ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The following discussion should be read in conjunction with Pinnacle West’s Consolidated Financial Statements and APS’s Consolidated Financial Statements and the related Notes that appear in Item 8 of this report. This discussion provides a comparison of the 2020 results with 2019 results. A comparison of the 2019 results with 2018 results can be found in the Annual Report on Form 10-K for the fiscal year ended December 31, 2019. For information on factors that may cause our actual future results to differ from those we currently seek or anticipate, see “Forward-Looking Statements” at the front of this report and “Risk Factors” in Item 1A.
OVERVIEW
Business Overview
Pinnacle West is an investor-owned electric utility holding company based in Phoenix, Arizona with consolidated assets of about $20 billion. For over 130 years, Pinnacle West and our affiliates have provided energy and energy-related products to people and businesses throughout Arizona.
Pinnacle West derives essentially all of our revenues and earnings from our principal subsidiary, APS. APS is Arizona’s largest and longest-serving electric company that generates safe, affordable and reliable electricity for approximately 1.3 million retail customers in 11 of Arizona’s 15 counties. APS is also the operator and co-owner of Palo Verde — a primary source of electricity for the southwest United States and the largest nuclear power plant in the United States.
COVID-19 Pandemic
The COVID-19 pandemic continues to be a rapidly evolving situation. It has led to economic disruption and volatility in financial markets worldwide. The Company is operating under long-standing pandemic and business continuity plans that exist to address situations including pandemics like COVID-19. We are focused on ensuring the health and safety of our employees, contractors and the general public by helping limit the spread of this virus and ensuring continued, safe and reliable electric service for APS customers.
We have identified business-critical positions in our operations and support organizations, with backup personnel ready to assist if an issue were to arise. Additionally, efforts to ensure the health and safety of our employees have resulted in bifurcated control rooms, thus reducing the number of employees in mission-critical locations. We also established COVID-19 safety protocols, social distancing practices including limiting one employee per vehicle and offering virtual options whenever possible. The Company also took rapid action to implement an all Company COVID-19 hotline, a focused COVID-19 team, and procured on-site COVID-19 testing at key facilities early in the pandemic. Through this testing, case management and contact tracing, the Company has been able to significantly limit COVID-19 transmission in the workplace. As a result of these efforts, we have been able to maintain the continuity of the essential services that we provide to our customers, while also managing the spread of the virus and promoting the health, physical and mental well-being and safety of our employees, customers and communities.
Essential planned work and capital investments are continuing during the pandemic, with some non-essential planned work postponed to the first quarter of 2021. APS has continuous discussions with suppliers on manpower and supply issues pertaining to COVID-19 and has measures in place to continue to monitor resource needs and supply chain adequacy. At this time, APS does not believe it has any material supply chain risks due to COVID-19 that would impact its ability to serve customers’ needs.
The Company’s operations and maintenance expenses, exclusive of bad debt expense, increased by approximately $25 million for the year ended December 31, 2020 due to costs for personal protective equipment and other health and safety-related costs related to COVID-19. We expect the Company’s operation and maintenance expenses will continue to be impacted for 2021 by the need for additional personal protective equipment and other health and safety-related costs related to COVID-19.
While the total expected impact of COVID-19 on future sales is currently unknown, APS has experienced higher electric residential sales and lower electric commercial and industrial sales since the outset of the pandemic. From March 13, 2020 through December 31, 2020, the cumulative impact in weather-normalized usage was approximately a 1% increase. During that period, APS’s retail electric residential weather-normalized sales increased 5%, and its retail electric commercial and industrial weather-normalized sales decreased 4% in the aggregate. APS expects the reduction in electric demand from commercial and industrial customers and increased demand from residential customers to normalize somewhat during 2021 as business activity continues to recover and more people return to work. Based on past experience, a 1% variation in our annual kWh sales projections under normal business conditions can result in increases or decreases in annual net income of approximately $20 million.
