interest.
“While it is appropriate to consider a broad array of factors, this process must be streamlined and reformed. Critical new additions to existing hydropower facilities are languishing under bureaucratic and often contradictory processes that can span a decade or more or which simply become too costly,” APPA said. “The byzantine licensing and permitting processes are also a significant impediment to simply maintaining existing hydropower capacity.”
Between now and 2030, 281 facilities representing nearly 14 gigawatts of hydropower generation and pumped storage capacity — roughly 30 percent of FERC hydropower licenses — are up for relicensing.
“We simply cannot afford to lose existing hydropower capacity without threatening to miss emission reduction goals and grid resiliency. Congress must streamline the licensing process by establishing FERC as the lead agency, giving it the authority to set and enforce schedules for the issuance of all resource agency authorizations and studies, and ensure any “mandatory conditions” are directly relevant to the project,” APPA argued.
Federal Tax Incentives
APPA said that another significant obstacle to the growth and retention of non-federal hydropower capacity is insufficient federal tax incentives on par with those available to other clean energy resources.
APPA noted that it strongly supports legislation introduced by Senators Maria Cantwell (D-WA) and Lisa Murkowski (R-AK), the Maintaining and Enhancing Hydroelectric and River Restoration Act of 2021 (S. 2306), that seeks to address this issue.
The bill would create a 30 percent tax credit to support upgrades at existing hydroelectric dams for qualified dam safety, environmental, and grid resilience improvements. “Critically, this credit would be available as a direct payment to public power utilities,” APPA said.
This provision is also included in a bill introduced by Representative Annie Kuster (D-NH), H.R. 4375, the Twenty-First Century Dams Act.
“It is critical that this provision be included in any energy tax credit legislation that may be considered this Congress,” the public power trade group said.
“Uncommon Dialogue” Effort
While APPA was not directly involved with the “Uncommon Dialogue” effort lead by the National Hydropower Association and a number of environmental and tribal organizations, it noted that many of APPA’s members are also members of the National Hydropower Association and were engaged as the proposal developed.
While APPA continues to believe that the hydropower licensing process requires more comprehensive reform along the lines of what was included in H.R. 3043 in 2017, “we appreciate the incremental changes included in the group’s recently (April 2022) released licensing reform proposals. We are particularly supportive of the proposed requirement that mandatory conditions under section 4(e) of the FPA be reasonably related to project effects on federal lands.”
With respect to other proposals put forth in by the Uncommon Dialogue group and associated legislation regarding dam removal, APPA said it opposes efforts to remove productive dams that provide, or have the potential to provide, clean and economic hydropower generation.
“Furthermore, proposals to appropriate funding for the Corps, Reclamation, and any other federal agencies for ‘dam related activities’ must include statutory text specifying that this funding cannot be incorporated into the rates paid by federal hydropower customers,” it said.
Federal Hydropower
APPA also said that federal hydropower and the Power Marketing Administrations are critical, though often overlooked, elements of the nation’s power supply.
APPA supports the continued existence and federal ownership of the PMAs and the sale of federally generated hydropower at cost-based rates and “strongly opposes any efforts to disproportionately assign costs to federal hydropower users for which they receive no additional benefits.”
National Hydropower Association
In his testimony at the hearing, the National Hydropower Association’s Woolf said that new and existing hydropower “is at risk due in part to the byzantine licensing and relicensing system.”
He said that the country is at the crest of a wave of hydropower licensing. “At the same time, relicensing takes 7.6 years to complete on average and often takes much longer than a decade.”
A recent industry survey found than more than 40 percent of hydropower industry asset owners said that they were actively considering decommissioning a facility, Woolf noted. “Alarmingly, 58 percent of facilities have submitted license surrender applications to FERC since 2010 including 17 in just the last two years.”
Reform of the hydro licensing process is urgently needed, he said, noting that the National Hydropower Association supports the joint license reform package.
