Omaha Public Power District Wins Grant For Its First Utility Scale Storage Project
June 22, 2020
by Peter Maloney
APPA News
Posted June 22, 2020
The Omaha Public Power District (OPPD) has won a $600,000 grant to fund a pilot project that would be the first utility scale battery energy storage device on the utility’s system.
The grant, from the Nebraska Environmental Trust, included matching funds from OPPD. Together, those funds are being used to build an approximately 1 megawatt (MW) battery at an OPPD substation.
The aim of the pilot project is to test how battery storage can be integrated into OPPD’s grid to provide load relief and voltage support at the substation level.
“This is a very big deal and the grant helps us accelerate our utility scale storage efforts,” Michal Lisowyj, alternative energy specialist at OPPD, said in an article in The Wire, OPPD’s newsletter. “We want to understand how various use cases and recurring cycling degrades the battery, much like a cell phone battery that doesn’t hold the same charge over time.”
OPPD said the battery would be small enough to fit in a storage container, enabling the public power utility to perform research that could be beneficial for its operations and customers, as well as for other utilities in Nebraska.
In addition, OPPD says the research gleaned in the pilot project will help it understand the procurement, construction, and operations of small energy-storage applications and how to scale for potential future applications.
“Given changes to OPPD’s generation mix – adding more variable renewable resources and retiring conventional resources – and grid operations, we see energy storage as a valuable technology in the future,” Courtney Kennedy, manager of alternative energy programs at OPPD, said via email.
“As costs come down, policies are being developed, and technology is evolving. We see now as the right time to test out the technology on a smaller scale to understand its opportunities and challenges to integrating it in our operations.”
For the past 10 years, OPPD has been growing its renewable energy portfolio, which has been primarily wind generation with smaller amounts of landfill gas, community solar, and hydroelectric power.
The public power utility is in the process of adding between 400 MW and 600 MW of solar power and natural gas backup to meet load growth and maintain system resiliency.
OPPD has set of goal of having net zero carbon dioxide emissions by 2050 and is studying several initiatives to meet that target.
Nebraska Environmental Trust is funded by Nebraska Lottery proceeds. The organization says it has awarded more than $320 million in conservation projects in the state since 1994.
NPPD solar project tied to storage
Another public power utility, Nebraska Public Power District, has also been pursuing energy storage.
In 2019, the City Council for Norfolk, Neb., approved an agreement for the state’s largest community solar project with NPPD that will be tied to a battery energy storage system (BESS) demonstration project expected to be in operation by mid-2020.
APPA storage tracker
The American Public Power Association recently launched a Public Power Energy Tracker, which is a resource for association members that summarizes energy storage projects undertaken by members that are currently online.
The tracker is available here.
Report Recommends West Coast Corridor of Electric Truck Charging Stations
June 22, 2020
by Peter Maloney
APPA News
Posted June 22, 2020
A group representing over a dozen West Coast utilities has released a report that recommends adding electric vehicle charging stations for freight haulers and delivery trucks along the interstate corridor running from Canada to Mexico.
The West Coast Clean Transit Corridor Initiative proposes a phased approach to installing charging stations along the Interstate-5 corridor.
The first phase calls for 27 charging sites along the 1,300-mile length of I-5 at 50-mile intervals for medium-duty electric vehicles, such as delivery vans, by 2025. Then, 14 of the 27 charging sites would be expanded to accommodate charging for electric big rigs by 2030. Of the 27 proposed sites, 16 are in California, five are in Oregon and six are in Washington.
The report proposes an additional 41 sites on other highways that connect to I-5. Those highways are Interstates 8, 10, 80, 210 and 710 and state routes 60 and 99 in California, I-84 in Oregon, and I-90 in Washington.
In the report’s scenario, each charging station would be equipped with up to 10, 350-kilowatt (kW) charging ports for a total peak load of 3.5 megawatts (MW). Each of the combined medium-heavy duty charging stations would be equipped with up to an additional 10, 2 MW charging ports for a maximum 23.5 MW peak load. The co-location approach would minimize the need for additional grid upgrades, reduce permit processing times, and minimize costs, the report said.
