Skip Navigation

California Grid Operator Calls For Electricity Conservation With Forecast Of High Temperatures

September 8, 2021

by APPA News
September 8, 2021

The California Independent System Operator (ISO) called for voluntary electricity conservation on Wednesday, Sept. 8, due to predicted high energy demand and tight supplies on the power grid.

With above-normal temperatures in the forecast for much of California and the West, the power grid operator was predicting an increase in electricity demand, primarily from air conditioning use, it noted on Sept. 7 in issuing a statewide Flex Alert that called for voluntary electricity conservation from 4 p.m. to 9 p.m.

During the Flex Alert time period, consumers are asked to lower their thermostats to 78 degrees or higher, if health permits, and take other voluntary measures that include avoiding the use of major appliances and unnecessary lights.

CAISO noted that in the past, reducing energy use during a Flex Alert has helped operators keep the power grid stable during tight supply conditions and prevented further emergency measures, including rotating power outages.

To take full advantage of all available supply, the ISO also issued a restricted maintenance operation (RMO) for Sept. 8 from noon to 9 p.m., notifying ISO participants to avoid taking grid assets offline for routine maintenance until the RMO is lifted.

Department of Energy Study Maps Out Path For Solar Energy Expansion on U.S. Grid

September 8, 2021

by Paul Ciampoli
APPA News Director
September 8, 2021

With aggressive cost reductions, supportive policies and large-scale electrification, solar energy could account for as much as 40% of the nation’s electricity supply by 2035 and 45% by 2050, according to a study released on Sept. 8 by the U.S. Department of Energy’s (DOE) Solar Energy Technologies Office (SETO) and the National Renewable Energy Laboratory (NREL).

To reach these levels, solar deployment will need to grow by an average of 30 gigawatts alternating current (GWac) each year between now and 2025 and ramp up to 60 GW per year between 2025 and 2030 — four times its current deployment rate — to total 1,000 GWac of solar deployed by 2035. By 2050, solar capacity would need to reach 1,600 GWac to achieve a zero-carbon grid with enhanced electrification of end uses, such as motor vehicles and building space and water heating.

Preliminary modeling shows that decarbonizing the entire U.S. energy system could result in as much as 3,200 GWac of solar due to increased electrification of buildings, transportation, and industrial energy and production of clean fuels.

Study Used Three Core Scenarios

The Solar Futures Study uses a suite of detailed power-sector models to develop and evaluate three core scenarios. The “Reference” scenario outlines a business-as-usual future, which includes existing state and federal clean energy policies but lacks a comprehensive effort to decarbonize the grid.

The “Decarbonization” (Decarb) scenario assumes policies drive a 95% reduction — from 2005 levels — in the grid’s carbon dioxide emissions by 2035 and a 100% reduction by 2050. This scenario assumes more aggressive cost-reduction projections than the Reference scenario for solar as well as other renewable and energy storage technologies, but it uses standard future projections for electricity demand.

And the “Decarbonization with Electrification” (Decarb+E) scenario goes further by including large-scale electrification of end uses.

The study also analyzes the potential for solar to contribute to a future with more complete decarbonization of the U.S. energy system by 2050, although this analysis is simplified in comparison to the grid-decarbonization analysis and thus entails greater uncertainty, DOE noted.

Even under the Reference scenario, installed solar capacity increases by nearly a factor of seven by 2050, and grid emissions decline by 45% by 2035 and 61% by 2050, relative to 2005 levels, DOE said. “That is, even without a concerted policy effort, market forces and technology advances will drive significant deployment of solar and other clean energy technologies as well as substantial decarbonization,” the study said.

The study said that the target-driven deep decarbonization of the grid modeled in the Decarb and Decarb+E scenarios yields more extensive solar deployment, similarly extensive deployment of wind and energy storage, and significant expansions of the U.S. transmission system.

In 2020, about 80 gigawatts (GW) of solar, on an alternating-current basis, satisfied around 3% of U.S. electricity demand. By 2035, the decarbonization scenarios show cumulative solar deployment of 760–1,000 GW, serving 37%–42% of electricity demand, with the remainder met largely by other zero-carbon resources, including wind (36%), nuclear (11%–13%), hydroelectric (5%–6%), and biopower/geothermal (1%).

By 2050, the Decarb and Decarb+E scenarios envision cumulative solar deployment of 1,050–1,570 GW, serving 44%–45% of electricity demand, with the remainder met by wind (40%–44%), nuclear (4%–5%), hydropower (3%–5%), combustion turbines run on zero-carbon synthetic fuels such as hydrogen (2%–4%), and biopower/geothermal (1%). Sensitivity analyses show that decarbonization can also be achieved via different technology mixes at similar costs, the DOE noted.

