Federal Government Sets California Offshore Wind Energy Lease Sale for December 6
October 18, 2022
by Paul Ciampoli
APPA News Director
October 18, 2022
The Bureau of Ocean Energy Management (BOEM) will hold an offshore wind energy lease sale on Dec. 6, 2022, for areas on the Outer Continental Shelf (OCS) off central and northern California, the Department of Interior said on Oct. 18.
This will be the first-ever offshore wind lease sale on America’s West Coast and the first-ever U.S. sale to support potential commercial-scale floating offshore wind energy development.
“This sale will be critical to achieving the Biden-Harris administration’s deployment goals of 30 gigawatts (GW) of offshore wind energy by 2030 and 15 GW of floating offshore wind energy by 2035,” Interior said. BOEM is part of Interior.
In May 2021, Interior Secretary Deb Haaland and California Governor Gavin Newsom joined Biden-Harris administration leaders to announce an agreement to advance areas for wind energy development offshore the northern and central coasts of California.
The California sale reflects the leasing path announced last year by Haaland and last month’s announcement of a new deployment goal of 15 GW of floating offshore wind energy by 2035.
BOEM will offer five California OCS lease areas that total approximately 373,268 acres with the potential to produce over 4.5 GW of offshore wind energy.
To date, BOEM has held 10 competitive lease sales and issued 27 active commercial wind leases in the Atlantic Ocean from Massachusetts to North Carolina.
The California Final Sale Notice (FSN), which will publish in the Federal Register later this week, provides detailed information about the final lease areas, lease provisions and conditions, and auction details. It also identifies qualified companies that can participate in the lease auction.
The FSN includes three lease areas off central California and two lease areas off northern California.
It also includes several lease stipulations designed to promote the development of a robust domestic U.S. supply chain and advance flexibility in transmission planning.
Among the stipulations announced Oct. 18, BOEM will offer bidding credits for bidders that enter into community benefit agreements or invest in workforce training or supply chain development; require winning bidders to make efforts to enter into project labor agreements; and require engagement with Tribes, underserved communities, ocean users, and agencies.
More information about the FSN and lease stipulations, a map of the area, the list of qualified bidders for the auction, and auction procedures is available on BOEM’s California website.
Rhode Island Utility Seeks Up to 1,000 MW of Offshore Wind Capacity
October 18, 2022
by Paul Ciampoli
APPA News Director
October 18, 2022
Rhode Island Gov. Dan McKee on Oct. 14 announced a request for proposals has been released by Rhode Island Energy for up to 1,000 megawatts of new offshore wind capacity.
In July, McKee signed into law legislation that seeks to expand Rhode Island’s offshore wind energy resources. The new law requires a market-competitive procurement for between 600 and 1,000 megawatts of newly developed offshore wind capacity.
This offshore wind procurement will have the potential to meet at least 30 percent of Rhode Island’s estimated 2030 electricity demand.
When added to the 30-megawatt Block Island Offshore Wind Farm and the planned 400-megawatt Revolution Offshore Wind project, about half of the state’s project energy needs will be powered by offshore wind.
The offshore wind procurement RFP will be posted at the following website: https://ricleanenergyrfp.com/.
Offshore wind project proposals by bidders will be due to Rhode Island Energy on February 1, 2023.
Public Power Utilities in Massachusetts Enter Expanded Hydropower Power Purchase Agreement
October 16, 2022
by Paul Ciampoli
APPA News Director
October 16, 2022
FirstLight Power recently announced the expansion of a power purchase agreement with Energy New England (ENE). As part of the agreement, 13 Massachusetts-based public power entities have agreed to purchase over 110 gigawatt hours per year of hydroelectric power produced by two of FirstLight’s hydroelectric facilities in Connecticut.
The agreement will help participating communities continue to make progress toward meeting Massachusetts’ requirements for municipal utilities to obtain 50 percent of their supply from carbon-free sources by 2030 under the climate legislation passed into law in 2021.
Working in collaboration with ENE, the new power purchase agreement will run from 2024 through 2030. In addition, it expands on the successful partnership with ENE and power purchase agreement that FirstLight entered with 21 municipal utilities in 2020, which at the time represented the largest renewable energy purchase by municipal utilities in New England to date.