Although heavy-duty trucks account for only 5% of the vehicles on U.S. roads, they contribute 23% of all transportation emissions, the report said. In California, the transportation sector accounts for nearly 80% of the state’s air pollution and more than 40% of all greenhouse gas emissions, and Washington and Oregon face “similar environmental challenges” with transportation being the largest contributor to air pollution and greenhouse gas emissions in those states as well, according to the report.
By 2030, medium and heavy-duty electric trucks could make up over 8% of all trucks on the road in California, Oregon, and Washington, the report said.
“Electrifying transportation is a key component to reaching our goal of net-zero carbon emissions by 2040,” Bill Boyce, manager of electric transportation at Sacramento Municipal Utility District, one of the report’s sponsors, said in a statement.
The report was commissioned by three public power utilities; Los Angeles Department of Water & Power, Sacramento Municipal Utility District, and Seattle City Light, two agencies: Northern California Power Agency and Southern California Public Power Authority, and six investor-owned utilities: Pacific Gas and Electric, Pacific Power, Portland General Electric, Puget Sound Energy, San Diego Gas & Electric, and Southern California Edison.
The report was completed by engineering firm HDR with analysis by CALSTART, S Curve Strategies, and Ross Strategic.
Several California utilities already have programs that support the adoption of electric trucks, but more support would be needed to reach electrification levels identified in the study and to meet state climate goals, the report said. The report recommends expanding state, federal or private programs that provide funding for electrification that could accelerate electric truck adoption.
The report does not give a total cost for implementing its recommendations, saying that such costs “can be challenging to predict given the numerous variables,” such as equipment selection, site location, distance from a utility interconnection, electric circuit capacity, permits, and labor costs. Total costs would have to be determined by individual assessments with in-person site visits on a site-by-site basis, the report said.
The report acknowledged that the proposed electric truck charging sites could take “significant” time to plan, permit, design, and build, presenting a chicken-or-the-egg dilemma in terms of whether to build charging stations or to wait for electric vehicle penetration rates to rise before building charging stations for them.
The report’s authors estimated that the medium-duty truck charging stations could each take between one and two years to plan and build while charging sites for heavy duty trucks could each take between three and five years to plan and build.
The report also noted that most electric utilities in California, Oregon, and Washington have enough capacity in urban areas along the I-5 corridor to support interconnections with the proposed medium duty charging sites.
In rural areas, however, capacity constraints would be encountered for some electric utilities in the three West Coast states and the potential need to install new distribution circuits in rural areas could significantly increase the cost of a charging site interconnection and would most likely require additional time and planning.
In all locations, most loads over 10 MW would require extensive upgrades to the electric grid and, most likely, a new customer-dedicated substation, which would likely translate into a “high probability” the proposed heavy duty truck charging sites would require a new substation and a new line interconnection, the report said.
The report argues that a network of publicly available charging sites could help promote standardization of electric charging infrastructure for electric trucks and says electric utilities are “uniquely positioned” to build on opportunities to overcome the challenges identified in the report.
FERC Commissioner McNamee Says He Intends To Serve For The Foreseeable Future
June 19, 2020
by Paul Ciampoli
APPA News Director
Posted June 19, 2020
Federal Energy Regulatory Commissioner Bernard McNamee on June 18 said that he intends to continue serving as a Commissioner for the foreseeable future.
He made his remarks at FERC’s monthly open meeting.
In January, McNamee announced that he would not seek another term at the Commission but said he would stay longer at the agency if needed. McNamee’s current term expires at the end of this month.
He is permitted to remain a Commissioner until a successor is confirmed or the end of the current Congress.
The U.S. Senate in December 2018 confirmed McNamee to join FERC as a Commissioner. McNamee, a Republican, previously served in several high-level positions at the U.S. Department of Energy, as well as at McGuireWoods LLP and the Texas Public Policy Foundation.
McNamee filled the seat on the Commission vacated by Robert Powelson, a Republican, who left the Commission to become President and CEO of the National Association of Water Companies.