On March 31, 2020, a stay at home order became effective for the state of Arizona and remained in effect until May 16, 2020, when it was lifted and Arizona began reopening. In June 2020, Arizona saw an increase in the number of COVID-19 cases, hospitalizations, and deaths. Accordingly, on June 29, 2020, the governor of Arizona closed bars, indoor gyms and fitness clubs or centers, indoor movie theaters, water parks and tubing operations until July 27, 2020 as a partial reversal of the state’s reopening and to mitigate the spread of COVID-19. On July 23, 2020, the governor of Arizona extended these closures and they remained in place until August 27, 2020, when bars, gyms and movie theaters reopened with certain restrictions. We cannot predict the impact of the spread of COVID-19 in Arizona, whether there will be additional reclosures and how any such reclosures will impact our financial position, results of operations or cash flows. We are continuing to monitor the impacts of COVID-19.
As a result of the COVID-19 pandemic, in mid-March 2020, the commercial paper markets failed to function normally and we were unable to utilize commercial paper as our primary method of acquiring short-term capital, which resulted in us drawing on our revolving credit facilities during the first quarter of 2020. In mid-April 2020, we were again able to utilize the commercial paper market and we have paid down the entire amount of the revolving credit facilities that were utilized as a result of the commercial paper market failure.
The Coronavirus Aid, Relief, and Economic Security (CARES) Act allows employers to defer payments of the employer share of Social Security payroll taxes that would have otherwise been owed from March 27, 2020 through December 31, 2020. We deferred the cash payment of the employer’s portion of Social Security payroll taxes for the period July 1, 2020 through December 31, 2020 that was approximately $18 million. We will pay half of this cash deferral by December 31, 2021 and the remainder by December 31, 2022.
On June 30, 2020, FERC issued an order granting a waiver request related to the existing AFUDC rate calculation beginning March 1, 2020 through February 28, 2021. The order provides a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic. APS has adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and has left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacts the AFUDC composite rate in 2020, but does not impact prior years. Furthermore, the change in the composite rate calculation does not impact our accounting treatment for these costs. The change did not have a material impact on our financial statements (see Note 1.)
Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020. In addition, APS waived all late payment fees during this suspension period. On September 14, 2020, APS extended this suspension of disconnection of customers for nonpayment and waiver of late payment fees until December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until October 15, 2021. APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic. The Summer Disconnection Moratorium (see Note 4), the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both events resulted in a negative impact to its 2020 operating results of approximately $23 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. APS also currently estimates that the Summer Disconnection Moratorium, the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with this will result in a negative impact to its 2021 operating results of approximately $20 million to $30 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. These estimated impact amounts for 2021 depend on certain current assumptions, including, but not limited to, customer behaviors, population and employment growth, and the impacts of COVID-19 on the economy. Additionally, due to COVID-19, APS delayed the reset of the EIS adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 and and also delayed the reset of the PSA to the first billing cycle of April 2021 rather than February 2021 (see Note 4).
On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020 (see Note 4). As of December 31, 2020, APS had refunded approximately $43 million to customers. The additional $7 million over the approved amount of $36 million was the result of the kWh credit being based on historic consumption which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings.
APS has spent more than $15 million to assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic, with $12.4 million of these dollars directly committed to bill assistance programs (the “COVID Customer Support Fund”). The COVID Customer Support Fund was comprised of a series of voluntary commitments of funds that are not recoverable through rates throughout 2020 of approximately $8.8 million. An additional $3.6 million in bill credits for limited income customers was ordered by the ACC in December 2020 of which 50%, up to a
maximum of $2.5 million, was committed to be funds that are not recoverable through rates with the remaining being deferred for potential future recovery in rates. Included in the COVID Customer Support Fund were programs that assisted customers that had a delinquency of two or more months with a one-time credit of $100, an expanded credit of $300 for limited income customers, programs to assist extra small and small non-residential customers with a one-time credit of $1,000, and other targeted programs allocated to assist with other COVID-19 needs in support of utility bill assistance. The December 2020 ACC order further assisted delinquent limited income customers with an additional bill credit of up to $250 or their delinquent balance, whichever was less. As of December 31, 2020, APS had distributed all funds for all COVID Customer Support Fund programs combined. Beyond the COVID Customer Support Fund, APS has also provided $2.7 million to assist local non-profits and community organizations working to mitigate the impacts of the COVID-19 pandemic.
