APPA Joins State And Local Stakeholders To Oppose “Minimum” Tax On Bond Interest
November 3, 2021
by APPA News
November 3, 2021
The American Public Power Association (APPA) has joined with other state and local stakeholders in opposition to the inclusion of municipal bond interest in a new Corporate Alternative Minimum Tax (AMT) included in the latest draft of the Build Back Better Act.
In their Nov. 1 letter to congressional leaders, APPA and the other groups note that tax-exempt bonds are the primary mechanism through which state and local governments raise capital to finance a wide range of essential public projects.
“This includes not only local roads, highways, and bridges, but also — among other things — airports, public transportation, affordable housing, water and wastewater, schools, libraries, town halls, nonprofit hospitals and universities, police and fire stations, and electric power and gas facilities. These are the investments that make our communities livable and commerce possible,” the letter said.
“Above all else, our groups are committed to minimizing the cost of financing these projects — costs that must be paid by our communities -– by preserving the tax exemption on municipal bonds,” the groups said in the letter.
The groups voiced alarm that section 138101, Corporate Alternative AMT, of the Rules Committee Print of the Build Back Better Act would impose a 15 percent minimum tax on tax-exempt bond interest for purchasers that currently hold about one quarter (or just under $1 trillion) of outstanding tax-exempt municipal bonds.
“Ultimately, this tax will not be borne by corporations, but by our communities, in the form of higher interest demanded by bondholders,” the letter went on to say.
“Our organizations are currently analyzing the effect of this provision, but we know that the Congressional Research Service estimates that subjecting private activity bonds to the individual AMT has raised the interest cost of those bonds by 50 basis points. Again, we do not know whether the effect would be identical, but can safely conclude that subjecting an even broader array of state and local government and non-profit bonds to this new tax will raise community borrowing costs.”
APPA and the other groups said that considering the size of the municipal bond market, with over $4 trillion in debt outstanding, “the costs will be significant and, again, will be borne by our communities, not by the holders of the bonds.”
At the same time, provisions that would improve municipal finance by increasing flexibility and decreasing costs were excluded from the Rules Committee Print despite being approved by the House Committee on Ways and Means earlier this year. These include provisions to reinstate the ability to issue tax-exempt advance refunding bonds, to increase the small issuer exception from $10 million to $30 million, and to restore and expand the use of direct-pay bonds. “It is inconceivable that neither of the two infrastructure bills currently being considered by Congress include provisions to improve infrastructure financing,” the groups said.
Cities, counties and states will need to partner with the federal government in carrying out the policies proposed in Build Back Better, “but these added costs will severely impact our ability to do so,”: the letter states.
As a result, the groups urged the House and Senate to amend section 138101 of the Rules Committee print to exclude tax-exempt bond interest from the proposed Corporate AMT.
Specifically, for purposes of calculating the AMT, adjusted financial statement income should be decreased by interest that is excluded from gross income under Internal Revenue Code Section 103.
“We would also strongly urge the House and Senate to include the elements of our bond modernization agenda, including reinstating the ability to issue tax-exempt advance refunding bonds, increasing the small issuer exception from $10 million to $30 million, and restoring and expanding the use of direct-pay bonds.”
Lazard Reports Show Continued Cost Declines For Renewables, Energy Storage
November 3, 2021
by Peter Maloney
APPA News
November 3, 2021
A trio of recently released reports shows that the cost of renewable energy continues to decline while energy storage costs were mixed and the use of hydrogen as a fuel remains dependent on availability and technology costs.
“Our three studies together document the continued acceleration of the energy transition,” George Bilicic, vice chairman and global head of the power, energy and infrastructure group at financial advisory firm Lazard, said in a statement. “We’re also seeing that the transition will not be dominated by any one solution — rather a new ‘all of the above’ approach, which includes renewable energy, storage, hydrogen and other solutions, will be key to effecting the permanent shift to increased energy efficiency and sustainability.”
Renewable Energy
Lazard’s latest annual Levelized Cost of Energy analysis (LCOE 15.0) shows the cost of onshore wind and utility-scale solar continues to be competitive with the marginal cost of coal, nuclear and combined cycle gas generation.
When government subsidies are included, the LCOE of onshore wind averaged $25 per megawatt hour (MWh), and utility-scale solar averaged $27/MWh, while the marginal cost of coal-fired generation averaged $42/MWh, nuclear’s average marginal cost was $29/MWh, and the average marginal cost of combined-cycle gas generation was $24/MWh, according to the Lazard report. The report put the midpoint of the unsubsidized LCOE of offshore wind at $83/MWh.
