Utility scale battery costs down about 70%, according to the EIA
October 27, 2020
by Peter Maloney
APPA News
October 27, 2020
The costs of utility scale battery storage in the United States fell about 70% between 2015 and 2018, according to data compiled by the Energy Information Administration (EIA), a part of the Department of Energy.
The average energy capacity cost of utility-scale battery storage went from $2,152 per kilowatt hour (kWh) in 2015 to $625/kWh in 2018, according to the EIA. The agency noted, however, that costs vary widely by region and by application.
Regionally, average utility scale battery costs between 2013 and 2018 ranged from $1,946/kWh in the PJM Interconnection to as low as $947/kWh in Hawaii. And in California, which had the most battery capacity of any state in 2019, average battery storage cost was $1,522/kWh.
In its analysis, the EIA grouped cost data into regions based on regional transmission organizations and independent system operators and aggregated entities to avoid disclosing confidential information.
Battery storage costs are usually published in terms of energy capacity, that is, cost per kilowatt hour or the total amount of energy that can be stored by a battery. But costs can also be expressed in terms of power capacity, or cost per kilowatt. Power capacity is the maximum amount of power a battery can provide at a given point in time. In power capacity cost terms, short-duration batteries cost less than long-duration batteries. In energy capacity cost terms, long-duration batteries are less expensive.
In PJM where most batteries are used for frequency regulation, there is an emphasis on shorter duration batteries rather than batteries capable of discharging over longer periods of time. That makes power capacity installed costs a better indicator of price for value in PJM, EIA said.
About two-thirds of battery storage capacity in California is used for frequency regulation. Batteries in the state also provide ancillary services, black start service and are used to help ease transmission congestion, EIA added.
At the end of 2018, the United States had 869 megawatts (MW) of installed battery power capacity and 1,236 megawatt hours (MWh) of battery energy capacity. In 2019, there was 152 MW of battery storage capacity installed in the United States and another 301 MW added through July 2020, according to EIA data.
The EIA expects battery storage to increase by more than 6,900 MW in the next few years with about 2,300 MW of that total being reported April and June. Large battery storage systems are increasingly being paired with renewable energy plants to increase grid reliability and resilience, EIA noted.
Just before the EIA published its data on Oct. 23, investment bank Lazard released its annual report on energy storage costs.
Lazard’s latest annual Levelized Cost of Storage Analysis (LCOS 6.0) shows that storage costs have declined across most use cases and technologies, particularly for shorter-duration applications, in part driven by evolving preferences in the industry regarding battery chemistry.
Calif. CCA Clean Power Alliance seeks renewable energy, storage proposals
October 27, 2020
by Paul Ciampoli
APPA News Director
October 27, 2020
California community choice aggregator Clean Power Alliance recently released a request for offers to expand its renewable energy portfolio.
Clean Power Alliance on Oct. 22 said it will solicit offers for long-term clean energy power purchase agreements, with an eye towards diversifying its renewable energy sources, adding long-duration storage, and securing structured products to deliver energy at specific key times.
The CCA said within the renewable energy contract category, it will be seeking renewable portfolio standard (RPS)-eligible generation and RPS plus storage projects that are 5 megawatts to 300 MW in size.
Within the standalone storage contract category, Clean Power Alliance will be seeking standalone storage projects that are 5 MW–100 MW in size.
For projects that include a storage component, eligible storage durations include conventional four-hour duration as well as longer storage duration (up to 12-hour duration).
Eligible projects must have a commercial operation date no later than the end of 2025. However, projects with commercial online dates of December 21, 2023 or sooner are preferred.
The CCA said that the projects solicited under the RFO will complement its recently expanded portfolio, which includes new solar plus storage, standalone storage, wind, and small hydroelectric projects approved by the CCA’s board over the past year.
Bid submissions are due by Nov. 20, 2020.
Clean Power Alliance serves approximately three million customers and one million customer accounts across 32 communities throughout Southern California.
Additional details about the RFO are available here.
The American Public Power Association has initiated a new category of membership for community choice aggregation programs.
DOE partnership to help remote and island communities improve electric service
October 26, 2020
by Peter Maloney
APPA News
October 26, 2020
The Department of Energy (DOE) has announced a partnership that aims to support remote and islanded communities seeking to transform their energy systems and lower their vulnerability to energy disruptions.
The Energy Transitions Initiative Partnership Program (ETIPP) draws together resources from several DOE offices and laboratories that will work with five community groups.
