Minnesota’s Princeton Public Utilities Launches Rate Study
January 31, 2022
by Paul Ciampoli
APPA News Director
January 31, 2022
Minnesota public power utility Princeton Public Utilities (PPU) has launched an electric rate study that is scheduled to be completed later this year.
In a Q&A with Public Power Current, Keith Butcher, General Manager of PPU, noted that PPU last conducted a rate study in 2015.
“In 2019, PPU implemented a 4% rate reduction in large part due to a reduction in wholesale costs from our supplier, Southern Minnesota Municipal Power Agency (SMMPA),” he noted in an email.
“Like other electric utilities, recent changes at both the wholesale and retail level are challenging the original assumptions from that previous rate study.”
He said that important factors that are changing since 2015 is a growth in customer-owned renewables, increased penetration of electric vehicles and overall changes in the local economy.
In addition, Butcher noted that PPU completed a conversion to AMI metering in the fall of 2021. “The increased data analytics that we can now perform knowing individual customer load shapes will help PPU more accurately track and predict future power delivery costs as well as our own revenue collections,” he said.
In 2021, PPU developed a 10-year capital improvement plan estimated at a cost of $11.7 million. The 10-year plan will be conducted in three phases. Goals of the plan include developing a new SCADA system for added system control and monitoring and completing the upgrade of the distribution network to a 12.47 kV system, among other things.
Financially, PPU has several electric bonds expiring in the next few years and has determined that the next few years will be a good time to invest in the system for the next generation, Butcher noted.
“Developing a better understanding of our changing bond requirements will help ensure fiscal sustainability during the transition from our old financing requirements to our new financing needs,” he said.
PPU is also anticipating load growth due to planned construction activities within its service territory as well as through some service territory acquisitions as city limits expand.
PPU has contracted with DGR Engineering to do a comprehensive rate study analysis that will determine fiscal requirements for the next 10 years, including integration of the impact of planned capital improvements projects and associated financing.
The analysis will also propose appropriate fiscal policy guidelines to serve as targets for rate-setting in the study and to provide future benchmarking metrics on an ongoing basis and develop an estimate of future power supply costs.
In addition, the analysis will project system operating expenses and cash requirements, including capital expenditures, financing obligations, and transfers, determine whether the present level of revenue is adequate or if adjustments are needed. Based on various scenarios, the analysis will develop a multi-year rate adjustment estimate and perform an analysis of customer class definitions, to determine if the current classes are appropriate.
It will also:
- Review the current rate structures, to determine if they align with the current utility cost structures and current industry practices;
- Perform a cost-of-service study, to allocate costs to the appropriate classes, and to the customers within the class;
- Assure fairness and equitability to all customers served;
- Develop proposed retail rates for implementation by PPU based on cost-of-service results;
- Evaluate the impact of the proposed rates on all customer classes; and
- Coordinate with PPU’s financial advisors to support issuance of debt required to fund capital projects.
The agreement with DGR Engineering was signed in December 2021 and work has begun, Butcher said. Results will be available by September for inclusion in PPU’s 2023 budget discussions.
PPU will use the findings to determine what, if any, rate modifications should be made.
“In the interest of transparency, the rationale and impact of any rate modifications will be shared with our customers,” Butcher said. “PPU wants to ensure everyone that we are being deliberative and clear in our work and that PPU is committed to implementing industry best practices in order to preserve and protect the system for current and future ratepayers.”
Having an outside, third-party expert “evaluate our rate structures lends credibility and objectivity to rate determination and will provide assurances to the community at-large that rates are fair and equitable,” he noted.
Court Sides With San Francisco PUC In Dispute With PG&E Over Power Grid Connections
January 31, 2022
by Paul Ciampoli
APPA News Director
January 31, 2022
The U.S. Court of Appeals for the District of Columbia Circuit recently sided with the San Francisco Public Utilities Commission (SFPUC) in a dispute with Pacific Gas & Electric (PG&E) over electricity connections. In its opinion, the appeals court directed the Federal Energy Regulatory Commission (FERC) to conduct further proceedings related to matters addressed in the decision.
The dispute centers on PG&E’s wholesale service to SFPUC under rules approved by FERC. The SFPUC purchases access to PG&E’s distribution system in San Francisco — paying PG&E about $20 million per year — to serve facilities providing city services.