While the rate of decline in the LCOE for onshore wind and utility-scale solar have slowed in recent years, the pace of decline for utility scale solar continues to be greater than that for onshore wind, the report found, noting that the average compound annual decline in LCOE of utility-scale solar was 8 percent over the past five years, compared with 4 percent for onshore wind.
And even though projects entering operation in 2021 were included in the report, Lazard cautioned that commodity cost inflation, supply chain disruption and accelerating downstream demand for renewable energy could put upward pressure on project capital costs that could become evident in future iterations of the firm’s LCOE report, though those increases might not necessarily translate into higher relative costs.
Energy Storage
Lazard’s latest annual Levelized Cost of Storage analysis (LCOS 7.0) showed mixed year-over-year changes in the cost of storage across use cases and technologies, driven in part by the confluence of emerging supply chain constraints and shifting preferences in battery chemistry.
“Industry preference is increasingly shifting towards Lithium-Iron-Phosphate (LFP) technology, which is less expensive than competing lithium-ion technologies, especially in shorter-duration applications, and has more favorable thermal characteristics, despite its relatively lower volumetric energy density,” according to the Lazard report.
In addition, other factors – such as supply constraints in commodity markets and manufacturing activities – are adding to inflation and putting pressure on energy storage capital costs, Lazard said.
The report also noted that hybrid applications, such as combining energy storage with solar power installations to mitigate renewable resource intermittency, are “becoming more valuable and widespread as grid operators begin adopting Estimated Load Carry Capability (ELCC) methodologies to value resources,” the report said.
Hydrogen
Lazard’s Levelized Cost of Hydrogen (LCOH 2.0) report showed that the cost of hydrogen is still largely dependent on the cost and availability of the energy resources required to produce it.
Most hydrogen is currently produced from fossil fuels using steam-methane reforming and methane splitting processes, producing “gray” hydrogen as distinct from “green” hydrogen produced from water and electricity generated by renewable resources.
In its analysis, Lazard did not include a cost of carbon dioxide calculation or government support mechanisms, though the authors said such considerations could be “impactful.” The analysis also did not include potentially significant factors such as conversion, compression, transmission or storage costs.
The intent of the analysis was to benchmark the LCOH of green hydrogen on a dollars per kilogram I$/kg) basis so that stakeholders could compare the cost of green hydrogen to other forms of energy in particular use cases, Lazard said.
And while green hydrogen is “currently more expensive than the conventional fuels or hydrogen it would displace,” it has the potential to reduce carbon dioxide emissions in traditionally “hard-to-decarbonize sectors such as transportation/mobility, heating, oil refining, ammonia and methanol production, and power generation,” the report found.
Senate Committee Advances Nomination of Phillips To Be FERC Commissioner
November 3, 2021
by Paul Ciampoli
APPA News Director
November 3, 2021
The Senate Energy and Natural Resources Committee on Nov. 2 voted to advance the nomination of Willie Phillips, Jr. to be a member of the Federal Energy Regulatory Commission (FERC).
Phillips, a Democrat, is currently Chairman of the Public Service Commission (PSC) of the District of Columbia.
Phillips’ nomination will require confirmation by the Senate and, if confirmed, Phillips would return FERC to its full complement of five commissioners after the departure of Commissioner Neil Chatterjee on August 30, 2021.
He would also give Democrats a 3-2 majority on the Commission.
The committee approved moving the nomination of Phillips to the Senate floor by voice vote.
APPA Emphasizes Need For Affordable Transmission Rates And Touts Joint Ownership
November 2, 2021
by Paul Ciampoli
APPA News Director
November 2, 2021
The Federal Energy Regulatory Commission (FERC) should not lose sight of the need to keep transmission rates affordable for consumers and its efforts to supervise the development of new transmission must prioritize effective planning to reliably meet the needs of load-serving entities (LSEs), the American Public Power Association (APPA) said in recent comments filed at the Commission.
At the same time, APPA also urged the Commission to promote joint transmission ownership through the transmission planning process by, for example, specifying that joint ownership of transmission facilities is a positive factor in evaluating transmission solutions in regional transmission planning processes.
APPA’s comments came in response to an advance notice of proposed rulemaking (ANOPR) issued by FERC in July 2021 to reform its transmission planning, cost allocation, and generator interconnection rules (Docket No. RM21-17).