Although the study emphasizes decarbonizing the grid, the Decarb+E scenario envisions decarbonization of the broader U.S. energy system through large-scale electrification of buildings, transportation, and industry. In this scenario, electricity demand grows by about 30% from 2020 to 2035, owing to electrification of fuel-based building demands (e.g., heating), vehicles, and industrial processes. Electricity demand increases by an additional 34% from 2035 to 2050. By 2050, all these electrified sectors are powered by zero-carbon electricity. In this scenario, the combination of grid decarbonization and electrification abates more than 100% of grid CO2 emissions relative to 2005 levels.

With respect to the broader U.S. energy system, the Decarb+E scenario reduces CO2 emissions by 62% in 2050, compared with 24% in the Reference scenario and 40% in the Decarb scenario. The 38% residual in the Decarb+E scenario reflects emissions from direct carbon-emitting fossil fuel use, primarily for transportation and industry.

“We do not model elimination of these remaining emissions in detail, but a simplified analysis of 100% decarbonization of the U.S. energy system by 2050 shows solar capacity doubling from the Decarb+E scenario — equating to about 3,200 GW of solar deployed by 2050 — to produce electricity for even greater direct electrification and for production of clean fuels such as hydrogen produced via electrolysis.”

solar
Source: DOE Solar Futures Study

Additional Key Findings

Additional key findings of the study include, among others, the following:

In addition, the study said that challenges must be addressed so that solar costs and benefits are distributed equitably. “Low- and medium-income communities and communities of color have been disproportionately harmed by the fossil-fuel-based energy system, and the clean energy transition presents opportunities to mitigate these energy justice problems by implementing measures focused on equity,” the study said. The study “explores measures related to the distribution of public and private benefits, the distribution of costs, procedural justice in energy-related decision making, the need for a just workforce transition, and potential negative externalities related to solar project siting and disposal of solar materials.”

Solar Futures Study Is Third In A Series Of Studies

 The Solar Futures Study is the third in a series of vision studies from SETO and NREL, preceded by the SunShot Vision Study (2012) and On the Path to SunShot (2016).

While the previous studies focused on the impacts of low-cost solar technologies on the economy, this study dives into solar energy’s role in a decarbonized grid and provides analysis of future solar technologies, the solar workforce, and how solar energy might interact with other technologies like storage.

Peninsula Clean Energy Will Receive 35 MW Of Geothermal Power Under PPA

September 7, 2021

by Paul Ciampoli
APPA News Director
September 7, 2021

Starting in July 2022, California community choice aggregator (CCA) Peninsula Clean Energy will receive 35 megawatts (MW) of geothermal power from The Geysers, a 725-MW complex run by Calpine Corporation and located 70 miles north of San Francisco.

The power purchase agreement is Peninsula Clean Energy’s first to involve geothermal.

The 15 geothermal power plants at The Geysers stretch across 45 acres in Sonoma and Lake Counties and are responsible for providing nearly one-tenth of the renewable power produced annually in California.

The geothermal power from The Geysers will bring Peninsula Clean Energy another step toward the CCA’s ultimate goal of providing 24/7 renewable power to its customers, it noted.

Peninsula Clean Energy is on track to deliver electricity that is 100 percent renewable by 2025 and has earned investment grade credit ratings from Moody’s and Fitch.

Peninsula Clean Energy is the official electricity provider for San Mateo County, Calif., and, beginning in 2022, for the City of Los Banos, Calif.

The American Public Power Association has initiated a new category of membership for CCA programs.

City Council Vote Marks Next Step in LADWP’s Transition To 100 Percent Carbon-Free Energy

September 7, 2021

by Paul Ciampoli
APPA News Director
September 7, 2021

The Los Angeles City Council on Sept. 1 directed the Los Angeles Department of Water and Power (LADWP) to take the steps necessary for the city to achieve 100 percent carbon-free energy by 2035.

“This is truly a great day for Los Angeles that puts our city firmly in a leadership position among world cities working to decarbonize the planet,” said Marty Adams, LADWP’s General Manager and Chief Engineer, in a statement. “Our city has set a goal of 100% carbon-free energy by 2035 and we’re here to tackle the challenge and say, LADWP is all in.”

Councilmembers voted on a motion introduced by Councilmembers Paul Krekorian and Mitch O’Farrell. The motion noted that LADWP is going to prepare a strategic long-term resource plan, which will determine the optimal pathway to achieve the 100 percent clean energy goal. It will align with LADWP’s priorities for ensuring power reliability, sustainability, affordability and equity for LADWP’s customers.  