In 2021, FirstLight extended many of these agreements with several participating utilities including Middleborough Gas and Electric Department (MGED) and Taunton Municipal Lighting Plant (TMLP).
The public power entities participating in the contract include: Belmont Municipal Light Department, Braintree Electric Light Department, Concord Municipal Light Plant, Danvers Electric Division, Groveland Municipal Light Department, Hingham Municipal Lighting Plant, Mass Development Finance Agency (MDFA)/Devens Utilities, Merrimac Municipal Light Department, Norwood Municipal Light Department, Reading Municipal Light Department, Rowley Municipal Lighting Plant, Wellesley Municipal Light Plant, and Westfield Gas & Electric.
As part of the latest agreement with ENE, FirstLight’s Shepaug Generating Station (in Southbury, Conn) and Stevenson Generating Station (in Monroe, Conn) will supply the energy and renewable energy credits.
One of the largest hydroelectric facilities in Connecticut, Stevenson Station was recently qualified as a Class I (in Maine) renewable energy facility. As Connecticut’s largest hydroelectric generation station and the second largest source of carbon-free electricity in the state, Shepaug Station is a Maine Class II renewable energy facility.
Broad Portfolio Approach Needed to Reach Affordable, Reliable Clean Energy: EPRI
October 8, 2022
by Peter Maloney
APPA News
October 8, 2022
A broad portfolio of clean energy technologies will be required to reach an affordable and reliable clean-energy transition, according to new research by the Electric Power Research Institute (EPRI).
The Low-Carbon Resources Initiative (LCRI) report, by EPRI and GTI Energy, modeled three scenarios to evaluate alternative technology strategies for achieving economy-wide net-zero emissions of carbon dioxide (CO2).
The All Options scenario assumes a full portfolio of clean energy technologies is available, including renewables, nuclear, fossil and bioenergy with carbon capture and storage, electricity storage, hydrogen and hydrogen-derived fuels, and biofuels.
The Higher Fuel Cost scenario assumes all technologies are available, but with higher costs for gas, oil, bioenergy, and CO2 transport and storage.
The Limited Options scenario assumes geologic storage of CO2 is not available and bioenergy supply is limited, but all other technologies are available.
Power Generation
Among the key findings, the LCRI report found that electric generating capacity would grow substantially, from 1,650 gigawatts (GW) to 4,860 GW, a 160 percent to 480 percent increase over current resources.
Across all scenarios, total wind and solar through 2050 ranged from roughly 600 GW to 3,500 GW, compared with 273 GW today, with the high end driven by electricity supporting hydrogen production.
Total clean firm capacity to balance the increase in intermittent resources also would grow, anywhere 1,140 GW to 1,446 GW, including a combination of natural gas, nuclear, hydrogen, hydro, geothermal, bioenergy, and electric storage technologies.
Nuclear Capacity
In all scenarios, the report’s authors found that existing nuclear would provide essential firm capacity in a net-zero energy system. In the Limited Options scenario, in which carbon capture and storage is restricted, new advanced nuclear technologies, such as small modular reactors, would provide around 60 GW of generating capacity as a carbon-free baseload option by 2050. Also, continued expansion and modernization of transmission and distribution network would be essential to support increased integration of renewables, electrification, and flexible demand-side resources. In all scenarios, they said, transmission and distribution investments would increase over time.
Natural Gas
Natural gas infrastructure would also play a crucial role in all scenarios in providing firm capacity for a transitioning power sector and for delivering low-carbon fuel to industry and buildings, particularly in colder climates, the report said. The composition of delivered gas varied by scenario and could include a blend of fossil, renewable and synthetic natural gas, and hydrogen, the report said.
With available options for carbon capture and storage, negative emissions, and blending, annual natural gas consumption could remain at levels similar to today, even in a net-zero energy future, the report said.
With higher natural gas prices, pipeline gas consumption would decline to about half of today’s level. In the Limited Options scenario, without carbon capture and storage, renewable and synthetic natural gas could substitute for fossil gas and pipeline gas consumption would decrease to around 17 percent of current levels.
The report found that carbon capture and storage technologies would be “pivotal” for the new natural gas plants that would be needed to provide up to 33 percent of clean firm capacity and, potentially, a significant portion of hydrogen and ammonia production.