A summary of the proposed changes, as well as the proposed changes to the text of the Federal Power Act (FPA) itself, are available here.
Salt River Project Joins Coalition To Explore Zero-CO2 Strategies, Hydrogen Hubs
May 16, 2022
by Peter Maloney
APPA News
May 16, 2022
Salt River Project is a member of a new coalition formed in Arizona to explore strategies for achieving a carbon dioxide neutral economy in the state, including the creation of a regional clean hydrogen hub.
In addition to Salt River Project (SRP), the coalition includes Arizona Public Service, Tucson Electric Power, and Southwest Gas, as well as Arizona State University, the University of Arizona, and Northern Arizona University.
Together, the coalition members aim to develop a statewide strategy for “deep decarbonization – approaching carbon neutrality for the whole economy.” The coalition also aims to find solutions that help address climate change and sustain Arizona’s economy in a carbon-neutral future.
“This challenge is bigger than any one company or industry. SRP appreciates the support and vision of this diverse set of partners willing to roll up their sleeves, work together and find solutions to become a low-net-carbon Arizona,” Mike Hummel, CEO and general manager of SRP, said in a statement.
In a first step toward achieving its goals, the coalition has established the Center for an Arizona Carbon-Neutral Economy in the Julie Ann Wrigley Global Futures Laboratory on Arizona State University’s Tempe campus where the coalition members aim to begin planning for a regional clean hydrogen hub. While not yet fully defined, the clean hydrogen hub would include hydrogen producers, consumers, and a connected infrastructure.
Used as a fuel, hydrogen releases water, not carbon dioxide as fossil fuels do, so if renewable resources can be used to create clean hydrogen, which can then be stored for use at a later time.
The coalition said it would seek funding for the project under the Infrastructure Investment and Jobs Act that was passed into law in November 20221 and established program guidance and funding for regional clean hydrogen hubs.
In February, the Department of Energy announced two requests for information to collect feedback from stakeholders to inform the implementation and design of the infrastructure law’s Regional Hydrogen Hub and the Electrolysis and Clean Hydrogen Manufacturing and Recycling Programs.
“Hydrogen is a sustainable energy option we are excited to further explore with our industry and research-focused peers in this collaborative coalition,” Kelly Barr, chief strategy, corporate services and sustainability executive at SRP, said in a statement. “It could likely play a significant role in transitioning coal communities to a new economic way of life, while also supporting the grid with clean energy, which are vital initiatives for SRP, Arizona and the entire U.S.”
In March, the governors of Colorado, New Mexico, Utah and Wyoming signed a memorandum of understanding for the development of regional clean hydrogen hubs and to compete jointly for a portion of the $8 billion allocated for hydrogen hubs under the infrastructure law.
Also in March, New York State, Connecticut, Massachusetts, and New Jersey formed a coalition to develop a proposal to become one of at least four regional clean energy hydrogen hubs as designated by the infrastructure act.
Public Power Credit Unaffected by Glen Canyon Dam Drought Measures: Fitch
May 14, 2022
by Paul Ciampoli
APPA News Director
May 14, 2022
Against the backdrop of recent urgent drought response actions at Lake Powell, which are intended to preserve water levels and power generation at the Glen Canyon Dam, the credit effect of generation shortages is limited because the dam constitutes only one of multiple generation sources for public power utilities rated by Fitch Ratings, the rating agency said on May.
Fitch noted that the U.S. Bureau of Reclamation (BOR) recently announced urgent drought response actions at Lake Powell, which are designed to preserve water levels and power generation at the Glen Canyon Dam, the second-largest hydroelectric power source in the Southwest.
“The announced actions will preserve minimum levels of power supply from this low-cost, carbon-free hydroelectric resource for regional public power utilities in the short term. Still, consensus is needed among the entities that rely on Lake Powell for water and power to address declining hydrology in the Colorado River Basin if power generation is to be sustained longer term,” said Fitch.