Together the partners will work with competitively selected communities to plan for, withstand, and recover from disruptions. In fall 2020, communities will be able to apply to participate in the multi-year program.
The ETIPP partners will identify and advance strategic, tailored technological solutions designed to bolster community resilience and reduce economic risk for the selected communities.
The targets of the program include 31 rural villages in Alaska prone to flooding and erosion, inland American Indian reservations in rural Northern California at risk of being islanded from the grid should a wildfire disable a single transmission line, year-round residents of 15 island communities off the coast of Maine, and communities in the U.S. Virgin Islands.
The DOE offices involved in the Energy Transitions Initiative (ETI) initiative are the Office of Strategic Programs, the Water Power Technologies Office, and the Solar Energy Technologies Office. The participating laboratories are the National Renewable Energy Laboratory (NREL), the Pacific Northwest National Laboratory, the Lawrence Berkeley National Laboratory, and the Sandia National Laboratories.
“The same technical assistance framework NREL developed and used in collaboration with ETI to advance successful energy transitions in Hawaii and the U.S. Virgin Islands can be tailored to ETIPP communities seeking to strengthen their resilience posture and mitigate their risks,” Elizabeth Doris, laboratory program manager for state, local, and tribal governments at NREL, said in a statement.
The community groups involved in the program are the Alaska Center for Energy and Power, the Coastal Studies Institute in North Carolina, the Hawaii Natural Energy Institute, the Island Institute in Maine, and the Renewable Energy Alaska Project.
Calif. PUC votes to provide storage incentives for low-income customers
October 26, 2020
by Paul Ciampoli
APPA News Director
October 26, 2020
The California Public Utilities Commission on Oct. 22 revised its Self-Generation Incentive Program (SGIP) to increase focus on supporting energy storage for low income customers and communities, medically vulnerable customers and facilities that provide critical services.
Specifically, the CPUC approved $108.5 million in additional funding for the SGIP “Equity Budget.” This funding provides incentives for customers who install energy storage systems and who are low-income residents or local governments, schools, nonprofits, or small business customers located in disadvantaged or low-income communities, or in Indian Country.
The CPUC noted that after it authorized increased incentive amounts for the Equity Budget in late 2019, customer demand for the program greatly increased. All authorized funding was quickly allocated and waiting lists were created.
Last week’s decision does not increase the absolute amount of funding for SGIP, but transfers funds to the Equity Budget from funding set aside for general large-scale storage projects, i.e., non-residential storage systems installed by customers that are not low-income or located in disadvantaged or low-income communities.
After the transfer of funds, the general large-scale storage budget will still have funding available for future projects.
The proposal voted on by the state utility commission is available here.
The SGIP was established in 2001 to increase deployment of distributed generation and energy storage systems to facilitate the integration of those resources into the electrical grid, improve efficiency and reliability of the distribution and transmission system, and reduce emissions of greenhouse gases, peak demand, and ratepayer costs.
Additional information about the SGIP is available here.
Glendale, Calif., utility wins approval for efficiency, DR programs
October 23, 2020
by Peter Maloney
APPA News
October 23, 2020
The Glendale City Council in California has unanimously approved multiple energy efficiency and demand response programs for Glendale Water & Power, the city’s public power utility.
The new clean energy programs are part of Glendale Water & Power’s efforts to reduce its reliance on fossil fuels. Last summer, the city council approved the utility’s plan to repower the aging Grayson Power Plant.
The Oct. 13 approvals included residential and commercial demand response programs, energy efficiency measures for commercial customers, and approval to begin negotiations for the development of a residential virtual power plant program.
The new demand response program would allow Glendale Water & Power to declare demand response events on peak days to reduce peak electrical load. Residential customers may participate in the program by using an existing smart thermostat and receiving a $50 incentive to join the program or by purchasing a new smart thermostat with a $100 discount through the program.
On peak days, Glendale Water & Power will adjust the temperature of the thermostats of participating customers to help reduce electrical demand. Residential customers will receive a $50 annual incentive for participating in the demand response program.
Commercial customers with demand of 50 kilowatts (kW) or greater are also eligible to participate and will receive a complimentary program site assessment to help identify load reduction strategies.
Commercial customers may join the program at two different levels: a 4-hour reduction ($10/kW-month or $50/kW-year) or a 2-hour reduction ($5/kW-month or $25/kW-year). Glendale Water & Power says the program will reduce peak energy demand by up to 10 megawatts (MW) on up to 15 peak days per year. Franklin Energy Services will provide services for the program.