The council also approved a related motion from O’Farrell and Krekorian that will create a strategic plan for equitable workforce hiring, which is aimed at ensuring a just transition to thousands of green new jobs.

Results Of NREL Study Released Earlier This Year

Earlier this year, results of a years-long analysis were released by the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL), which found that meeting Los Angeles’ goal of reliable, 100% renewable electricity by 2045, or even 2035, is achievable with rapid deployment of wind, solar, storage, and other renewable energy technologies this decade.

The results of the study were released by Los Angeles Mayor Eric Garcetti, United States Secretary of Energy Jennifer Granholm, LADWP Board of Water and Power Commissioners President Cynthia McClain-Hill, Adams, a number of Los Angeles City Council members and Dr. Martin Keller, Executive Director, NREL. They participated in a virtual press event to release the Los Angeles 100% Renewable Energy Study, known as LA100.

More recently, in June, LADWP said it would launch a comprehensive and inclusive, community-driven effort to achieve a just and equitable 100% carbon-free future for all communities of Los Angeles. LADWP’s Board of Water and Power Commissioners on June 23 authorized the public power utility to move forward with LA100 Equity Strategies, which aims to incorporate community-driven and equitable outcomes into the goals of the LA100 study completed by NREL.

LADWP Officials Appear Before Council

Prior to the council’s vote, Adams and Reiko Kerr, LADWP Senior Assistant General Manager-Power System Engineering, Planning, and Technical Services, offered remarks on LA100 and took questions from councilmembers.

“When you talk to anybody in the Department of Energy, they will tell you the only thing they’re talking about in D.C. is the City of Los Angeles and the LA100 study,” Adams told councilmembers. “This is a huge win for the city,” Adams said.

There is also a LA100 next steps plan. “This is the parts and pieces. This is where we’re looking at exactly what we have to complete in the next ten years to reach that clean energy future goal.”

LADWP’s strategic long-term resource plan is a 25-year plan that is examining what LADWP’s staffing and human resources plan needs to be because there will be a “tremendous need for expanding our workforce to get this work done,” he said. The plan is also looking at “how these projects have to dovetail together to make sure we don’t have outages or instability in the system in the meantime.” Operation and maintenance are another component of this plan “to make sure that the power reliability that the city of L.A. has enjoyed not only continues but improves all through the process,” Adams said.

“I promise you that we’re going to take this very seriously and make this happen,” Adams told councilmembers prior to the vote.

 Adams discussed LA100 in an American Public Power Association Public Power Now podcast earlier this year.

“This vote is a vote that will be transformative to the future of the City of Los Angeles,” Councilmember Krekorian said. “This is a vote that will help shape the future of the economy of Southern California. This is a vote that will create thousands and thousands of new, good jobs. It’s a really big deal.”

In a news release related to the vote, Krekorian noted that LADWP has already taken significant steps toward achieving its 100 percent clean energy goal, laying the groundwork to accommodate 580,000 electric vehicles and adding over 1,000 megawatts of energy storage by 2030.    

At the council meeting on Sept. 1, Krekorian asked Adams and Kerr to talk about how LADWP is poised to take advantage of federal and state government infrastructure investment funding opportunities “to be able to begin building the things that we need to build” to get to 100 percent carbon-free energy, to upgrade the transmission and distribution infrastructure “and otherwise take advantage of that funding that’s available.”

Kerr said that green hydrogen has received a lot of attention at both the federal and state level “and so we’ve been in discussions for funding for that. At the state level, there is potential opportunity for green hydrogen and that has multiple benefits.”

She noted that green hydrogen allows firm dispatchable generation that has carbon-free emissions “for those times where you either have an emergency or you lose import capability or there’s no wind and no solar to ensure that we have reliability.” (A recent APPA report on hydrogen notes that green hydrogen or renewable hydrogen is made from renewable energy via electrolysis).

Green hydrogen also provides long duration storage, Kerr noted. She said that this is very important “because when you look at the over generation of renewables in the springtime” there is a large amount of over generation because that time of year is when loads are low, “but you’re really building your generation profile for those peak periods during the summer, so you have all that excess. If we can use that to create the green hydrogen in the spring, you can use that hydrogen to store it” over multiple months until needed in the summer. “We’ll be looking for state funding,” she said.

Kerr noted that LADWP has issued a request for information for green hydrogen in-basin, so there are state opportunities for local green hydrogen.        