PG&E, “in an attempt to stymie competition from the SFPUC, has been obstructing public projects for years, demanding the installation of unnecessary and expensive equipment before hooking up those projects to the electric grid,” SFPUC said in a news release related to the court’s decision.
The court’s decision covers two separate appeals from San Francisco, challenging a series of FERC orders.
One, a San Francisco complaint in January 2019 about what SFPUC claimed were PG&E’s demands for costly and unnecessary equipment designed for high-voltage primary power connections. San Francisco argued that secondary connections, which carry lower voltages, are the appropriate connection types for these projects. FERC sided with PG&E, and San Francisco appealed to the D.C. Circuit Court, which ruled in the city’s favor.
The appellate court, in a unanimous ruling by a three-judge panel, found that FERC had not justified its decision to uphold PG&E’s refusal to provide SFPUC interconnections at secondary voltage. Focusing on the Commission’s finding that PG&E’s actions were justified by safety and reliability concerns, the court found that FERC’s decision-making was flawed, noting in the ruling that FERC “does not provide sufficient justification for its conclusion,” “does not meet its burden of reasoned decision-making,” and that FERC’s “‘passing reference to relevant factors,’ … is not sufficient to satisfy [FERC]’s obligation to carry out ‘reasoned’ and ‘principled’ decision making.”
The court also said that the orders on review “present a troubling pattern of inattentiveness to potential anti-competitive effects of PG&E’s administration of its open-access tariff.”
The court said that “More than a century ago, Congress authorized the Hetch Hetchy System not only to provide San Francisco with a source of cheap power but also to ensure competition in its retail power market. Faced with claims that PG&E was frustrating that competition by treating its own retail service preferentially and refusing service for customers San Francisco had served for decades, [FERC] fell short of meeting its ‘duty’ to ensure that rules or practices affecting wholesale rates are ‘just and reasonable.’”
The second case addressed by the court started with a San Francisco complaint in 2013 regarding grandfathered customers who were served up until 1992.
The court found that FERC’s orders on grandfathering, which limited the city’s ability to continue to serve many of the customers it was serving in 1992, “are arbitrary and capricious.”
The court’s decision invalidated FERC’s orders on these topics and sent the matters back to FERC for “further proceedings consistent with this opinion.”
The SFPUC is a department of the City and County of San Francisco. It delivers drinking water to 2.7 million people in the San Francisco Bay Area, collects and treats wastewater for the City and County of San Francisco, and generates power for municipal buildings, residents, and businesses.
California Community Choice Aggregators Enter Into Storage Service Agreement
January 30, 2022
by Paul Ciampoli
APPA News Director
January 30, 2022
A group of California community choice aggregators (CCAs) recently voted to enter into an energy storage service agreement with REV Renewables for 69 megawatts/552 megawatt hours of long-duration energy storage.
The REV Renewables Tumbleweed project will be a California Independent System Operator grid-connected, lithium-ion battery storage resource located near Rosamond, in Kern County, California, with an expected online date of 2026.
The CCAs are members of California Community Power, a joint powers agency.
The participating CCAs are: CleanPowerSF, Peninsula Clean Energy, Redwood Coast Energy Authority, San Jose Clean Energy, Silicon Valley Clean Energy, Sonoma Clean Power Authority and Valley Clean Energy. Participating members will follow their own review and approval processes with their local, elected boards.
The California Public Utilities Commission (CPUC) Mid-Term Reliability Procurement order requires all CPUC-jurisdictional load serving entities, including CCAs, to procure from energy storage facilities capable of discharging for a minimum of 8 hours.
The Tumbleweed project satisfies approximately 55% of the long-duration storage compliance requirements of the participating members.
The joint procurement effort by the CCAs for long-duration energy storage began before the CPUC issued the new procurement order when a subset of the CCAs issued a Request for Offers (RFO) in October 2020 seeking to procure cost effective and viable long-duration storage resources.
Participation in the RFO and resulting projects is voluntary for each joint powers agency member.
The American Public Power Association has initiated a new category of membership for community choice aggregation programs.
PJM, N.J. Regulators File Agreement With FERC Tied To Offshore Wind
January 30, 2022
by Paul Ciampoli
APPA News Director
January 30, 2022
The PJM Interconnection and the New Jersey Board of Public Utilities (NJBPU) recently filed a first-of-its-kind joint agreement with the Federal Energy Regulatory Commission (FERC) on Jan. 27 outlining how New Jersey will put PJM’s competitive planning process to work in pursuit of its offshore wind goals.