The city council also approved an energy efficiency program for commercial customers that will provide eligible businesses with the direct installation of energy efficient lighting and heating, ventilation, and air conditioning upgrades. Glendale Water & Power expects the upgrades to reduce annual electric usage in the city by up to 35,000 kilowatt hours (kWh) and reduce demand by up to 8.3 MW. Lime Energy Services will be contracted to provide the services for the program.
The city council also directed Glendale Water & Power to complete negotiations with Sunrun for a proposed virtual power plant program that would provide solar generation and battery storage from 3,000 to 4,000 single-family residences and 30 to 40 multi-family properties.
The proposed program would deliver solar energy and an average of 25.25 MW of solar-powered battery storage each year to Glendale over 25 years and would provide backup power to participating customers in the event of a grid outage.
Once contract negotiations are complete, the contracts for the virtual power plant program will be presented to the city council for consideration. The utility says it would be the largest virtual power plant program of its kind.
After the contracts are finalized, Glendale Water & Power expects the new clean energy programs to get started early in 2021. When fully implemented, the utility expects the programs to deliver an average peak capacity of 38.4 MW.
“Our new clean energy programs show that Glendale is at the forefront of a clean energy commitment and will help transition GWP to have 100% renewable energy sources by 2045,” Steve Zurn, general manager of Glendale Water & Power, said in a statement.
The utility’s plan for the Grayson plant includes a 75 MW, 300 MWh battery storage system, as much as 50 MW of distributed energy resources that include solar photovoltaic systems, energy efficiency and demand response programs, and 93 MW of thermal generation from up to five internal combustion engines.
APPA holds virtual grading meeting to vet Reliable Public Power Provider applications
October 23, 2020
by Paul Ciampoli
APPA News Director
October 23, 2020
The American Public Power Association’s first-ever virtual grading meeting for Reliable Public Power Provider (RP3) applications was held this month.
“The COVID-19 pandemic prevented APPA from hosting the grading meeting in our offices this year,” noted Alex Hofmann, Vice President, Technical and Operations Services, at APPA. “However, the meeting went smoothly thanks to the flexibility and dedication of the RP3 Panel and guest veteran graders,” he said.
APPA’s RP3 program recognizes utilities that demonstrate high proficiency in reliability, safety, workforce development, and system improvement. Utilities keep the RP3 designation for three years.
APPA received 111 2020 RP3 applications. A total of 18 panel members participated in this month’s virtual grading meeting, as well as as well as six veteran graders.
The panel will be meeting virtually again at the beginning of December to finalize the grades after reviewing responses to requests for information that will be sent out to utilities the week of Oct. 26.
A total of 114 public power utilities earned the RP3 designation earlier this year from APPA and there are currently a total of 278 utilities with a designation.
EPA proposes to revise the Cross-State Air Pollution Rule Update
October 23, 2020
by Paul Ciampoli
APPA News Director
October 23, 2020
The Environmental Protection Agency on Oct. 15 proposed the Revised Cross-State Air Pollution Rule (CSAPR) Update in order to fully address the outstanding interstate pollution transport obligations of 21 states for the 2008 ozone National Ambient Air Quality Standards (NAAQS).
Starting in the 2021 ozone season, the proposed rule would require additional emissions reductions of nitrogen oxides (NOx) from power plants in 12 states.
The action addresses the remand of the CSAPR Update by the U.S. Court of Appeals for the D.C. Circuit on September 13, 2019, in Wisconsin v. EPA. The court found that EPA failed to fully eliminate significant contribution to nonattainment and interference with maintenance of the 2008 ozone NAAQS from upwind states by downwind areas’ attainment dates.
EPA is proposing that for 9 of the 21 states for which the CSAPR Update was found to be only a partial remedy (Alabama, Arkansas, Iowa, Kansas, Mississippi, Missouri, Oklahoma, Texas, and Wisconsin), their projected NOx emissions in the 2021 ozone season and thereafter will not significantly contribute to a continuing downwind nonattainment and/or maintenance problem.
Therefore, the states’ CSAPR Update federal implementation plans or the state implementation plans subsequently approved to replace certain states’ CSAPR Update Federal Implementation Plans fully address their interstate ozone transport obligations for the 2008 ozone NAAQS.