“APPA agrees that as new electric generation resources, especially renewable resources, are developed, new transmission facilities may be required, and the uses of the electric transmission grid will evolve with the change in resource mix,” the trade group said in its initial comments in the ANOPR proceeding.
Public power utilities and public power joint action agencies “engage in planning to meet the resource needs of their customers or of their members in a manner that is safe, reliable, affordable, and consistent with the policy preferences of their community-owners,” APPA noted.
Public power utilities are LSEs and, as such, have a critical concern that the Commission’s efforts provide for integration of new resources through transmission planning and generator interconnection that will maintain reliable and affordable service to customers, APPA told FERC.
The Commission’s efforts to supervise the development of new transmission must prioritize effective planning to reliably meet the needs of LSEs, consistent with Federal Power Act (FPA) section 217(b)(4).
At the same time, APPA said that rising transmission costs are a major concern for many of its members. “Increased transmission investment in recent years has resulted in substantial increases in transmission rates in some regions, and this trend is expected to continue,” it said.
The Energy Information Administration’s 2020 Annual Energy Outlook projects, for example, that rising transmission and distribution costs will offset much of the projected decrease in generation costs through 2050. These transmission cost increases “impose a significant burden on public power utilities and the customers they serve.”
While additional transmission infrastructure may be needed to accommodate new resources, replace aging infrastructure, and promote reliability and resilience, the Commission, in considering proposed changes to its transmission planning and cost allocation rules, “must remain cognizant of the need to avoid placing unreasonable cost burdens on transmission customers.”
Of particular concern to public power utilities would be revised Commission rules that assign to them costs of transmission facilities from which they derive little or no reliability or economic benefit, APPA said.
“Protecting consumers from unreasonable costs is not only a statutory obligation under the FPA, it is a practical imperative if the Commission’s planning and cost allocation rules are to effectively promote transmission development.”
APPA said it is encouraged that the ANOPR recognizes the need to consider the impacts of reform on costs to consumers, and APPA urged the Commission to keep such cost impacts at the center of any analysis of potential reforms.
While transmission investment has been robust in recent years, APPA said it shares the Commission’s concern that the current regional and interregional transmission planning and generator interconnection processes may not consistently result in the most efficient transmission projects.
“Inefficient transmission planning and generator interconnection processes can result in LSEs having the worst of both worlds: rising transmission costs without efficient and effective transmission solutions. Accordingly, APPA agrees that there is merit in the Commission’s effort to assess whether changes to its current rules and policies are warranted.”
As a general matter, however, APPA noted that concerns with the transmission planning and generator interconnection processes are likely to be highly regional in nature, which argues against a “one-size-fits all” approach to implementing any reforms in this proceeding.
At the same time, APPA pointed out that one important issue that is not raised in the ANOPR is the benefit of promoting joint transmission ownership opportunities for non-public utilities. “The Commission has consistently recognized the benefits of joint ownership, and APPA urges the Commission to act to promote joint ownership opportunities through any reforms to the transmission planning process.”
While the Commission’s incentive policies have been the primary mechanism through which the Commission has encouraged joint ownership, that approach has had relatively limited success in promoting joint ownership opportunities, APPA said.
“As part of any reforms adopted in this proceeding, APPA urges the Commission also to promote joint ownership through the transmission planning process by for, example, specifying that joint ownership of transmission facilities is a positive factor in evaluating transmission solutions in regional transmission planning processes.”
APPA highlighted positions on some of the ANOPR’s inquiries including, among other things:
- The Commission should promote regional transmission planning that includes a greater emphasis on anticipated future generation and more robust scenario planning, including analyses of multiple futures;
- Any reforms adopted as a result of the ANOPR should allow for regional flexibility that permits existing regional planning and differences to be taken into account;
- The transmission planning process must avoid endorsing projects based on speculative resource projections;
- Planning reforms must ensure a level playing field for all types of resources;
- In order to reasonably account for anticipated generation, transmission planning should focus on generation that is likely to be added to the transmission system based on the resource plans of LSEs, consistent with the requirements of FPA section 217(b)(4);
- The definition of Public Policy Requirements adopted in Order No. 1000 remains a reasonable guideline for what the Commission should require transmission providers to consider in their transmission planning processes when considering matters other than reliability and economic drivers;
- It may be appropriate for transmission planners to conduct transmission planning and cost allocation on a more holistic basis, taking into account reliability, economic, and Public Policy drivers; and
- The Commission should consider whether reforms are necessary to ensure that local transmission planning processes are adequately identifying optimal transmission solutions.