Hydrogen
The report also projects the use of hydrogen as a low CO2 fuel will increase whether through fuel cell vehicles, blending with the natural gas supply to support needs in buildings, or through direct use for process heating in industries. And in a scenario in which carbon capture and storage is limited, hydrogen use will “expand significantly.” Bioenergy could also emerge as another key decarbonization resource, providing low-CO2 alternatives to petroleum-based fuels.
Energy Efficiency
The report’s modelling shows that adoption of efficient electrification technologies and structural shifts to less energy-intensive activities across the economy will combine to reduce final energy 25 percent to 38 percent by 2050 compared with current levels, even with 80 percent GDP growth compared with 2020. Final energy refers to energy consumed at the point of end use.
The modeling shows that “reductions in energy consumption enable emissions reductions throughout energy value chains and across the transportation, buildings, and industrial sectors through technological improvement and switching to more efficient energy carriers and technologies,” the report’s authors said. Many of those changes are cost effective and are assumed to occur even in the absence of an explicit decarbonization target, they added.
Overall, “optionality enables affordability,” the authors concluded. “Achieving economy-wide net-zero CO2 emissions while maintaining reliable delivery of energy and energy services across the economy will require a broad set of low-carbon technologies,” they wrote, adding that a flexible approach to CO2 reduction would allow each sector and region “to follow their own decarbonization path while minimizing overall costs.”
“Imposing greater limitations on resource and technology options could significantly increase the overall cost to achieve net-zero emissions,” the report’s authors said.
Salt River Project Extends Contract for Biomass Power
October 7, 2022
by Paul Ciampoli
APPA News Director
October 7, 2022
Arizona public power utility Salt River Project (SRP) has approved a contract to continue purchasing renewable energy from a biomass plant in the state that will provide baseload power while helping to cut the risk of devastating forest wildfires in northern Arizona.
The 10.5-year purchase power agreement with Novo BioPower will use wood chips from strategic forest thinning efforts in the SRP watersheds focusing on the East Clear Creek watershed projects and including the White Mountain Apache Tribal lands.
The SRP capacity output of the plant will support approximately 80,000 acres of strategic forest thinning over the next 10 years while providing renewable power for customers.
In a news release, the utility said that the forested lands of northern Arizona have been hit by devastating wildfires and are primed for more infernos like those that have impacted Arizona, California, and Colorado. Many forested lands in northern Arizona have thousands of trees per acre and suffered from extreme drought, which can fuel large wildfires with catastrophic impacts.
“To decrease the risks of forest wildfires, partnerships like this enable thinning projects to be conducted across the SRP watersheds, restoring forests and watersheds to more natural conditions and avoiding wildfires devastating impacts on the natural ecosystem, rural communities and the Valley’s water supply. These partnerships are critical for the success of forest thinning projects throughout the state.” said Elvy Barton, SRP Forest Health Management Principal.
SRP is working with the U.S. Forest Service and other entities on a number of strategic forest thinning projects that will help mitigate the forest wildfire threat and provide fuel for the renewable power plant.
So far, more than 5,700 acres of trees are being thinned and about 16,000 acres are planned in the next four years.
“Finding economically positive uses for the huge volume of biomass on the National Forests is a major barrier to overcome in order to ensure the long-term protection of critical watersheds in northern Arizona. The Novo BioPower provides the only existing market for low-grade biomass material,” SRP said.
Among SRP’s sustainability goals are a pledge to help thin 500,000 acres on the SRP watersheds by 2035 and an expanded pledge to add 2,025 MW of new utility-scale solar energy to SRP’s renewable portfolio by 2025.
Sunnova Seeks Approval To Build Solar-Storage ‘Micro Utilities’ in California
September 7, 2022
by Peter Maloney
APPA News
September 7, 2022
Sunnova Energy International has applied to the California Public Utilities Commission (CPUC) to develop solar-and-storage “micro-utilities” in California.
Sunnova’s wholly owned subsidiary Sunnova Community Microgrids California (SCMC) said it plans to target newly constructed homes where it can work with developers to design and implement mostly self-sustaining micro-utilities equipped with solar and storage facilities.
The company said the installations would be “largely self-sustaining micro-utilities by equipping new home communities with solar and storage to provide consumers with a better energy service that allows them to live in a more resilient home and community with latest-generation energy infrastructure.”