For the remaining 12 states (Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia), their projected 2021 emissions were found to contribute at or above a threshold of 1 percent of the NAAQS to the identified nonattainment and/or maintenance problems in downwind states.
EPA is proposing to issue new or amended federal implementation plans to revise state emission budgets that reflect additional emissions reductions from electric generating units beginning with the 2021 ozone season (May 1 – September 30).
The federal implementation plans would require power plants in the 12 linked states to participate in a new CSAPR NOx Ozone Season Group 3 Trading Program. The new program largely replicates the existing CSAPR NOx Ozone Season Group 2 Trading Program, with the main differences being the geography and budget stringency.
In addition, EPA is proposing to adjust these states’ emission budgets for each ozone season (2021-2024) thereafter until air quality projections demonstrate resolution of the downwind nonattainment and/or maintenance problems for the 2008 ozone NAAQS.
The emission budgets signify a control strategy that reflects the full optimization of existing selective catalytic reduction controls (SCRs), optimize idled SCRs and upgrades of low NOx burners for the 2022 ozone season, with an estimated marginal cost of $1,600 per ton. Based on EPA’s analysis the proposal is projected to result in a reduction of 17,000 tons of NOx during the summertime ozone season in 2021 and subsequent years.
EPA is proposing to authorize a one-time conversion of allowances banked from 2017 to 2020 under the CSAPR NOx Ozone Season Group 2 Trading Program into a limited number of allowances that can be used for compliance in the CSAPR NOx Ozone Season Group 3 Trading Program.
For non-electric generating units (EUGs) and emissions sources, EPA analyzed whether any emissions reductions should be required from non- EGUs to address significant contribution under the 2008 ozone NAAQS.
The agency’s analysis suggests that there are relatively fewer emissions reductions available at a cost threshold comparable to the cost threshold selected for EGUs.
Emission reductions from non- EGUs are estimated to have a relatively small effect on any downwind receptor in the year by which such controls could likely be installed. Therefore, EPA proposes that limits on ozone season NOx emissions from non-EGU sources are not required to eliminate “significant” contribution under the 2008 ozone NAAQS.
EPA is under a court order to finalize the proposal by March 15, 2021. There will a 45-day public comment period once the proposed rule is published in the Federal Register.
EPA plans to host a virtual public hearing in November 2020.
Missouri regulators open proceeding to determine long-term RTO membership benefits
October 22, 2020
by Paul Ciampoli
APPA News Director
October 22, 2020
The Missouri Public Service Commission has opened a proceeding to determine the long-term benefits of continued membership in a regional transmission organization (RTO) by the state’s investor-owned electric utilities.
“The Commission believes there are benefits in RTO membership but long-term costs and commitments of RTO membership, especially given the structure, services, and membership of both Southwest Power Pool (SPP) and Midcontinent Independent System Operator (MISO) continue to change significantly with the passage of time,” the PSC said in an Oct. 19 news release.
In order to determine whether continued membership in an RTO is in the ratepayers’ best interest, the PSC “must inquire into the nature of the benefits of RTO membership, the monetized value of those benefits, and what time horizons should be employed to compare asset lives (costs) to the values of benefits streams,” it said.
The PSC directed the state’s investor-owned utilities to take part in a workshop and cooperate with Commission Staff in its investigation.
PSC Staff and the electric utilities will determine:
- The kind of information needed to respond to the Commission’s current and previous orders on RTO membership;
- Whether such information is reasonably and economically available, and if not, what kind of information could be used as a proxy to control costs and expeditiously respond to the Commission;
- The cost of gathering, analyzing, and interpreting such information; and
- Whether there are any identifiable “deal breaker” events or categories of events that would make it unreasonable for a Missouri investor-owned utility to remain in an RTO
PSC staff will file a report related to its findings by June 30, 2021.
The PSC order opening the proceeding is available here.
Calif. CCA Central Coast Community Energy receives “A” issuer credit rating
October 22, 2020
by Paul Ciampoli
APPA News Director
October 22, 2020
Central Coast Community Energy on Oct. 16 received an “A” issuer credit rating from Standard & Poor’s, which Central Coast Community Energy said is the highest rating received by a California community choice aggregator (CCA).
S&P’s issuer credit rating and “stable” outlook is an independent assessment of the CCA’s operational and financial strategies over the long term, “confirming the agency’s economic stability and footing for future success,” Central Coast Community Energy said in a news release.