The agreement details the contractual commitments and responsibilities of the NJBPU and PJM regarding the competitive selection of transmission solutions to enable New Jersey’s goal of delivering 7,500 megawatts (MW) of offshore wind generation to its residents by 2035.
The filing advances the process from a study agreement FERC approved last year. PJM is asking FERC to issue an order no later than April 15.
PJM is in the process of evaluating 80 proposals submitted in a competitive solicitation window for wind that ran from April 15 to Sept. 17, 2021.
PJM anticipates recommending to New Jersey by May the most cost-effective and efficient transmission solutions. The NJBPU expects to decide whether to sponsor selected transmission projects by September. Each proposal offers solutions to deliver offshore wind generation to the existing bulk electric grid.
Typically, PJM’s Regional Transmission Expansion Plan (RTEP) includes projects driven by reliability or market-efficiency criteria. The state agreement approach provides an avenue to incorporate public policy goals into the process, PJM said.
New Jersey is the first state to make use of the state agreement approach, which enables a state, or group of states, to propose a project to assist in realizing public policy requirements as long as the state (or states) agrees to pay all costs of any state-selected buildout included in the RTEP. Those costs would be recovered from customers in those states.
New York Power Authority To Invest $70 Million To Modernize Underground Power Line
January 29, 2022
by Paul Ciampoli
APPA News Director
January 29, 2022
The New York Power Authority (NYPA) is moving forward with a $70 million upgrade and modernization of the Long Island Sound Cable, an underground transmission line that transverses the Long Island Sound from Westchester County to Nassau County, carrying up to 600 megawatts of electricity to Long Island.
The NYPA Board of Trustees on Jan. 25 approved a nearly $38 million contract with Elecnor Hawkeye, an engineering and construction firm, to undertake the project’s design, manufacturing, delivery, assembly, and commissioning.
The transmission project will enable accelerated progress against New York State’s goal for 70 percent of the state’s electricity to come from renewable sources by 2030. It also advances the State’s path to realize a zero-emission grid by 2040 as outlined in the Climate Leadership and Community Protection Act, NYPA noted.
The reconductoring project, which is slated to begin this fall and complete in 2023, will include the replacement and commissioning of the Nassau County section of the cable, in addition to the installation of additional manholes, fiber optic replacements, and instrumentation improvements to bring operational flexibility to the line and alleviate the risk of faults.
The action by the NYPA trustees builds on the October 2021 board approval to purchase the high-pressure fluid-filled cable needed for the reconductoring project from the Okonite Company for $28 million.
The scope of the project will be submitted to the Department of Public Service within the next few months.
The 26-mile, 345-kilovolt transmission line was placed into service in May 1991 and is part of a statewide network of approximately 1,400 circuit-miles of high-voltage transmission lines and associated substations owned by NYPA.
As part of NYPA’s 10-year strategic plan, VISION2030, NYPA is committed to growing transmission throughout New York State.
The modernization of the Long Island Sound Cable is one of several transmission improvement and development projects NYPA is working on independently, or with other industry partners, across the state, including:
- Smart Path, a $484 million project to improve 78 circuit-miles of transmission from Massena in St. Lawrence County to the Town of Croghan in Lewis County;
- Smart Path Connect, a $605 million, multi-faceted project that includes rebuilding more than 50 circuit-miles of transmission between Massena and the Town of Clinton, rebuilding approximately 55 circuit-miles of transmission southward from Croghan to Marcy, and rebuilding and expanding several substations along the impacted transmission corridor;
- Central East Energy Connect, a $276 million project that includes the construction of more than 90 circuit-miles of new 345 kV and 115 kV transmission lines and two substations between Marcy in the Mohawk Valley and New Scotland in the Capital Region; and
- Clean Path NY, an $11 billion clean infrastructure project that includes a new 174-mile underground transmission line that will enable the delivery of more than 7.5 million megawatt-hours of energy into New York City every year.
EIA Forecasts Drop In Natural Gas Generation As Renewable Energy Resources Increase
January 29, 2022
by Paul Ciampoli
APPA News Director
January 29, 2022
The U.S. Energy Information Administration (EIA) expects rising electricity generation from renewable energy resources such as solar and wind will reduce generation from fossil fuel-fired power plants over the next two years.