The Energy Authority, Northwest Public Power Utilities In Strategic Partnership
November 2, 2021
by Paul Ciampoli
APPA News Director
and Peter Maloney
APPA News
November 2, 2021
The Energy Authority (TEA) recently announced its participation in the next phase of the Northwest Power Pool Western Resource Adequacy Program (WRAP) in partnership with seven public power utilities.
TEA will join the WRAP as the load responsible entity, pooling the loads and resources of the seven PUDs, which are Benton PUD, Clark Public Utilities, Cowlitz PUD, Emerald People’s Utility District, Franklin PUD, Grays Harbor PUD, and Lewis County PUD. All of the PUDs are based in Washington State, with the exception of Oregon-based Emerald.
The aggregated group of utilities represents over 440,000 retail electricity customers with a combined average peak load of over 2,700 MW. TEA said its public power ownership and existing relationships make this a logical extension of the portfolio management and scheduling services that TEA already provides.
The PUDs “are seeking to continue their proven track record of providing cost-effective and reliable services to customers in the face of new complexities and an ever-changing industry. Standing up a resource adequacy program is a critical next step as the region undergoes transformative changes in the coming years,” TEA said.
Established in 1997, TEA is headquartered in Jacksonville, Florida. TEA’s West Region Office, located in Bellevue, Washington, provides a full range of power and portfolio management services for public power utilities located in the Bonneville Power Administration balancing area as well as in the state of California.
NWPP Completes Design Phase of Western Resource Adequacy Program
NWPP began planning the WRAP to prepare for the scheduled decommissioning coal plants in the region and increasing renewable integration. The program includes a comprehensive review of resource adequacy in NWPP’s territory.
NWPP is now gearing up to implement the first stage of WRAP in which participants will commit to meeting a common resource adequacy planning standard. Agreements in the first stage of the program will be non-binding, meaning there will be no penalties if participants do not meet their adequacy obligations.
The first stage also will not include the operational component of the program that would allow participants to pool and share resources during times when grid operating conditions are constrained.
Later stages of the program will layer on additional requirements and functions and evaluate further design changes that may be needed. The full program is expected to be in operation in 2024.
“We have reached a major milestone in our effort to stand up a resource adequacy program in the West,” Frank Afranji, president of NWPP, said in a statement. “A common resource adequacy planning standard will increase coordination and visibility with respect to adequacy in the region and is a positive step toward enhancing regional reliability.”
The next phase of the WRAP project will include evolving the NWPP’s corporate structure to house an independent board so NWPP can serve as the administrator of the program and filing with the Federal Energy Regulatory Commission (FERC).
NWPP said it would continue to work with Southwest Power Pool (SPP) to develop and implement the WRAP project. NWPP has hired SPP as the operator of the WRAP project. The scope of SPP’s services as a program operator include performing forward showing functions, modeling and system analytics, real-time operational program development, continual technical improvement, and IT systems work.
The next phase of the WRAP project also includes new participants Black Hills Power and Clatskanie Public Utility District.
In total, there are 20 participants in WRAP, representing approximately 57,300 megawatts of load and spanning nine states and one Canadian province committed to the program’s next phase. NWPP said it expects additional participants to join the program in the coming weeks.
NWPP released a report in August that detailed the design of the WRAP project.
CPS Energy Board Appoints Rudy Garza As Interim President And CEO
November 2, 2021
by Paul Ciampoli
APPA News Director
November 2, 2021
The CPS Energy Board of Trustees voted on Nov. 1 to appoint Rudy Garza as Interim President and CEO, effective November 8, 2021. Garza will serve in this role while the search for the permanent President and CEO takes place.
CPS Energy President and CEO Paula Gold-Williams on Oct. 21 informed the public power utility’s Board of Trustees of her plans to leave CPS Energy in early 2022.
The Board of Trustees announced at an October 25, 2021 board meeting that Chair Willis Mackey and Vice Chair Janie Gonzalez will lead the CEO Search Committee for the new President and CEO. All Board Members will be involved in the process.
To help with the national search, the board will retain an external firm, which has not been selected yet. Gold-Williams will remain with the utility in a helpful capacity through her formal planned departure in January 2022, CPS Energy said.