Calif. Community Choice Aggregators Sign PPAs For Solar-Storage Capacity
June 19, 2020
by Peter Maloney
APPA News
Posted June 19, 2020
Two California community choice aggregators, Monterey Bay Community Power and Silicon Valley Clean Energy, have signed a power purchase agreement (PPA) with 8minute Solar Energy for the output of a solar-plus-storage plant the company is building.
8minute Solar Energy’s 200-megawatt (MW) Aratina Solar Center includes 150 megawatt-hours (MWh) of storage and is scheduled to come online before year-end 2023. It is being build in Kern County, Calif., where 8minute built eight other solar projects.
Monterey Bay Community Power has contracted for 120 MW of solar power and 30 MW of battery storage with a three-hour discharge duration from the Aratina project, which is sufficient to meet between 7% and 8% of its retail load. Silicon Valley Clean Energy has contracted to buy 80 MW of solar power and 20 MW of battery storage with a three-hour duration from 8minute Solar Energy, which will be able to meet 6.6% of the utility’s annual retail load.
The PPA came out of a joint request for offers issued by Monterey Bay Community Power and Silicon Valley Clean Energy in April 2019.
In addition to the PPA with 8minute Solar Energy, the April request for proposals also resulted in the community choice aggregators signing a 20-year PPA in late May with NextEra Energy for output from its 500-MW Yellow Pine Energy Center in Clark County, Nevada, starting in December 2022.
Monterey Bay Community Power has contracted for 75 MW of solar capacity and 39 MW of energy storage, enough to meet 5% of its annual retail load. Silicon Valley Clean Energy has contracted for 50 MW of solar capacity and 26 MW of energy storage, enough to meet 4% of its annual retail load.
The solicitation also resulted in the community choice aggregators signing contracts for geothermal power, one with Coso Geothermal Power Holdings and the other with Ormat Technologies, as well as another solar-plus-storage contract with Rabbitbrush LLC.
The contract with Coso calls for Monterey Bay Community Power to receive 67.5 MW per year and for Silicon Valley Clean Energy to receive 43 MW per year for five years. For the following 10 years, power deliveries to the aggregators drop to 50 MW per year and 28 MW per year, respectively.
Under the Ormat contract, Monterey Bay Community Power and Silicon Valley Clean Energy will each purchase 7 MW from Ormat’s 30-MW Casa Diablo-IV geothermal project in Mammoth Lakes, Calif., which is due online by year-end 2021.
The 10-year PPAs have a fixed MWh price that includes energy, capacity, environmental attributes, and all other ancillary benefits. The remaining 16 MW of capacity from the geothermal plant is contracted to be sold to Southern California Public Power Authority under a PPA signed in early 2019.
Monterey Bay Community Power and Silicon Valley Clean Energy also signed 15 year PPAs for a combined capacity of 100 MW of solar power and 20 MW of battery storage from a project Rabbitbrush is building in Rosamond, Calif., that is due online in June 2022.
“The Aratina Solar Center, complete with battery storage, will allow us to store and deliver solar power when our customers need it — well into the evening hours — reducing our reliance on carbon-emitting gas plants and moving us ever closer to a decarbonized grid,” Girish Balachandran, CEO of Silicon Valley Clean Energy, said in a statement.
House Bill Includes Several Items of Importance To Public Power
June 19, 2020
by Paul Ciampoli
APPA News Director
Posted June 19, 2020
House Speaker Nancy Pelosi, D-CA, on Jun 18 announced additional details on Democrats’ comprehensive infrastructure package, the Moving America Forward Act, which includes several items of importance to public power.
The House Transportation and Infrastructure Committee recently completed consideration of the Investing in a New Vision for the Environment and Surface Transportation in America (INVEST in America) Act, a five-year surface transportation bill that would authorize $494 billion for transit, highways, and rail. On the evening of Thursday, June 18, the House Transportation and Infrastructure Committee approved the INVEST in America Act.
This will serve as the basis for the Moving America Forward Act, which will add several significant provisions, including on clean energy, tax, healthcare, drinking water, and broadband.
The Moving America Forward Act includes the following sections of importance to public power:
* $70 billion for clean energy infrastructure, including energy efficiency, grid modernization, and the development of an electric vehicle (EV) charging network;
* Reinstatement of the ability to issue direct payment bonds;
* Reinstatement of the ability to issue tax-exempt advance refunding bonds; and
* An increase in the small issuer exemption from $10 million to $30 million.