More detailed discussion of the impacts and future uncertainties related to the COVID‑19 pandemic can be found throughout this Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Combined Notes to Pinnacle West’s and APS’s financial statements that appear in Part II, Item 8 of this report and “Risk Factors” in Part I, Item 1A of this report.
Strategic Overview
Our strategy is to deliver shareholder value by creating a sustainable energy future for Arizona by serving our customers with clean, reliable and affordable energy.
Clean Energy Commitment
We are committed to doing our part to make the future clean and carbon-free. Our vision for APS and Arizona presents an opportunity to engage with customers, communities, employees, policymakers, shareholders and others to achieve a shared, sustainable vision for Arizona. This goal is based on sound science and supports continued growth and economic development while maintaining reliability and affordable prices for APS’s customers.
APS’s new clean energy goals consist of three parts:
•A 2050 goal to provide 100% clean, carbon-free electricity;
•A 2030 target of achieving a resource mix that is 65% clean energy, with 45% of the generation portfolio coming from renewable energy; and
•A commitment to end APS’s use of coal-fired generation by 2031.
APS’s ability to successfully execute its clean energy commitment is dependent upon a number of important external factors, some of which include a supportive regulatory environment, sales and customer growth, development of clean energy technologies and continued access to capital markets.
2050 Goal: 100% Clean, Carbon-Free Electricity. Achieving a fully clean, carbon-free energy mix by 2050 is our aspiration. The 2050 goal will involve new thinking and depends on improved and new technologies.
2030 Goal: 65% Clean Energy. APS has an energy mix that is already 50% clean with existing plans to add more renewables and energy storage before 2025. By building on those plans, APS intends to attain an energy mix that is 65% clean by 2030, with 45% of APS’s generation portfolio coming from renewable energy. Clean is measured as percent of energy mix which includes carbon-free resources like nuclear and demand-side management, and renewable is expressed as a percent of retail sales. This target will
serve as a checkpoint for our resource planning, investment strategy, and customer affordability efforts as APS moves toward 100% clean, carbon-free energy mix by 2050.
2031 Goal: End APS’s Use of Coal-Fired Generation. The commitment to end APS’s use of coal-fired generation by 2031 will require APS to cease use of coal-generation at Four Corners. APS has permanently retired more than 1,000 MW of coal-fired electric generating capacity. These closures and other measures taken by APS have resulted in a total reduction of carbon emissions of 26% since 2005. In addition, APS has committed to end the use of coal at its remaining Cholla units by 2025.
APS understands that the transition away from coal-fired power plants toward a clean energy future will pose unique economic challenges for the communities around these plants. We worked collaboratively with stakeholders and leaders of the Navajo Nation to consider the impacts of ceasing operation of APS coal-fired power plants on the communities surrounding those facilities to propose a comprehensive Coal Community Transition ("CCT") plan. The proposed framework provides substantial financial and economic development support to build new economic opportunities and addresses a transition strategy for plant employees. We are committed to continuing our long-running partnership with the Navajo Nation in other areas as well, including expanding electrification and developing tribal renewable projects. Our proposed CCT plan supports the Navajo Nation, where the Four Corners Power Plant is located, the communities surrounding the Cholla Power Plant and the Hopi Tribe, which is impacted by closure of the Navajo Plant. The CCT plan is currently pending ACC approval. (See Note 4 for a discussion of the CCT plan.)
Renewables. APS intends to strengthen its already diverse energy mix by increasing its investments in carbon-free resources. Its near-term actions include competitive solicitations to procure clean energy resources such as solar, wind, energy storage, demand response and DSM resources, all of which lead to a cleaner grid.
APS has a diverse portfolio of existing and planned renewable resources, including solar, wind, geothermal, biomass and biogas. APS’s clean energy strategy includes executing purchased power contracts for new facilities, ongoing development of distributed energy resources and procurement of new facilities to be owned by APS. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the projects to the electric grid. See “Business of Arizona Public Service Company — Energy Sources and Resource Planning — Current and Future Resources — Renewable Energy Standard — Renewable Energy Portfolio” in Item 1 for details regarding APS’s renewable energy resources.