In its filing with the California commission, SCMC asked the CPUC to qualify it as a “micro-utility” and to request a certificate to construct and operate microgrids under California’s public utilities code.
The company hopes to build multi-property microgrids for residential and commercial customers in California and be the first solar and storage focused micro-utility company in the state able to own and operate behind-the-meter nanogrids, community assets, and front-of-the-meter distribution infrastructure.
SCMC community assets would include complete distribution infrastructure and energy assets including solar, battery storage, and emergency generation, the company said.
California’s first 100 percent renewable energy, front-of-the-meter, multi-customer microgrid, in Humboldt County, came online in June, providing energy resilience for a regional airport and a U.S. Coast Guard Air Station.
NREL Outlines Paths And Challenges Of Reaching 100% Clean Electric Grid By 2035
September 6, 2022
by Peter Maloney
APPA News
September 6, 2022
There are several pathways to accomplish the decarbonizing of the U.S. electric grid by 2035, but they all come with their own sets of challenges, according to a new report from the National Renewable Energy Laboratory (NREL).
The report, Examining Supply-Side Options to Achieve 100% Clean Electricity by 2035, examines the types of supply side clean energy technologies and the scale and pace of deployment needed to achieve 100 percent clean – defined as zero net greenhouse gas emissions – power grid by 2035, which NREL says could put the United States on a path to economy wide decarbonization by 2050.
The authors noted that the report comes on the heels of the enactment of the Inflation Reduction Act (IRA), which, with the Bipartisan Infrastructure Law (BIL), aims to reduce economy wide greenhouse gas emissions in the United States to 40 percent below 2005 levels by 2030. The reductions are expected to be more pronounced within the electric power sector with initial estimates of declines of 68 to 78 percent below 2005 levels by 2030. Nonetheless, the authors say the laws are likely not sufficient to bring the country all the way to 100 percent carbon dioxide free electricity by 2035.
In the study, which as done in partnership with the Department of Energy (DOE) with funding support from the DOE’s Office of Energy Efficiency and Renewable Energy, the authors evaluated four core scenarios that were each compared with two reference scenarios, one with current policy electricity demand and the other with higher load growth as a result of accelerated electrification.
The authors noted that the most cost effective pathway to large-scale decarbonization likely involves electrification of buildings and much of the transportation and industrial sectors, as well as “aggressive” energy efficiency and demand management measures. However, they also noted that electrification “will dramatically increase demand, which in turn makes it more difficult to decarbonize the electricity system due to the rate of deployment needed.”
The four core scenarios used in the study are:
- All Options, in which all technologies continue to decline in cost while reaching higher levels of performance, including development and deployment of direct air capture (DAC) technology, which removes carbon dioxide directly from the atmosphere. (The other three scenarios assume DAC does not achieve cost and performance targets needed to be deployed at scale.)
- Infrastructure Renaissance, which assumes improved transmission technologies as well as new permitting and siting approaches that allow greater levels of transmission deployment with higher capacity.
- Constrained, in which additional constraints to deployment of new generation and transmission capacity increases costs and limits deployment of certain technologies.
- No CCS, in which carbon capture and storage (CCS) technologies do not achieve needed cost and performance targets for cost-competitive deployment.
Beyond the four core scenarios, NREL also analyzed 142 additional sensitivities in the study in order to capture future uncertainties related to technology cost, performance, and availability.
None of the scenarios in the study include the IRA and BIL energy provisions, but NREL said their inclusion is not expected to significantly alter the 100 percent systems explored.
In all the core scenarios, the 100 percent requirement is met on a net basis, meaning gross emissions can be offset through negative emissions technologies, such as DAC, that can capture carbon dioxide from the air.
In all scenarios, as much as 5 percent of 2035 generation is from fossil fuel technologies. The All Options scenario includes about 660 gigawatts (GW) of fossil capacity of all types in 2035.
Only the No CCS scenario precludes the use of fossil fuel generation; it also has the greatest use of seasonal storage. In the other three scenarios, fossil generators continue to contribute through 2035, but their emissions must be offset by technologies including DAC and bioenergy with carbon capture and storage. Fossil plants with carbon capture and storage would have to have emissions offsets because their capture rates are assumed to be 90 percent and upstream methane leakage from natural gas production must also be offset.