Pelosi said the House will take up the Moving America Forward Act before July 4.
CPUC Grants Conditional PSPS Approvals, Accelerates Microgrid Deployments
June 18, 2020
by Peter Maloney
APPA News
Posted June 18, 2020
The California Public Utilities Commission (CPUC) last week granted conditional approval of wildfire mitigation plans submitted by utilities in the state.
In a separate action on the same day, June 11, the CPUC issued a decision requiring the state’s large investor-owned utilities to accelerate deployment of microgrids and resiliency projects to minimize the impacts of wildfire-caused power outages and Public Safety Power Shut-off (PSPS) events.
Wildfire mitigation plans
In approving the wildfire mitigation plans for Horizon West and Trans Bay Cable, Liberty Utilities, PacifiCorp, Southern California Edison, San Diego Gas & Electric, and Pacific Gas and Electric (Docket #: R.18-10-007), the CPUC is requiring the utilities to provide “clear analysis and data” to support their wildfire safety proposals.
To that end, the CPUC developed risk measurement tools, including a “Maturity Model,” that evaluates the utilities’ wildfire risk mitigation efforts across 10 categories and 52 specific capabilities.
The CPUC held the wildfire mitigation plan of Bear Valley Electric Service until the commission’s June 25 meeting.
While the CPUC said the utilities are “generally demonstrating progress” in reducing wildfire risk, most utilities “demonstrate a need for improvement.”
For instance, in a separate June 10 document, the CPUC said it is “imperative” that Pacific Gas and Electric makes “a meaningful reduction” in the scale and scope of PSPS [Public Safety Power Shutoffs] for the 2020 fire season and beyond.”
But despite the utility’s programs and improved re-energization protocols, “PG&E does not articulate quantitatively how it expects hardening to increase PSPS thresholds for individual circuits,” impeding the commission’s ability “to determine how the $5.3 billion in hardening work will affect the probability of a PSPS in communities in California.”
In a similar vein, the CPUC said that Southern California Edison (SCE) “has not described their deployment strategy and timelines in sufficient detail to convince the [commission] that the highest risk circuits are being targeted in a nuanced way and that this work will be completed on time” and must meet the conditions issued by the CPUC to address those gaps.
Microgrid decision
In the June 11 microgrid decision ( Docket #: R.19-09-009), the CPUC called for the state’s utilities to streamline and expedite interconnection processes for microgrids, resiliency, and other projects, and to collaborate with local and tribal governments to rapidly develop and deploy projects that could keep electricity on for critical facilities and other customers during power outages.
The CPUC put the microgrid rulemaking on a fast track after “the mismanagement by utilities of the October 2019 PSPS events” and said the new rule is intended to increase the deployment of new projects during this wildfire season.”
Last November, the CPUC began an investigation to assess whether the state’s investor-owned utilities properly balanced the need to provide safe and reliable service when planning and executing their recent PSPS events.
“The use of microgrids, coupled with the CPUC’s work to hold utilities accountable for creating and implementing wildfire mitigation plans, will help make communities more resilient in advance of the 2020 Wildfire season,” CPUC President Marybel Batjer said in a statement.
In addition to microgrids, the June 11 order requires the state’s IOUs to modify their net energy metering tariffs to allow storage devices to charge from the grid in advance of a PSPS event. The order also requires the IOUs to modify their net energy metering tariffs to remove the storage sizing limit.
Columbus EV Program Exceeds Its Electric Vehicle Sales Target
June 18, 2020
by Peter Maloney
APPA News
Posted June 18, 2020
There were 3,323 electric vehicles sold in the seven-county Columbus, Ohio, metropolitan region from April 2017 to February 2020, breaking the target of 3,200 vehicles sold that was set by the Smart Columbus Electrification Program.
Going into the Smart Columbus program, only 0.4% of vehicles sold in the Columbus region were battery electric vehicles or plug-in hybrid electric vehicles. Columbus set an electric vehicle adoption target of 1.8%, or 3,200 vehicles, by March 2020. During the grant period, which ended March 31, electric vehicle sales reached a high of 2.34% in fourth-quarter 2018 and of 1.6% in fourth-quarter 2019.