In May 2021, LADWP joined a coalition that aims to bring down the cost of green hydrogen. LADWP, along with the Green Hydrogen Coalition and other partners, launched HyDeal LA, a collaboration of developers, green hydrogen off-takers, integrators, equipment manufacturers, investors, and advisors. The group aims to work together to bring the cost of green hydrogen down to $1.50 per kilogram in the Los Angeles Basin by 2030 by creating a commercial green hydrogen cluster at scale.

Joining HyDeal LA marks another significant initiative around green hydrogen for LADWP, which is leading the conversion of the Intermountain Power Project in Delta, Utah to the world’s first turbine intentionally designed and built to operate with a blend of 30% green hydrogen and 70% natural gas when the plant goes into operation in mid-2025. It will be designed to scaleup to 100% carbon free green hydrogen by 2035.

LADWP has some projects that could be considered shovel ready, noted Adams, who went on to say that the utility is working to try to streamline environmental processes because a lot of the costs for the projects relate to “just getting them off the ground, getting them engineered and getting them approved to be constructed.”

Adams said that “We will continue to seek all avenues for resources,” adding that there is “a lot of federal money out there for construction, particularly infrastructure construction and so we are very much focused on getting whatever funds are available because all those funds then decrease the costs that ultimately go to our ratepayers.”

Study Finds Hydrogen Peakers Beat Batteries, But Not Gas Peakers

September 3, 2021

by Peter Maloney
APPA News
September 3, 2021

Hydrogen fuel could be a more economical solution to the intermittency of renewable energy resources than lithium-ion batteries, but it is not an economic match to natural gas-fired peaking plants at current market prices, according to a new report from researchers at the MIT Energy Initiative (MITEI).

Hydrogen is attracting a lot of interest as an alternative fuel for power peaking power plants. Several public power utilities, particularly on the West Coast, are exploring hydrogen as an alternative to natural gas and are looking at projects to produce so-called green hydrogen by using renewable resources to power electrolyzers that produce the gas from water. Utilities ranging from the Los Angeles Department of Water and Power and the Northern California Power Agency to the Douglas County PUD and the Nebraska Public Power District have embarked on hydrogen pilot projects.

While there has been a rapid rise in the deployment of lithium-ion batteries to aid in the integration of intermittent resources such as wind and solar power, batteries are sized to produce power for hours at a time and are best used to address daily imbalances between electric supply and demand, the authors of the report in Applied Energy said. (The online version of the article was published in July; the print version is due out in October.)

The report’s authors, Drake Hernandez and Emre Gencer, used a least cost of energy (LCOE) approach to analyze the economics of meeting seasonal energy imbalances, comparing hydrogen-fired gas turbines (HFGT) and lithium-ion battery systems (LI).

They found that the LCOE associated with meeting seasonal energy imbalances is $2,400 per megawatt hour (MWh) using a hydrogen-fired gas turbine and $3,000/MWh using a lithium-ion battery system. If a gas turbine is fired with “blue” hydrogen, that is, hydrogen produced by reforming natural gas, the average LCOE decreases to $1,560/MWh. On average, reforming hydrogen rather than electrolytic hydrogen turned out to be the cheapest option for replacing peaking plants, the report found.

Nonetheless, “the power prices required to justify investment in an HFGT to replace a natural gas-fired gas turbine are considerably higher than those seen in the market today,” the authors said.

“Our study’s essential takeaway is that hydrogen-fired power generation can be the more economical option when compared to lithium-ion batteries—even today, when the costs of hydrogen production, transmission, and storage are very high,” Hernandez said in a statement.

The study also looked at the economics of retrofitting natural gas plants to burn hydrogen, as opposed to building entirely new facilities, and found the price for converting a fossil fuel plant to burn hydrogen is high and such conversions likely would not take place until more sectors of the economy embrace hydrogen, either as a transportation fuel or for varied manufacturing and industrial purposes.

The authors also noted that “enormous investments” would be necessary to expand hydrogen production facilities to meet grid-scale needs. “With any of the climate solutions proposed today, we will need a carbon tax or carbon pricing; otherwise, nobody will switch to new technologies,” Gencer said in a statement.

The study looked at all peaking plants in California, using 2019 as the base year. The researchers looked at the costs of running natural gas-fired peakers, defined as plants operating 15 percent of the year to make up for intermittent energy resources. They also determined the amount of carbon dioxide released by those plants and the expense of abating those emissions.

The American Public Power Association recently issued a report that offers a perspective 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.