Reduced hydroelectric output, as a result of the Colorado River Basin drought, is driving replacement power supply of purchasing utilities higher, but the increases are manageable, the rating agency said.
The BOR increased project energy and capacity rates charged to purchasing utilities by 8% and reduced available allocations in December 2021, given the region’s increasingly severe drought conditions.
The BOR indicated it would no longer purchase power in order to firm deliveries to purchasing utilities, given increasing market energy prices in the western U.S., Fitch said.
Utilities rated by Fitch “are absorbing the incremental cost caused by reduced supply in 2022 by replacing the lower generation with additional purchased power costs, increased output from other owned generation, or reduced off-system (optional, non-customer) sales. To the extent the project’s power supply remains curtailed, the replacement costs in relation to overall power supply costs for Fitch-rated public power issuers are expected to be recovered through rate adjustments.”
The Colorado River Storage Project (CRSP), which includes the 1,320-megawattt Glen Canyon Dam power plant, provides cost-based energy supply at typically below market prices to 130 public entity customers: 53 native American tribes, 60 municipalities, cooperatives and irrigation districts, and 17 other entit
Four Fitch-rated utilities receive between 5% and 18% of their total power supply from the project: Colorado Springs, Colorado; Platte River Power Authority, Colorado; Tri-State Generation and Transmission Association, Inc., Colorado; and the Utah Municipal Power Agency, Utah. Two additional rated systems, Fort Collins, Colorado and Provo, Utah, purchase power from these utilities.
“The Glen Canyon Dam constitutes only one of multiple generation sources for the Fitch-rated utilities, limiting the credit effect of generation shortages, even in the event of full cessation of power from the facility,” Fitch said.
But the rating agency said that the reduction of low-cost power supply from Glen Canyon “is just one example of the sector’s broader operating cost pressures. “Additionally, lower generation from Glen Canyon reduces carbon-free electricity as the sector is pursuing cleaner, non-emitting electric sources.”
Glen Canyon Dam, Lake Powell, and the Glen Canyon Dam power plant together form the largest project of the CRSP and are collectively owned and managed by the BOR. The project controls water releases from the Upper Colorado River Basin to the Lower Basin and generates hydroelectric power, accounting for approximately 75% of CRSP’s generating capacity.
Fitch noted that the entire Colorado River Basin is experiencing progressively worse drought conditions since 2000.
The BOR in early May announced drought response actions that it said would help prop up Lake Powell by nearly 1 million acre-feet of water over the next 12 months (May 2022 through April 2023).
On May 3, Lake Powell’s water surface elevation was at 3,522 feet, its lowest level since originally being filled in the 1960s.
A critical elevation at Lake Powell is 3,490 feet, the lowest point at which Glen Canyon Dam can generate hydropower. “This elevation introduces new uncertainties for reservoir operations and water deliveries because the facility has never operated under such conditions for an extended period. These two actions equate to approximately 16 feet of elevation increase,” BOR said.
BOR invoked its authority to change annual operations at Glen Canyon Dam for the first time. The measure protects hydropower generation and the water supply for the city of Page, Arizona, and the LeChee Chapter of the Navajo Nation, it said.
APPA Urges FERC To Ensure Reliable And Affordable Supply Of Natural Gas
May 11, 2022
by Paul Ciampoli
APPA News Director
May 11, 2022
The Federal Energy Regulatory Commission (FERC) should clarify or revise aspects of draft gas policy statements issued in March by FERC that could interfere with FERC’s pursuit of policies that help ensure a reliable and affordable supply of natural gas in order to support a reliable and resilient power grid and reasonable electric rates for consumers, the American Public Power Association (APPA) said.
FERC on March 24, 2022, voted to seek additional comments on two policy statements it issued in February that provide guidance regarding the certification of interstate natural gas pipelines and consideration of greenhouse gas emissions (GHG) in natural gas project reviews.