Palo Verde. Palo Verde, the nation’s largest carbon-free, clean energy resource, will continue to be a foundational part of APS’s resource portfolio. The plant currently supplies nearly 70% of our clean energy and provides the foundation for the reliable and affordable service for APS customers. Palo Verde is not just the cornerstone of our current clean energy mix, it also is a significant provider of clean energy to the southwest United States. The plant’s continued operation is important to a carbon-free and clean energy future for Arizona and the region, as a reliable, continuous, affordable resource and as a large contributor to the local economy.
Affordable
We believe it is APS’s responsibility to deliver electric services to customers in the most cost-effective manner. Since January 2018 through December 2020, the average residential bill decreased by 7.3%, or $10.95.
Building upon existing cost management efforts, APS launched a customer affordability initiative in 2019. The initiative was implemented company-wide to thoughtfully and deliberately assess our business processes and organizational approaches to completing high-value work and internal efficiencies. Through the initiative and existing cost management practices, APS met its goal of $20 million in cost savings as of December 31, 2020.
Participation in the EIM continues to be an effective tool for creating savings for APS's customers from the real-time, voluntary market. APS continues to expect that its participation in EIM will lower its fuel and purchased-power costs, improve visibility and situational awareness for system operations in the Western Interconnection power grid, and improve integration of APS’s renewable resources. APS is in discussions with the EIM operator, CAISO, and other EIM participants about the feasibility of creating a voluntary day-ahead market to achieve more cost savings and use the region’s renewable resources more efficiently.
Reliable
While our energy mix evolves, the obligation to deliver reliable service to our customers remains. Notwithstanding the challenges presented by the COVID-19 pandemic as well as the hottest summer on record, APS continued to provide reliable service to its customers in 2020, setting a new all-time high peak energy demand of 7,660 MW, exceeding the prior peak set in 2017 by nearly 300 MW and achieved strong reliability results.
Planned investments will support operating and maintaining the grid, updating technology, accommodating customer growth and enabling more renewable energy resources. Our advanced distribution management system allows operators to locate outages, control line devices remotely and helps them coordinate more closely with field crews to safely maintain an increasingly dynamic grid. The system also integrates a new meter data management system that increases grid visibility and gives customers access to more of their energy usage data.
Wildfire safety remains a critical focus for APS and other utilities. We increased investment in fire mitigation efforts to clear defensible space around our infrastructure, build partnerships with government entities and first responders and educate customers and communities. These programs contribute to customer reliability, responsible forest management and safe communities.
The new units at our modernized Ocotillo power plant provide cleaner-running and more efficient units. They support reliability by responding quickly to the variability of solar generation and delivering energy in the late afternoon and early evening, when solar production declines as the sun sets and customer demand peaks.
Customer-Focused
Customers are at the core of what APS does every day and its focus remains on its customers and the communities it serves. It is APS’s goal to achieve an industry-leading best-in-class customer experience.
In 2020, APS adopted a number of changes to improve customer experience. It transitioned to a 24/7 care center operation to better serve its customers around the clock. APS improved its call center performance, answering nearly 75% of its more than 1.5 million telephone calls in 30 seconds or less. APS
has also made many improvements to its digital experience through its aps.com site, and its overall digital experience continues to improve for its customers.
APS also convened a customer advisory board and stakeholder committee in 2020 to serve as a vehicle for gathering valuable qualitative insights, directly from customers and stakeholders, that intends to keep APS apprised of customer needs, wants, and perspectives. Additionally, the customer advisory board is leveraged to identify and diagnose potential customer pain points and to help shape and co-create customer solutions.
APS is also providing assistance to residential and business customers that have been impacted by the COVID-19 pandemic. See “COVID-19 Pandemic” above for more information about customer support during COVID-19.
Emerging Technologies
Energy Storage
APS deploys a number of advanced technologies on its system, including energy storage. Storage can provide capacity, improve power quality, be utilized for system regulation, integrate renewable generation, and, in certain circumstances, be used to defer certain traditional infrastructure investments. Energy storage can also aid in integrating higher levels of renewables by storing excess energy when system demand is low and renewable production is high and then releasing the stored energy during peak demand hours later in the day and after sunset. APS is utilizing grid-scale energy storage projects to benefit customers, to increase renewable utilization, and to further our understanding of how storage works with other advanced technologies and the grid. We are preparing for additional energy storage in the future.