Central Coast Community Energy “is proud to receive the first ‘A’ investment grade credit rating among California CCAs. This is a testament to the hard work and forward thinking” the CCA’s staff and leadership have demonstrated since launching in 2018, said Central Coast Community Energy Policy Board Chair and Santa Cruz County Supervisor Bruce McPherson.
“In that short time this agency has set a very high bar in terms of financial strength, operational responsibility, innovative energy procurement and energy programs, not to mention extending CCA benefits to the entire Central Coast,” he said.
The rating will allow the CCA “to embark on an even more impactful path towards reducing greenhouse gas emissions through local energy programs and energy procurement,” and it helps to ensure the “longevity and continued success” of the CCA on behalf of its communities.
Central Coast Community Energy said that the rating recognizes the CCA’s stability within the California CCA market and the strong socio-economic conditions of its growing service area.
Central Coast Community Energy serves more than 400,000 customers throughout the Central Coast, including agriculture, commercial and residential customers in communities located within Monterey, San Benito, San Luis Obispo, Santa Barbara and Santa Cruz counties.
S&P’s rating action emphasized the CCA’s strong economic fundamentals, comprehensive governance structure, robust energy risk management policy, and experienced executive leadership as contributing factors to its being the first CCA to receive an ‘A’ rating and “stable” outlook.
The rating enables the CCA to continue providing electric service and innovative energy programs at competitive rates to its 33 member agencies and over 400,000 agriculture, commercial, and residential customers, Central Coast Community Energy said.
In addition, the rating will aid in increasing the number of counterparties competing for Central Coast Community Energy wholesale contracts, lower transaction costs, and make innovative financing structures accessible to help the CCA continue to develop solutions to California’s greatest energy challenges, Central Coast Community Energy said.
The American Public Power Association has initiated a new category of membership for community choice aggregation programs.
AVANGRID to acquire New Mexico-based IOU PNM Resources
October 21, 2020
by Paul Ciampoli
APPA News Director
October 21, 2020
Connecticut-based energy company AVANGRID will acquire New Mexico investor-owned utility PNM Resources in a transaction with an $8.3 billion enterprise value, the companies announced on Oct. 21.
As a result of the transaction, which has been approved by the boards of the two companies, PNM’s shareholders will receive approximately $4.318 billion in cash.
PNM said that the transaction will create a large, diversified national regulated utility and renewable energy platform with approximately $14 billion of rate base and more than four million electric and natural gas utility customers.
AVANGRID is the third largest wind operator in the U.S. and has more than 7.5 gigawatts of installed wind and solar capacity.
“The strategic combination with PNM Resources also provides a platform for AVANGRID to expand its renewables business in the Southwest beyond its existing 1.9-gigawatt capacity wind projects in New Mexico and Texas and 200 megawatts of wind and solar capacity in Arizona,” PNM said in a news release.
PNM said it remains committed to exiting coal
PNM said it remains committed to exiting coal through the approved abandonment of San Juan Generating Station in 2022 and the continued efforts to exit its 200-megawatt ownership interest in the Four Corners Power Plant earlier than originally planned. The plants are located in New Mexico.
PNM said that it sees the potential for additional customer savings by exiting the plant sooner than the expiration of the ownership and coal supply agreements in 2031. “An earlier exit from Four Corners also opens the door for the combined company to bring additional renewable resources onto the grid in support of New Mexico’s increasing renewable energy standards and 2045 carbon-free mandate,” it said.
The transaction is subject to PNM Resources shareholder approval, regulatory approvals from the New Mexico Public Regulation Commission, Public Utility Commission of Texas, Federal Energy Regulatory Commission, Department of Justice, Nuclear Regulatory Commission, Federal Communications Commission and Committee on Foreign Investment in the United States, and other customary closing conditions.
The transaction is expected to close between October and December 2021.
Connecticut-based AVANGRID has two primary lines of business: Avangrid Networks and Avangrid Renewables.
Avangrid Networks owns eight electric and natural gas utilities, serving more than 3.3 million customers in New York and New England. Avangrid Renewables owns and operates a portfolio of renewable energy generation facilities across the United States. Spain’s Iberdrola owns 81.5% of the outstanding common stock of AVANGRID.
Through its regulated utilities, Public Service Company of New Mexico and Texas-New Mexico Power, PNM Resources has approximately 2,811 megawatts of generation capacity and provides electricity to approximately 790,000 homes and businesses in New Mexico and Texas.