The forecast share of generation for U.S. non-hydropower renewable sources, including solar and wind, grows from 13% in 2021 to 17% in 2023, EIA said on Jan. 18 in its latest Short-Term Energy Outlook.
EIA is also forecasting that the share of generation from natural gas will fall from 37% in 2021 to 34% by 2023 and the coal share will decline from 23% to 22%.
“One of the most significant shifts in the mix of U.S. electricity generation over the past 10 years has been the rapid expansion of renewable energy resources, especially solar and wind,” EIA noted.
The amount of solar power generating capacity operated by the U.S. electric power sector at the end of 2021 is 20 times more than it was at the end of 2011, and U.S. wind power capacity is more than twice what it was 10 years ago.
Another significant shift in the generation mix has been a steady decline in the use of coal-fired power plants since their peak output in 2007 and the increasing use of natural gas, primarily as a result of sustained low natural gas prices, EIA said.
But that trend reversed in 2021 when the cost of natural gas delivered to U.S. electric generators averaged $4.88 per million British thermal units, more than double the average cost in 2020. As a result, the share of generation from natural gas declined from 39% in 2020 to 37% last year, while the share of generation from coal rose for the first time since 2014 to average 23%.
In its current Short-Term Energy Outlook, EIA forecasts that most of the growth in U.S. electricity generation in 2022 and 2023 will come from new renewable energy sources.
EIA estimates that the electric power sector had 63 gigawatts (GW) of existing solar power generating capacity operating at the end of 2021. “We forecast solar capacity will grow by about 21 GW in 2022 and by 25 GW in 2023. We expect that 7 GW of wind generating capacity will be added in 2022 and another 4 GW in 2023. Operating wind capacity totaled 135 GW at the end of 2021,” EIA said.
“Our forecast of growth in renewable electricity generation over the next two years leads to our forecast of a reduced need for fossil-fueled generation,” the federal agency said.
Although it expects natural gas prices for electric generators to decline, the operating costs of renewable generators will continue to be generally lower than natural gas-fired units, according to EIA.
“We expect that regions of the country with the largest increases in renewable capacity, such as Texas and the Midwest/Central regions, will experience the largest reductions in natural gas generation.”
DOE Unveils Several New Initiatives Aimed At Removing Community Solar Barriers
January 28, 2022
by Paul Ciampoli
APPA News Director
January 28, 2022
The U.S. Department of Energy (DOE) on Jan. 25 unveiled several new initiatives to remove barriers to the deployment of community solar.
Together, the initiatives will help achieve the National Community Solar Partnership’s (NCSP) target to enable community solar to power the equivalent of five million households and create $1 billion in energy bill savings by 2025, DOE said.
The American Public Power Association is a member of NCSP, which is a coalition of community solar stakeholders working to expand access to affordable community solar.
Attendees at NCSP’s annual summit on Jan. 25 discussed NCSP’s “Pathway to Success,” a plan to address persistent barriers to equitable access.
The plan has five focus areas: developing community solar knowledge and know-how, expanding state-level programs, improving access to financing, reducing customer acquisition barriers and broadening awareness of the benefits of community solar programs.
The initiatives supporting this pathway include:
- A new States Collaborative, engaging nearly half of the nation’s states and the District of Columbia, which will support expansion and development of new community solar programs at the state level. This will be made up of state energy officials and program administrators and by providing best practices, technical assistance, and opportunities for direct peer-to-peer learning.
- The Credit Ready Solar Initiative, which will help community solar developers better access project financing. This initiative will bring together lenders, philanthropic institutions, and community solar developers — especially those that are community-based or serve low- to moderate-income households — to create standard processes and a marketplace for deploying project capital.
- A $2 million NCSP Technical Assistance program, which is offered on a rolling basis at no cost to NCSP partners and provides personalized support to help them accelerate implementation, improve the performance of their program or project, and build capacity for future community solar development.
Additional information about NCSP is available here.
Garden City, Kansas, Buys T&D Facilities, Marking Final Major Step For Power System Revamp
January 27, 2022
by Paul Ciampoli
APPA News Director
January 27, 2022
Garden City, Kansas, recently purchased transmission and distribution facilities from a rural electric cooperative, marking the final major step that the city has taken as part of revamping the city’s electric system.