Burlington Electric Department And Mayor Propose Net Zero Energy Revenue Bond

September 3, 2021

by Paul Ciampoli
APPA News Director
September 3, 2021

Burlington, Vermont, Mayor Miro Weinberger and public power utility Burlington Electric Department (BED) have proposed a new, $20 million Net Zero Energy Revenue Bond that would accelerate progress toward Burlington’s climate goals, while reducing upward rate pressure for BED customers, BED reported on Sept. 2.

In addition, the mayor and BED announced that BED’s green stimulus program would continue and that Moody’s Investors Service affirmed BED’s A3 rating.

The Net Zero Energy Revenue Bond, combined with a portion of BED’s annual General Obligation (GO) Bond, would make numerous investments, including:

The Net Zero Energy Revenue Bond would reduce future rate pressure significantly for BED customers relative to a scenario where BED made these investments without the bond, BED noted.

Debt service on the revenue bond proposal and that portion of the GO bond used for strategic electrification would be supported by net revenue from strategic electrification projects between Fiscal Year 2023 and Fiscal Year 2025 that will contribute approximately 40 percent of BED’s obligation over the 20-year debt service life of the bonds and savings of $684,000 of BED’s debt service starting in Fiscal Year 2026, due to the maturity of existing bond debt.

Also, under a new Vermont Public Utility Commission (PUC) order approving a BED proposal, the utility will double funding at least through the end of Fiscal Year 2025 for strategic electrification, including continuing its green stimulus program.

The doubling of funding would be supported by approximately $5.3 million from BED’s annual GO Bond. This will reduce fossil fuel use through customer incentives for heat pumps, EVs, electric lawn care equipment, electric bikes, and more, as well as avoid over 47,000 tons emissions, equivalent to nearly 100,000 barrels of oil burned, compared to business as usual, BED said.

Meanwhile, Moody’s Investors Service affirmed BED’s A3 rating on outstanding revenue bonds on August 16, 2021, with a stable outlook. Moody’s cited BED’s 100 percent renewable power supply, the diverse local economy in Burlington, and recent action to adjust rates for the first time in 12 years as positive indicators.

Among the first of its kind nationwide, the Net Zero Energy Revenue Bond proposal was recommended by the Burlington Electric Commission by a 5-0 vote. The Burlington Board of Finance and City Council will consider the proposal for placement on the November ballot at their September 13 meetings.

In September 2019, Weinberger, joined by BED General Manager Darren Springer, City Director of Sustainability Jennifer Green, and other stakeholders, released the City’s Net Zero Energy Roadmap. More than a year in the making, the roadmap studies what it will take for Burlington to accomplish its goal to become a Net Zero Energy city by 2030, and identifies four key pathways to get there.

Springer discussed the roadmap in an episode of the American Public Power Association’s Public Power Now podcast.

Details On Green Stimulus Program

In the wake of the COVID-19 pandemic, Weinberger announced that a new green stimulus program would be launched using existing funds to support a range of expanded and new initiatives to help boost both the city’s economic recovery from the pandemic and its transition to becoming a Net Zero Energy city.

In response, BED worked quickly last year to implement the green stimulus, which launched on June 1, 2020 and offers incentives for technologies including heat pumps, heat pump water heaters, electric vehicles, and more.

The success in 2020 of the green stimulus led the mayor and BED to announce that the green stimulus program initiatives have been extended into 2021 and will remain available through year’s end or until funding is exhausted.

San Diego County Board of Supervisors Approves Community Choice Energy Move

September 1, 2021

by Paul Ciampoli
APPA News Director
September 1, 2021

The County Board of Supervisors for San Diego, Calif., voted on Aug. 31 to authorize the county to join a community choice energy (CCE) program called San Diego Community Power.

The CCE launched in March and includes the cities of Chula Vista, Encinitas, Imperial Beach, La Mesa and San Diego.

The county will become part of a joint powers authority which governs the CCE. CCEs are also known as community choice aggregators (CCAs).

Community choice allows cities and counties to buy electricity, including renewable energy like solar and wind for residents and businesses. CCEs offer customers in the county’s unincorporated areas an alternative to buying power from investor-owned San Diego Gas and Electric (SDG&E). SDG&E would still provide transmission and delivery services, as well as billing.

The CCE could provide residents competitive utility rates and cost savings compared to SDG&E, and also offer more renewable power, the board of supervisors said.

Currently, there are 24 CCEs operating throughout the state including two in San Diego County, San Diego Community Power and the Clean Energy Alliance. The alliance members include Carlsbad, Del Mar and Solana Beach. In all, the state’s CCEs serve 11 million customers.

San Diego Community Power is expected to begin serving county customers in spring 2023.