Garza has more than 25 years as a leader in the electric and natural gas utility industry and has served in both the public and private sectors over the course of his career. Garza has a Bachelor of Science in Electrical Engineering from the University of Texas in Austin and a Master of Business Administration from the University of North Texas.
Garza previously served as Chief Customer & Stakeholder Engagement Officer for CPS Energy and he will become the first Hispanic leader to hold this leadership position.
Garza joined CPS Energy in 2012 and previously served as Senior Vice President of Distribution Service and Operations where he oversaw the maintenance and construction activity of the electric distribution system and has also served the company in the role of Vice President of External Relations.
CPS Energy said that Garza and his leadership team will be evaluating the realignment of work and will provide updates on any organizational changes in the coming weeks.
Snohomish PUD projects Aim To Increase EV Charging Access, Social Equity
November 2, 2021
by Peter Maloney
APPA News
November 2, 2021
The Snohomish County Public Utility District has entered partnerships to provide electric vehicle (EV) charging facilities on a socially equitable basis in Everett, Wash., where the PUD is based.
In partnership with the City of Everett, Snohomish PUD is working on a project to install an in-ground resonant magnet induction charging system for electric buses at Eclipse Mill Park near downtown Everett. The installation, the first of its kind in western Washington, would have the ability to charge public buses while they are in service at the bus stop. It will also serve as a demonstration project for future electric vehicle charging installations.
“This project will allow buses to quickly charge during layover times, improving overall route efficiency,” Melinda Adams, transportation services manager at Everett Transit, said in a statement.
In a second project, Snohomish PUD is partnering with HopeWorks to install two new electric vehicle chargers, supplementing an existing charger at the newly constructed HopeWorks Station, a housing and commercial building. Snohomish PUD plans to install one public fast electric vehicle charger and one Level 2 charger for the public, residents, and staff usage.
HopeWorks Station is designed as a Sustainability Demonstration Site that serves residents coming out of homelessness with affordable housing and a workforce development center providing a career training program.
Snohomish PUD said both projects aim to increase the availability of electric vehicle charging and transportation for communities historically underserved by electric vehicle infrastructure and disproportionately impacted by climate change and pollution from transportation.
Snohomish PUD said both projects align with its electric transportation goals as outlined in SHB 1512, the Washington State law that, among other things, gave public power utilities authority to invest in electric vehicle infrastructure.
Both projects will be partially funded by Washington State’s Clean Energy Fund, which is managed by the state’s Department of Commerce and supports the development, demonstration and deployment of clean energy technology.
The Clean Energy Fund will contribute $728,780 to the bus charger project, which has a price tag of about $800,000. The Clean Energy Fund will contribute $135,582 to the HopeWorks project, which has a total cost of about $150,000.
To date, Washington’s Clean Energy Fund has invested more than $131 million in 98 clean energy projects in the state.
The American Public Power Association’s Public Power EV Activities Tracker summarizes key efforts undertaken by members — including incentives, electric vehicle deployment, charging infrastructure investments, rate design, pilot programs, and more. Click here for additional details.
Supreme Court Agrees To Review Appeals Court’s Power Plant Emissions Ruling
November 1, 2021
by APPA News
November 1, 2021
The U.S. Supreme Court on October 29 said it would review the U.S. Court of Appeals for the District of Columbia Circuit decision to vacate and remand the Environmental Protection Agency’s (EPA) Affordable Clean Energy (ACE) rule and repeal of the Clean Power Plan under section 111(d) of the Clean Air Act (CAA).
The appeals court found that ACE, as well as the repeal of the 2015 CPP, “hinged on a fundamental misconstruction of” CAA section 111(d). The appeals court’s decision rejected EPA’s position that the CAA only allows the agency to craft emissions restrictions that apply directly “at the source” of power plants. The position was a departure from the CPP’s sector-wide approach to reducing emissions. “In addition, the ACE rule’s amendment of the regulatory framework to slow the process for the reduction of emissions is arbitrary and capricious,” the appeals court said.
The Supreme Court granted four separate petitions to review the D.C. Circuit’s January 2021 decision. The cases are now consolidated for further consideration.
Each petition questioned whether the EPA has the statutory authority to completely restructure the electricity system nationwide.