In all the modeled scenarios, NREL said new clean energy technologies would be deployed at an “unprecedented scale and rate” to achieve 100 percent clean electricity by 2035.
The models call for wind and solar energy to provide between 60 and 80 percent of generation in the least-cost electricity mix in 2035, with overall generation capacity growing to roughly three times the 2020 level by 2035. That would require the installation of between 40 and 90 GW of solar on the grid per year and 70 to 150 GW of wind power per year by the end of the decade. That growth in renewable generation would represent a fourfold increase in the current annual deployment levels of wind and solar power, NREL noted.
Across the four scenarios, 5 to 8 GW of new hydropower and 3 to 5 GW of new geothermal capacity would also need to be deployed by 2035, as well as 120 to 350 GW of diurnal storage, that is, storage capable of discharging from to 2 to up to 12 hours.
Seasonal storage would also have to play an important role in reaching 100 percent clean energy by 2035, NREL said, because there would be a multiday-to-seasonal mismatch of variable renewable supply and demand if clean electricity comprises 80 to 95 percent of generation. Across the scenarios, seasonal storage capacity in 2035 would need to range from 100 to 680 GW, which would require “substantial development” of infrastructure such as fuel storage, transportation and pipeline networks.
In the Constrained scenario, nuclear capacity more than doubles, reaching 27 percent of generation, while limited growth in the other three core scenarios results in a contribution of 9 to 12 percent, largely from the existing nuclear fleet, NREL said.
Differences in energy contribution among the four core scenarios are largely driven by constraints in transmission and renewable siting, NREL said. In all scenarios, a “significant” amount of new transmission would be needed to deliver energy from wind-rich regions to load centers in the eastern United States. Total transmission capacity in 2035 would need to be 1.3 to 2.9 times current capacity, requiring 1,400 to 10,100 miles of new high-capacity transmission lines per year, NREL said.
Technologies being deployed today “can provide most of U.S. electricity by 2035 in a deeply decarbonized power sector,” but achieving a net-zero electricity sector at the lowest cost will take advances in research and development into emerging technologies, including the “potentially important role of several technologies that have not yet been deployed at scale, including seasonal storage and several CCS-related technologies,” NREL said in the study.
In addition, a growing body of research has demonstrated that the cost of transitioning to 100 percent carbon dioxide free electricity increases steeply as the 100 percent mark is approached. The higher costs of the so-called “last 10% challenge” are driven largely by the seasonal mismatch between variable renewable energy generation and consumption, NREL said.
NREL said it has been studying how to solve the last 10 percent challenge, including outlining key unresolved technical and economic considerations and modeling possible pathways and system costs.
“There is no one single solution to transitioning the power sector to renewable and clean energy technologies,” Paul Denholm, principal investigator and lead author of the study, said in a statement. “There are several key challenges that we still need to understand and will need to be addressed over the next decade to enable the speed and scale of deployment necessary to achieve the 2035 goal.”
APPA Releases Guide For Public Power Utilities Interested In Community Solar
August 17, 2022
by Paul Ciampoli
APPA News Director
August 17, 2022
The American Public Power Association (APPA) recently released the Municipal Utility Community Solar Workbook, a free how-to guide for utilities interested in exploring community solar.
The workbook is a culmination of expert advice, resources, and best practices from the Municipal Utility Community Solar Working Group, the Department of Energy (DOE), and the National Renewable Energy Laboratory (NREL).
From identifying community interest to selecting an appropriate site, determining budgeting and pricing models, working with vendors, and enrolling customers in the program, this guidebook walks utilities through the processes, materials, and considerations for exploring community solar projects from a public power perspective.
Utilities can also review the additional considerations necessary for establishing community solar programs that reach or support customers with low to moderate incomes and prioritize equity.
The guide is available for download here.
DOE and APPA will be hosting a release webinar for the workbook on September 1 at 2:00 PM EDST. Register for the webinar at this link.
Solar Power Installations Slow Because Of Supply Chain, Other Issues: EIA
August 15, 2022
by Peter Maloney
APPA News
August 15, 2022
Solar power installations are running about 20 percent behind schedule due to supply chain and other issues, according to the Department of Energy’s Energy Information Administration (EIA).