Association offers new CCA program membership category

The American Public Power Association has initiated a new category of membership for CCA programs.

Court Vacates Final Rule That Set New Waters of the U.S. Definition

September 1, 2021

by Paul Ciampoli
APPA News Director
September 1, 2021

The U.S. District Court for the District of Arizona on Aug. 30 vacated a Trump Administration rule that set a new definition for “waters of the United States” (WOTUS).

At issue in the proceeding is a final rule — the Navigable Waters Protection Rule (NWPR) — announced last year by the Environmental Protection Agency (EPA) and the Army Corps of Engineers.

The NWPR addresses traditional navigable waters and territorial seas but narrowed the extent of federal jurisdiction by excluding isolated water bodies, “ephemeral” waters that form only in response to rain, and most ditches.

The final rule called for four categories of waters are federally regulated: (1) The territorial seas and traditional navigable waters; (2) Perennial and intermittent tributaries to those waters, (3) Certain lakes, ponds, and impoundments, and (4) Wetlands adjacent to jurisdictional waters.

The final rule also detailed 12 categories of exclusions, features that are not WOTUS, such as features that only contain water in direct response to rainfall (e.g., ephemeral features); groundwater; many ditches; prior converted cropland; and waste treatment systems.

The American Public Power Association generally supported the NWRP rule as it provided clarity and certainty over the scope of jurisdictional waters. A clear WOTUS definition is critically important as the electric utility industry transitions its generation fleet to low and non-emitting resources. The association believes that the NWPR provided clear descriptions of exclusions for many water features that traditionally have not been regulated such as waste treatment systems and ditches.

The rule was subsequently challenged in court by Earthjustice and the Pascua Yaqui Tribe, Fond du Lac Band of Lake Superior Chippewa, Tohono O’odham Nation, Menominee Indian Tribe of Wisconsin, Quinault Indian Nation, and Bad River Band of Lake Superior Chippewa.

In May 2021, these parties sought summary judgement in the proceeding.

In lieu of filing a response to the motion for summary judgment, the EPA and Corps of Engineers filed a motion for voluntary remand of the NWPR without “vacatur” (vacating the final rule). The plaintiffs in the case did not oppose remand of the NWPR but argued that remand should include vacatur. 

Details On Court Decision

“The concerns identified by plaintiffs and the agency defendants are not mere procedural errors or problems that could be remedied through further explanation,” the court said in its ruling. “Rather, they involve fundamental, substantive flaws that cannot be cured without revising or replacing the NWPR’s definition of ‘waters of the United States,’” the court said. The order was written by U.S. District Judge Rosemary Marquez.

“Accordingly, this is not a case in which the agency could adopt the same rule on remand by offering ‘better reasoning or…complying with procedural rules,’” wrote Marquez.

Neither is this a case in which vacating the final rule could result in possible environmental harm, the judge went on to say. “To the contrary, remanding without vacatur would risk serious environmental harm,” she said. 

Marquez noted that the two federal agencies have identified indicators of a substantial reduction in waters covered under the NWPR compared to previous rules and practices. The judge noted that between June 22, 2020 and April 15, 2021, the Corps made approved jurisdictional determinations under the NWPR of 40,211 aquatic resources or water features and found that approximately 76% were non-jurisdictional. The agencies have identified 333 projects that would have required Section 404 permitting under the Clean Water Act prior to the NWPR but no longer do, the court said.

Marquez said that the reduction in jurisdiction has been particularly significant in arid states. In New Mexico and Arizona, nearly every one of over 1,500 streams assessed under the NWPR were found to be non-jurisdictional, “a significant shift from the status of streams under both the Clean Water Rule and the pre-2015 regulatory regime,” she wrote.

“The seriousness of the agencies’ errors in enacting the NWPR, the likelihood that the agencies will alter the NWPR’s definition of ‘waters of the United States,’ and the possibility of serious environmental harm if the NWPR remains in place upon remand, all weigh in favor of remand with vacatur,” the order said.

The motion for voluntary remand made by EPA and the Army Corps of Engineers was therefore granted to the extent it seeks voluntary remand of the NWPR. At the same time, Marquez said that the NWPR is vacated and remanded for reconsideration to the EPA and the Army Corps of Engineers.

The vacatur means the test to determine which waters are jurisdictional will revert pre-2015 WOTUS regulations. However, legal experts disagree on whether a district court can vacate a rule nationally, meaning the pre-2015 test might apply only on a narrower scale, such as on land controlled by the six plaintiff tribes.