Garden City’s public power utility was established in 1914 and currently serves 11,500 meters. The utility has a Platinum Reliable Public Power Provider rating from the American Public Power Association.
Before January 2014, Garden City was a full-requirement customer of the local electric cooperative for power supply and had been for over 30 years.
However, on January 1, 2014, Garden City began receiving all of its power supply needs from the Kansas Municipal Energy Agency (KMEA), which included the installation of 27 megawatts of natural gas generation at the Jameson Energy Center located in Garden City.
The move to KMEA has saved the city millions of dollars per year in power supply expenses. But the city was still paying the local electric cooperative a local access charge of $500,000 per year for 115-kV transmission access.
In 2017 and 2018, Garden City made plans to construct transmission lines and substations for access to the 115-kV transmission system, additional capacity, and better reliability.
In the spring of 2019, the local electric cooperative offered to sell portions of its system that would provide the city access to the 115-kV transmission system at a lesser cost than building new which would have created some stranded investments for the cooperative.
The city had offered to purchase some of the facilities years before, but those offers were not accepted.
Garden City ultimately agreed to purchase four substations and 1.5 miles (99 distribution poles) of distribution lines. Two of the four substations provided direct access to the 115-kV transmission system.
The city installed larger substation class transformers and upgraded them to include electronic equipment breakers /relays and connected it all to its SCADA system.
The city closed on this project at the end of 2021, and now has direct access, additional capacity and better reliability that it has sought since 2014 and no longer needs to pay the $500,000 local access charge per year.
Reading Municipal Light Department Launches Renewable Choice Program
January 27, 2022
by Paul Ciampoli
APPA News Director
January 27, 2022
The Reading Municipal Light Department (RMLD) in Massachusetts recently announced the upcoming launch of its renewable choice opt-in program that will allow customers to support additional renewable energy resources above and beyond RMLD’s annual non-carbon energy targets.
Funds from the renewable choice program will be used to retire additional New England Power Pool Generation Information System compliant renewable certificates, specifically Mass Class 1 certificates.
The program launches February 1, 2022 for residential customers and will be available to commercial and industrial customers this spring.
Customers can choose to contribute at one of three levels to bring their monthly electricity usage to 50%, 75%, or 100% renewable/non-carbon. The renewable choice charge will be based on the participating customer’s monthly kilowatt hour (kWh) usage and will be added as a line item on the customer’s monthly electric bill.
A one-year commitment is required, and customers must be current with their bill to sign up.
Additional information about the program is available here: https://www.rmld.com/home/pages/renewable-choice.
The page also features a calculator which allows customers to input their monthly kWh usage to see how much their monthly renewable choice charge would be for all three available participation percentage levels.
Established in 1894, RMLD is a municipal electric utility serving over 70,000 residents in the towns of Reading, North Reading, Wilmington, and Lynnfield Center. RMLD has over 30,000 meter connections within its service territory.
SMUD Unveils First Utility-Scale Storage Battery Project
January 26, 2022
by Paul Ciampoli
APPA News Director
January 26, 2022
Officials from California’s Sacramento Municipal Utility District (SMUD) on Jan. 24 were joined by regional leaders for a ribbon-cutting of SMUD’s first utility-scale storage battery project.
With the ribbon cutting, the public power utility unveiled six large-scale lithium-ion battery storage units at the Hedge Solar Farm in south Sacramento, a pilot project that will demonstrate the feasibility of utility-scale battery storage.
The large-scale lithium-ion battery system is a step forward in SMUD’s vision to add 1,100 megawatts (MW) of battery storage over the next decade, a keystone to the utility’s 2030 Zero Carbon Plan.
Hedge Solar Farm batteries will provide 4 MW of electricity and 8 megawatt-hours of storage. The six battery containers are 20 feet long, weigh 52,000 pounds each, and house 3,840 interconnected battery cells.
This is the largest battery installation in the greater Sacramento area and the first of its kind for a publicly owned utility in California, SMUD said.
The following officials attended the ribbon cutting:
SMUD CEO and General Manager Paul Lau
Rep. Doris Matsui, D-Calif.
SMUD Board of Directors Vice President Heidi Sanborn
Sacramento Mayor Darrel Steinberg
Sacramento Councilman Eric Guerra
California Assemblymember Kevin McCarty
California Assemblymember Ken Cooley
Matthew Nelson of Electrify America
John Roeser of Mitsubishi