“Public power utilities across the country continue to reduce their GHG emissions through a variety of means, such as fuel switching to lower-emitting resources, investments in renewable and other non-emitting resources, the integration of distributed energy resources, and a host of energy efficiency measures,” APPA said in comments submitted to FERC on April 25 (Docket Nos. PL18-1, PL21-3).
Public power utilities “also have been reducing GHG emissions by facilitating the electrification of the transportation sector in their communities, and by promoting the electrification of water and space heating, as well as appliances. As new technologies become commercially available and additional investments are made in clean energy technologies, public power utilities will further reduce their GHG emissions,” APPA said.
Meanwhile, natural gas-fired generation continues to play — and is expected to continue to play — an important role in the nation’s resource mix. In its most recent Annual Energy Outlook, the Energy Information Administration projects that natural gas resources will remain relatively constant as approximately one-third of the generation mix at least through 2050. “These resources, moreover, are expected to be critical to the overall reliability of the bulk electric system as the resource mix transitions to more intermittent renewable energy, a point that has been emphasized by the North American Electric Reliability Corporation,” APPA noted.
Public Power Utilities Rely On Gas-Fired Generation
Many public power utilities rely on natural gas-fired generation, either owned or contracted through bilateral or organized wholesale markets, and these utilities continue to have a critical interest in access to reliable and affordable supplies of natural gas.
“Even leaving aside the importance of natural gas to electric reliability, the price of natural gas often directly impacts the wholesale price of electricity, both within and outside the organized wholesale markets, and higher natural gas prices are likely to mean higher electricity bills for public power customers,” the trade group noted.
It said that a reliable and affordable supply of natural gas depends on adequate transportation infrastructure. APPA supports Commission policies that streamline the permitting process for needed interstate natural gas pipeline infrastructure, consistent with the Congress’ principal aim in enacting the Natural Gas Act to “encourage the orderly development of plentiful supplies of . . . natural gas at reasonable prices” and “protect consumers against exploitation at the hands of natural gas companies.”
“It is axiomatic that regulatory predictability and certainty help promote investment in necessary infrastructure; indeed, that is one of the stated purposes of the Commission’s revisitation of its gas pipeline certificate policies. APPA is concerned, therefore, by the degree of uncertainty and opposition that the Draft Gas Policy Statements have engendered among natural gas companies and other key stakeholders,” APPA said.
APPA agrees that it may be appropriate to reassess the Commission’s existing policies for evaluating the need for new pipeline infrastructure, particularly with respect to cases involving precedent agreements with pipeline affiliates, to ensure that costs are not being unfairly shifted to captive customers for unnecessary expansions.
But the Commission’s “proposed shift in focus from the economics of proposed pipelines to a more open-ended public interest balancing, however, could create significant uncertainty for the gas industry in trying to gauge the standards for pipeline approval. Such uncertainty could, in turn, constrain natural gas supply availability, potentially increasing electric prices and degrading grid reliability.”
APPA also said that uncertainty regarding how the Commission’s certificate policy will be applied may also perversely undermine decarbonization efforts by influencing electric utilities to retain older, less efficient generating units that might otherwise be displaced due to concerns about inadequate natural gas infrastructure, “notwithstanding the suggestion that the Commission will consider evidence that a proposed project ‘will displace more pollution-heavy generation sources’ in assessing project benefits.”
In this respect, a policy under which the Commission broadly examines the entirety of a proposal and balances all its benefits against all of its adverse impacts “is likely to leave a great deal of uncertainty in the minds of pipeline developers and their potential electric generation customers.”
APPA also urged the Commission to further consider and clarify the suggestion that the Commission will encourage applicants to mitigate indirect GHG emissions “given the substantial uncertainty that the proposed policy has created for natural gas pipeline companies, and the potential deleterious effects that such uncertainty could have on developing needed pipeline infrastructure.”