The questions presented to the court are as follows:
- Whether Congress constitutionally authorized the EPA to issue significant rules – including those capable of reshaping the nation’s electricity grids and unilaterally decarbonizing virtually any sector of the economy under CAA section 111(d) — without any limits on what the agency can require so long as it considers cost, non-air impacts, and energy requirements;
- Whether the CAA unambiguously excludes generation shifting (also known as emissions trading) from the measures the EPA may consider in determining the “best system of emission reduction” to regulate emissions from existing power plants;
- Whether the EPA can promulgate regulations for existing stationary sources based on binding nationwide “performance standards” at a generation-sector-wide level, instead of at the individual source level, and can those regulations deprive States of all implementation and decision making power in creating their CAA section 111(d) plans; and
- Whether CAA section 111(d) clearly authorizes EPA to decide such matters of vast economic and political significance as to whether and how to restructure the nation’s energy system.
In defending the ACE rule at the D.C. Circuit, the EPA argued that it needed to repeal the CPP and replace it with the ACE rule because the CPP relied on an overly expansive interpretation of Section 111 of the CAA.
The CPP called for emitting sources to implement the best systems of emissions reduction (BESR) that were not limited to “inside the fence” modifications to the source.
The EPA subsequently argued that Section 111 unambiguously constrains EPA to include only improvements “at” and “to” existing sources when determining BSER. The D.C. Circuit disagreed, finding that the provisions defining BSER contain no such spatial limitation.
After the D.C. Circuit’s decision, EPA was expected to draft a new rule to regulate carbon dioxide emissions from power plants. Now, with the high court’s decision to take up the case, it throws significant uncertainty onto that process.
Oral arguments are likely to be held by the Supreme Court in February or March 2022, and a decision rendered before the court adjourns its October 2021 term on June 30, 2022.
CPS Energy Partners With Zpryme On Educational Augmented Reality App
October 29, 2021
by Paul Ciampoli
APPA News Director
October 29, 2021
Zpryme, an Austin, Texas-based based energy research company, on Oct. 20 announced a partnership with San Antonio, Texas-based public power utility CPS Energy to roll out an educational augmented reality (AR) application.
The dual language AR app, called Electrify San Antonio, will help students to learn about the energy production and distribution cycle. The app is available in Spanish and English.
Electrify San Antonio starts by exploring the inner workings of a CPS Energy power plant and its recycling systems, and demonstrates the process for creating distributed, renewable energy.
The app then provides an overview of three separate renewable energy sources and their frameworks and concludes with a unique user experience on how electricity is transmitted and distributed to local communities and businesses.
Electrify San Antonio is free and available for download in the Google Play and the Apple App Store.
Customer Connections Group Selects New Planning Committee Officers
October 29, 2021
by APPA News
October 29, 2021
New officers for the Customer Connections section and planning committees were named at the closing session of the American Public Power Association’s (APPA) 2021 Customer Connections Conference in Scottsdale, Ariz., which was held in October.
Nicki Parker, Customer Care Manager, Farmington Electric Utility System, New Mexico, will chair APPA’s Customer Connections Section in 2022. Palma Lough, Member Relations & Training Manager, Oklahoma Municipal Power Authority, is vice chair.
Alice Tucker, Customer Service Manager, Easley Combined Utilities, South Carolina, will chair the Customer Service Planning Committee; Lily Burgess, Office Manager, Stowe Electric Department, Vermont, will serve as vice chair. Caitlin Aburrow, Senior Director, Global Product Marketing, Oracle Utilities will serve as an advisory officer.
Koral Miller, Energy Services Manager, Mason County PUD 3, Shelton, Washington, will chair the Energy Innovation Planning Committee; Kristofor Sellstrom, Energy and Gas Resources Manager, Jamestown Board of Public Utilities, New York will serve as vice chair. Samantha Hart, Senior Project Manager, Sales and Innovation, Milepost Consulting will serve as an advisory officer.
Dale Odom, Supervisor, Business Development Services, ElectriCities of North Carolina will chair the Key Accounts Planning Committee; Andy Pollard, Electric Superintendent, Harrisonville Municipal Utilities, Missouri will serve as vice chair. Mary Malone, Director, Account Development, Questline Services will serve as an advisory officer.
Heather Contant, Director of Government & Community Relations, Delaware Municipal Electric Corporation will chair the Public Communications Planning Committee; Valerie Larson-Holmes, Director of Communications, Missouri River Energy Services, Sioux Falls, South Dakota will serve as vice chair.
For more information on APPA’s Customer Connections sections and committees, contact CustomerConnections@PublicPower.org.