Biden Administration Action

Prior to the court’s order, EPA Administrator Michael Regan in June announced that the EPA and the Army Corps of Engineers would formally revise the definition of WOTUS.

The 2020 NWPR was identified in President Biden’s Executive Order 13990, which directs federal agencies to review all existing regulations, orders, guidance documents, policies, and any other similar agency actions promulgated, issued, or adopted between January 20, 2017, and January 20, 2021.

Upon review of the NWPR, the two agencies determined that the rule is significantly reducing clean water protections based on a review of the 333 projects they said would have required § 404 permits before the NWPR, but no longer do because of the narrower scope of jurisdiction under the NWPR. However, industry stakeholders contend the Agencies have not disclose all the data necessary to review the list of projects. For those jurisdictional determinations (JDs) found online, there are no prior JDs, therefore how can the Agencies determine that certain water features would have required a permit but no longer do under the NWPR.

The Department of Justice on June 9 filed a motion requesting remand of the NWPR rule.

The action reflects the agencies’ intent to initiate a new rulemaking process that restores the protections in place prior to the 2015 WOTUS implementation and anticipates developing a new rule that defines WOTUS “and is informed by a robust engagement process as well as the experience of implementing the pre-2015 rule, the Obama-era Clean Water Rule, and the Trump-era Navigable Waters Protection Rule,” EPA noted in a news release.

Subsequently EPA issued a notice, announcing public meetings and a solicitation for pre-proposal feedback on a new WOTUS definition. APPA plans to submit comments September 3 articulating the key principals any new WOTUS definition should include considering the recent court decision.

Public Power Crews Continue Restoration Work as Ida Shifts to Tropical Depression

August 31, 2021

by Paul Ciampoli
APPA News Director
August 31, 2021

In the wake of Hurricane Ida, which made landfall in Louisiana over the weekend as a Category 4 hurricane, public power utility crews continued to assist with power restoration efforts in the Southeast as Ida shifted to a Tropical Depression.

The Department of Energy (DOE) in an update said that as of 7:00 a.m. EDT on August 31, there were approximately 1.1 million customer outages due to Ida, with approximately 1 million outages in Louisiana.

DOE said that as of 5:00 a.m. EDT on Aug. 31, Tropical Depression Ida was 185 miles southwest of Nashville, Tennessee, moving northeast at 12 MPH, with maximum sustained winds of 30 MPH.

“Considerable heavy rain and flooding threats will continue to spread from the Tennessee and Ohio Valleys into the central and southern Appalachians and Mid Atlantic through Wednesday,” DOE said.

DOE noted that utilities are conducting damage assessments and restoration efforts as conditions permit. Damage assessments are expected to take three days and estimated restoration times will be established once damage assessments are complete, the federal agency said.

Utilities in the impacted area pre-staged crews, equipment, and materials and mutual assistance networks have been activated to support restoration efforts as needed. A large number of public power utilities from several states sent crews to Louisiana prior to the arrival of Ida.

Many of those crews were set to assist Louisiana public power Lafayette Utilities System (LUS) in its recovery efforts. For example, mutual aid crews from the City of Tallahassee, Fla., deployed Saturday to arrive in Lafayette Sunday morning before the storm to assist LUS. With LUS receiving little to no impacts from Ida, the City of Tallahassee was redeployed to the City of Houma, La.

LUS on Aug. 31 reported that a team from LUS is in Houma doing damage assessment as well as line and tree trimming crews from Tallahassee, North Carolina’s Greeneville Utilities Commission, the City of Statesville, N.C., the City of High Point, N.C., the City of Wilson, N.C., Oklahoma’s Grand River Dam Authority, Nebraska’s Lincoln Electric System, the Town Tarboro, N.C., and North Carolina’s Wake Forest Power that pre-staged in Lafayette for Ida.

 

houma
Ida-related damage in Houma, La. (photo from LUS Facebook page)

Crews from Thomasville, Ga., were deployed to St. Martinsville, La., initially, released Aug. 31 and then asked to assist Houma.

Brandon Wylie with Electric Cities of Georgia (ECG) has been assisting in Morgan City, while ECG Training and Safety Specialist Calvin Vallee has been helping out in St. Martinsville. On Sept. 1, they both will be traveling to Houma. Wylie is Director of Safety and Training at ECG.

Crews from the Georgia public power communities of Griffin and Calhoun were deployed to Morgan City, La.