The Smart Columbus Electrification Program won a $40 million grant in June 2016 from the U.S. Department of Transportation’s Smart City Challenge.
Top officials with the Columbus, Ohio, Division of Power in 2016 detailed how the division is working to implement projects tied to the smart city initiative.
The Department of Transportation says that through the program it has leveraged nearly $350 million in public and private funds for smart city and advanced transportation technologies.
In addition to the DOT grant, public power city Columbus was awarded a $10 million grant from the Paul G. Allen Family Foundation to speed the transition to an electrified, low-emissions transportation system.
Smart Columbus was also the beneficiary of aligned investments totaling more than $720 million from private, public and academic institutions in the region to support technology and infrastructure investments to upgrade Columbus’ transportation network and aid in making Columbus a model connected city of the future.
Smart Columbus is a regional smart city initiative co-led by the City of Columbus and Columbus Partnership, which includes partnerships with The Ohio State University, Battelle, and American Electric Power.
Seventy Columbus employers partnered with Smart Columbus to develop education and incentive programs that encouraged residents drive electric and drive less.
“This success could not have been achieved without the vision and engagement of leaders from across Columbus’ public and private sectors,” Alex Fischer, president and CEO of the Columbus Partnership, said in a statement.
The educational and marketing aspects of the Smart Columbus program included the Smart Columbus Ride & Drive Roadshow, which facilitated 11,956 test drives; the Smart Columbus Experience Center, which conducted an additional 400 electric vehicle test drives; the “EVolve Your Thinking” digital education campaign; and the Smart Columbus Electrified Dealer program, which has trained more than 70 sales associates from 35 dealerships. The program also drove efforts to incorporate electric vehicles into public and private vehicle fleets, which resulted in the deployment of more than 300 electric vehicles.
“Our work with Smart Columbus has taught us many lessons about making EV charging more accessible and we’ll use this experience as we expand to other areas of the state.” Raja Sundararajan, president and chief operating officer of AEP Ohio, said in a statement.
Check out APPA’s Electric Vehicle Tracker for additional details on what public power utilities are doing with respect to EVs.
NYPA Resumes Work On Projects That Were Suspended Due To Pandemic
June 17, 2020
by Paul Ciampoli
APPA News Director
Posted June 17, 2020
The New York Power Authority has resumed work on certain projects that were suspended so that the Authority could focus on the continued safe operation of its power plants and transmission system in response to the COVID-19 pandemic.
Several large NYPA projects were underway when New York Gov. Andrew Cuomo announced New York PAUSE as the COVID virus began to appear in New York State.
At that time, NYPA suspended various types of non-critical repair work and capital project work and focused on the continued safe operation of its power plants and transmission system.
NYPA recently reported that several of its North Country projects are in various stages of restarting.
The Authority has restarted work on a vital transmission infrastructure project to rebuild and strengthen the Moses-Adirondack transmission lines, an 86-mile line running North-South through St. Lawrence and Lewis Counties in the North Country.
The project, known as the Moses-Adirondack Smart Path Reliability Project, supports Cuomo’s plan to modernize New York’s energy system.
NYPA has also restarted work on a project to restore a small hydroelectric power plant that feeds power to the Village of Potsdam.
NYPA is providing approximately $4 million in financing and technical assistance to the village for the overhaul and upgrade of their hydro facility, which is expected to be back in service by the end of the year.
NYPA has also resumed work on a $5.6 million concrete rehabilitation project at the Massena Intake. The project consists of replacing the concrete roadway deck and sidewalks and the installation of a railing system.
Meanwhile, NYPA has set a target date of mid-July to restart work on its North Country Battery Storage Project.
NYPA will resume work shortly on a $29.8 million, 20-megawatt battery storage demonstration facility adjacent to an existing substation in Franklin County.
The project, which is anticipated to be in service by the end of the year, supports the state’s nation-leading 3,000 MW by 2030 storage goal.