Developers had planned to install 17.8 gigawatts (GW) of utility-scale solar photovoltaic (PV) generating capacity in 2022, according to the EIA’s June 2022 Preliminary Monthly Electric Generator Inventory. However, over the first six months of the year, only 4.2 GW of capacity came online, less than half of what the industry had planned to install, a 20 percent shortfall.
“Our preliminary data from January through June 2022 show that PV solar installations were delayed by an average of 4.4 GW each month, compared with average monthly delays of 2.6 GW during the same period last year,” according to the EIA. In most cases, the reported delays are for six months or less, the EIA added.
Most of the projects that are due to come online in the next 18 months are already under construction, the EIA noted.
About 1.9 GW of solar installations under construction have been delayed but are still scheduled to come online in 2022, and 1.7 GW of projects under construction have been delayed to 2023, the EIA said.
Various factors could cause delays, the EIA noted, including broad economic factors, such as supply chain constraints, labor shortages, and high prices of components, as well as factors specific to electric generation projects, such as obtaining permits or testing equipment.
In particular, the EIA noted that in February, the Bush administration eased but did not end tariffs on imported crystalline silicon solar products from China, raising the tariff-rate quota, or threshold for imposing higher tariffs, from 2.5 GW to 5.0 GW and excluding bifacial panels from the extended tariffs.
In April, the Department of Commerce announced an anti-dumping circumvention investigation of solar cells and modules imported from Cambodia, Malaysia, Thailand, and Vietnam, countries that allegedly use parts made in China that otherwise would be subject to tariffs.
In a June executive action, President Joseph Biden sought to advance the deployment of the U.S. solar panel industry by authorizing the easing of import duties for 24 months for solar cells and modules imported from the countries under investigation. Biden also invoked the Defense Production Act to expand domestic production of solar modules.
California Energy Commission Sets Preliminary 25 GW By 2045 Offshore Wind Goal
August 15, 2022
by Peter Maloney
APPA News
August 15, 2022
The California Energy Commission (CEC) recently adopted a report establishing offshore wind goals, bringing the state one step closer to developing its coastal resources.
Preliminary findings of the report set planning goals of 2,000 to 5,000 megawatts (MW) of offshore wind by 2030 and 25,000 MW by 2045.
The report is the first of four that the CEC has been directed to produce by AB 525 by no later than June 30, 2023. Under the legislation, the CEC, in coordination with federal, state, and local agencies and a wide variety of stakeholders, must develop a strategic plan for offshore wind energy developments off the California coast in federal waters and submit it to the California Natural Resources Agency and the state’s Legislature.
Among other conclusions, the CEC said that for 2030 it would be “prudent” to have the AB 525 strategic plan evaluate at least the current adopted 2032 Integrated Resource Plan (IRP) amount of offshore wind of 1,700 MW, potentially up to nearly 5,000 MW, which is what can be accommodated on existing transmission.
Offshore wind capacity beyond that amount “appears infeasible from a transmission perspective by 2030, the report found. For 2045, “there is greater possibility of achieving some or all of the transmission upgrades examined by the state’s ISO [independent system operator],” the report said, concluding that “this suggests the CEC may consider establishing a MW planning goal for 2045 of at least 10 GW to 14.3 GW for 2045.”
The authors of the report also recommended that the complementary nature of offshore wind to solar power outputs, both daily and in the winter, suggests that the CEC should establish offshore wind planning goals that are “reasonably higher” than the current adopted amount of offshore wind in the state’s IRP.
The report’s authors cautioned, however, “the recommended MW planning goals do not consider potential impacts to ocean use and environmental considerations.” They added, “the assessment of potential impacts and the strategies for addressing those impacts that are identified for the strategic plan will inform and may potentially limit the amount of maximum feasible capacity of offshore wind and the MW planning goals that are ultimately identified in the strategic plan.”
CEC staff will next study the economic benefits of offshore wind in relation to seaport investments and workforce development needs. The staff will also create a roadmap to develop a permitting process for offshore wind energy facilities and associated electricity and transmission infrastructure. The entire plan must be submitted to the Legislature by June 2023.
Plans for renovations to prepare for offshore wind activities are already under way at the Port of Humboldt Bay with $10.5 million in funding approved by the CEC earlier this year. Governor Gavin Newsom’s 2022–23 budget proposes an additional $45 million for other needed upgrades at waterfront facilities.