ECG is a non-profit organization providing strategic and technical services to 52 public power communities with utility operations. Calhoun and Griffin are members of ECG.

lines
Crews from the Cities of Calhoun and Griffin helping restore power in Morgan City, Louisiana (Photo from City of Calhoun, Ga., Government)

Meanwhile, Nebraska’s Omaha Public Power District on Aug. 31 said it was sending 15 employees to Baton Rouge, La., to help with power restoration in the aftermath of Ida.

OPPD’s team – including four, three-person line crews, two transportation mechanics, and one field supervisor – left Monday at noon and are expected to arrive in Baton Rouge this evening. They will work with investor-owned Entergy Louisiana.

oppd
OPPD trucks ready to roll out to Louisiana (photo from OPPD)

“Our linemen are happy for the opportunity to provide mutual aid support,” said OPPD Papillion Center Manager Eli Schiessler, who is overseeing the effort. “It’s particularly gratifying to be able to help another community, given the level of support we have received from other utilities this year in our service territory.”

Meanwhile, a 16-man contingent of line technicians and supervisory staff from Nebraska Public Power District (NPPD) will be hitting the road on Tuesday, journeying to Baton Rouge to provide mutual aid and restore power.

The contingent from NPPD will be utilizing a variety of equipment used in restoration efforts, with a commitment for two weeks to assist in restoring power for Entergy.

NPPD crews were expected to arrive Thursday to begin assistance.

Meanwhile, the City of New Smyrna Beach, Fla., and Fort Pierce Utilities Authority sent mutual aid crews to assist utilities personnel in the City of Plaquemine, Louisiana. The Florida public power utility teams were set to deploy on Sunday to arrive in Plaquemine Monday to begin restoring power once the storm passes. Plaquemine said that as of 6 pm, Aug. 30, power had been restored to almost all of the city’s utility customers.

Crews from the following Florida public power utilities were released and are on their way back to Florida: JEA, Lakeland, Orlando, Kissimmee.

Meanwhile, a caravan of Missouri-based public power utility crews headed to Mississippi to help Southwestern Electric Cooperative to get the power back on.

The effort involves 32 lineworkers from seven Missouri Public Utility Alliance (MPUA) towns — crews from Missouri cities of Carthage, Higginsville, Independence, Lebanon, Nixa, Palmyra, and Poplar Bluff.

Ashburnham, Massachusetts, Utility Using DEP Grant To Install Downtown EV Charging Station

August 31, 2021

by Peter Maloney
APPA News
August 31, 2021

Ashburnham Municipal Light Plant (AMLP) plans to install an electric vehicle (EV) charging station using funds from the Massachusetts Department of Environmental Protection (DEP).

The charging station will have four charging ports and is scheduled to be installed at Town Hall on Ashburnham’s Main Street before the end of 2021. The $28,158 grant comes from the Public Access Charging Program within the DEP’s Electric Vehicle Incentive Program.

AMLP applied for the grant with its joint action agency, the Massachusetts Municipal Wholesale Electric Company (MMWEC).

“This is a good thing for Ashburnham because receiving the grant allows additional capital planning to be earmarked for future EV installations,” Kevin Sullivan, AMLP’s general manager, said in a statement.

Sullivan also noted that the grant would help the public power utility align with Massachusetts’ carbon dioxide emission reduction goals. “This grant continues to move Ashburnham in the direction of carbon reduction by providing the impetus for electric vehicle purchases and expanding the EV infrastructure in town,” he said.

AMLP installed a Level 2 electric vehicle charging station at the town’s library in January 2020. The station was funded by a grant from Massachusetts’ Green Communities program, with additional financial support by AMLP and Ashburnham’s Economic Development Committee.

When the new charging station is installed at the Town Hall, Ashburnham will have six charging ports.

Massachusetts’ Global Warming Solutions Act of 2008 requires a 25 percent reduction in greenhouse gas emissions from all sectors of the economy below the 1990 baseline emission level in 2020 and at least an 80 percent reduction in 2050.

The Massachusetts DEP’s Public Access Charging Program provides funding to property owners to cover a portion of the cost of electric vehicle charging stations accessible to the general public. There is $1.5 million allocated to the program, and applications are considered on a first-come, first-served basis until the funds are exhausted.

The Public Access Charging Program provides up to 80 percent of the cost of a charging station installed at non-government owned properties and up to 100 percent of the cost of installing a charger at a government owned property.

Applicants must commit to providing funds to cover any remaining costs of a charging station or its installation and all the operating and maintenance costs for three consecutive years after the charging station is in operation.

The American Public Power Association’s Public Power EV Activities Tracker summarizes key efforts undertaken by members — including incentives, electric vehicle deployment, charging infrastructure investments, rate design, pilot programs, and more. Click here for additional details.