NYPA is continuing to take proactive measures to guard against COVID-19
NYPA noted that it is continuing to take proactive measures to protect the health of its employees, and communities in which it operates, by limiting situations in the virus can be transmitted.
Employees are surveyed daily for wellness and are asked to stay home if they are displaying signs of illness.
Health checks require both NYPA employees and contractors to answer questions regarding themselves and their families, related to physical symptoms associated with COVID. Depending on the work situation, additional personal protective equipment will be worn as warranted for the health and safety of its workers, customers and the general public.
Through an Incident Command Structure, NYPA continues to monitor the pandemic and will make adjustments to these precautions as necessary.
Platte River Power Authority To Retire Coal-Fired Unit 16 Years Ahead of Schedule
June 17, 2020
by Paul Ciampoli
APPA News Director
Posted June 17, 2020
The Platte River Power Authority on June 16 said that its coal-fired Rawhide Unit 1 generating resource will cease producing electricity by 2030, 16 years before its planned retirement date.
Platte River’s board approved a resource diversification policy in December 2018, which calls for a 100% noncarbon energy mix by 2030, and planners immediately began studying future energy mix options without the use of the 280 MW coal-fired unit as part of its integrated resource planning process.
While the IRP is currently on hold until public meetings and stakeholder engagement resumes, Platte River’s leadership needed to announce Unit 1’s retirement to support state regulatory timelines that align with the broader objectives for a noncarbon future, Platte River said.
Platte River is a not-for-profit wholesale electricity generation and transmission provider that delivers energy and services to its owner communities of Estes Park, Fort Collins, Longmont and Loveland, Colorado for delivery to their utility customers.
The last IRP that Platte River completed in 2016 did not call for additional generating capacity. Platte River nevertheless added 30 MW of new solar energy, studied the feasibility of a zero-net carbon energy mix, signed a power purchase agreement (PPA) for an additional 150 MW of wind power and later increased the amount to 225 MW, and will soon add 22 MW of additional solar power with 2 MWh of battery capacity.
It is currently negotiating another PPA for up to 150 MW of new solar generation.
Platte River noted that Rawhide Unit 1 has earned national recognition for its reliability, capacity and environmental performance. Throughout its life, Unit 1 has operated with an equivalent availability factor of 97.28%, running thousands of hours between planned or unplanned outages, delivering energy up to its nameplate capacity. When built, the unit featured state-of-the art emissions controls that most plants were not required to have and more were added before regulatory mandates.
From the beginning, Unit 1 provided more than half of the energy needs for Platte River’s owner communities, supplemented by federal hydropower contracts, natural gas resources, market purchases, wind and solar resources.
By the end of 2020, more than 50% of the energy delivered by Platte River will come from noncarbon resources including wind, solar and hydro facilities, and Platte River continues to take steps needed to achieve its 100% noncarbon goal.
In addition to Unit 1, the 4,560-acre Rawhide Energy Station also hosts five natural gas combustion turbines and a 30 MW solar farm, along with another 22 MW of solar power (with battery storage) currently under construction.
Energy from the 225 MW Roundhouse wind farm located in southern Wyoming will be delivered to the Rawhide Energy Station and then to Platte River’s owner communities.
Platte River’s ownership interest in the Craig station will also conclude when Unit 1 is retired in 2025 and Unit 2 follows, thereby ending the use of all coal-fired generating capacity by 2030.
The Rawhide Energy Station has multiple generation resources, and workers will be needed for those facilities, Platte River noted.
Jason Frisbie, general manager and CEO of Platte River, said that plans will be developed to smoothly transition workers to new roles after closure.
Following its retirement, Unit 1 will undergo a lengthy decommissioning process.
APPA Urges FERC To Dismiss Petition Tied To Net Metering Jurisdiction
June 17, 2020
by Paul Ciampoli
APPA News Director
Posted June 17, 2020
The Federal Energy Regulatory Commission should dismiss a petition asking it to find that it has jurisdiction over energy sales from rooftop solar facilities and other distributed generation located on the customer side of the retail meter whenever the output of these resources exceeds the customer’s demand, the American Public Power Association said on June 15.
Granting the petition could jeopardize public power net metering programs and render the distributed generation output of hundreds of thousands of public power utility customers subject to federal regulation, APPA said in its protest (Docket No. EL20-42-000).
Moreover, the petition for a declaratory order submitted by the New England Ratepayers Association (NERA) in April should be dismissed because it does not present an appropriate case for a declaratory ruling, APPA said, noting that FERC’s policy with respect to authority over retail net metering programs has been well-settled for years.
NERA is seeking a declaratory order that there is exclusive federal jurisdiction over energy sales from distributed generation located on the customer side of the retail meter whenever the output exceeds the customer’s demand or the energy from such a generator is designed to bypass the customer’s load.
The petition argues that a wholesale sale occurs when the output from behind-the-meter generation exceeds demand, and the rates for such sales must be priced in accordance with section 210 of the Public Utility Regulatory Policies Act (PURPA), or sections 205 and 206 of the Federal Power Act (FPA), as applicable.
NERA also asks the Commission to “find unlawful, and therefore reject, state net metering laws which assert jurisdiction over such wholesale sales and establish a price in excess of what PURPA or the FPA allows for wholesale sales subject to this Commission’s exclusive jurisdiction.”
Public power net metering programs could be jeopardized
APPA noted hundreds of self-regulated public power utilities across the country accommodate their customers’ behind-the-meter resources through retail net metering programs.
Local control over these programs allows public power utilities to structure retail net metering approaches that respond to the policy preferences of their states and local communities, while seeking to ensure that the costs and benefits associated with distributed generation deployment are appropriately reflected in retail rates.
“Although the petition does not specifically address the use of net metering by public power utilities, the declarations requested by NERA, if granted, could jeopardize public power net metering programs in addition to the state laws that NERA asks the Commission to ‘reject,’” APPA said.
Granting the petition could render the distributed generation output of hundreds of thousands of public power utility customers subject to federal regulation, under the FPA or PURPA, APPA told FERC.
APPA urges FERC to dismiss petition
FERC should dismiss the petition without reaching the merits, APPA argued, saying that the matters on which NERA seeks a declaratory order are neither the source of controversy nor uncertainty.
It pointed out that the Commission’s policy with respect to authority over retail net metering programs has been well-settled for years, and was recently reaffirmed in FERC Order Nos. 841 and 841-A, relating to storage resources.
“Granting the petition and upsetting the regulatory certainty that the Commission has fostered would be a recipe for creating, not terminating, controversy and regulatory uncertainty. The petition is potentially sweeping in scope and broadly applicable, yet it is not grounded in any concrete proposal or specific facts and circumstances, nor does the petition include sufficient information for the Commission to analyze and address the requested declarations,” APPA said.
Referring to criticisms leveled at net metering by the NERA petition, APPA agreed that there are legitimate policy issues associated with the practice, including cost allocation and cross-subsidization concerns arising from net metering’s impact on recovery of a utility’s fixed costs. APPA said it “recognizes that it is important that all distributed generation customers pay a fair share of the costs of keeping the grid operating safely and reliably, recognizing the benefits provided by those customers.” APPA argued, however, that these are issues that state and local regulators can address.
If FERC does not dismiss the petition outright, it should deny the declarations requested by NERA and reaffirm that its jurisdiction under the FPA or PURPA is not implicated when a retail net metering customer is a net consumer of energy over the applicable billing period, APPA said.
“This policy appropriately acknowledges the authority of state and local regulators over the rates, terms and conditions of retail electric service,” APPA argued, adding that D.C. Circuit rulings cited by NERA do not require reconsideration of the Commission’s approach.
Moreover, the Commission’s policy is also in accord with a section of PURPA that requires state and local regulators to consider net metering programs for electric consumers, “a directive that is inconsistent with the notion that retail electricity delivered by the distribution utility cannot be netted against the energy generated by a retail customer’s distributed generation.”
APPA said that even if the Commission conceivably could conclude that retail net metering customers are making wholesale sales subject to federal regulation, “it is an entirely reasonable and legally permissible policy choice for the Commission to conclude that its jurisdiction is not implicated where a retail customer is a net purchaser of retail power over the applicable billing period.”