In early 2018, APS entered into a 15-year power purchase agreement for a 65 MW solar facility that charges a 50 MW solar-fueled battery. Service under the agreement was scheduled to begin in 2021; however, APS terminated the agreement, effective February 16, 2021, because the facility will not meet the expected in-service date. In 2018, APS issued an RFP for approximately 106 MW of energy storage to be located at up to five of its AZ Sun sites. Based upon its evaluation of the RFP responses, APS decided to expand the initial phase of battery deployment to 141 MW by adding a sixth AZ Sun site. These battery storage facilities are expected to be in service by June 2022. Additionally, in February 2019, APS signed two 20-year PPAs for energy storage totaling 150 MW. In April 2019, a battery module in APS’s McMicken battery energy storage facility experienced an equipment failure, which prompted an internal investigation to determine the cause. APS has now completed its investigation of the McMicken battery incident and is working with all counterparties to ensure that the learnings from the investigation, and the corresponding safety requirements, are incorporated into all battery storage projects going forward, including the projects associated with the two above-referenced PPAs. These PPAs were also subject to ACC approval in order to allow for cost recovery through the PSA. APS received the requested ACC approval on January 12, 2021, and service under both agreements is expected to begin in 2022.
We currently plan to install at least 850 MW of energy storage by 2025, including the energy storage projects under PPAs and AZ Sun retrofits described above. The remaining energy storage is expected to be made up of resources solicited through current and future RFPs. Currently, APS has two RFPs in the market that seek energy storage resources: (i) a battery storage RFP for projects to be located at the remaining two AZ Sun sites that were not included in the 2018 RFP referenced in the preceding paragraph; and (ii) an ‘all source’ RFP that solicits both standalone energy storage and renewable energy plus energy storage resources. Such resources would be expected to be in service during 2023 and 2024.
Electric Vehicles
APS is making electric vehicle charging more accessible for its customers and helping Arizona businesses, schools and governments electrify their fleets. In 2020, APS expanded its Take Charge AZ Pilot Program and installed 84 dual-plug Level 2 charging stations at business customer locations with more stations expected to be added through 2021. The program provides charging equipment, installation, and maintenance to business customers, government agencies, and multifamily housing communities. In addition to the Level 2 charging stations, APS will begin construction of direct current fast charging stations that will be owned and operated by APS at five locations in Arizona. This project is projected to be completed by the end of 2021 with each location including 2-150 kilowatt and 2-350 kilowatt DC fast charging stations. These stations will be accessible through the Electrify America charging network.
The ACC ordered the state’s public service corporations, including APS, to develop a long-term, comprehensive Statewide Transportation Electrification Plan (“TE Plan”) for Arizona. The TE Plan is intended to provide a roadmap for Transportation Electrification in Arizona, focused on realizing the associated air quality and economic development benefits for all residents in the state along with understanding the impact of electric vehicle charging on the grid. APS is actively participating in this process, which is scheduled to be completed by March 2021 and submitted to the ACC for review and approval.
Hydrogen Production
Palo Verde, in partnership with Idaho National Laboratory and two other utilities, has been chosen by the DOE’s Office of Nuclear Energy to participate in a hydrogen production project with the goal to improve the long-term economic competitiveness of the nuclear power industry. The multi-phase project is planned for 2020 through 2023. In the first phase, Idaho National Laboratory will perform a technical and economic assessment of using electricity generated at Palo Verde to produce hydrogen.
Experience from Palo Verde’s utility partners’ demonstration projects and from the Palo Verde-specific technical economic assessment is expected to offer insights into methods for flexible transitions between electricity and hydrogen generation in solar-dominated electricity markets.
Carbon Capture
Carbon capture technologies can isolate CO2 and either sequester it permanently in geologic formations or convert it for use in products. Currently, almost all existing fossil fuel generators do not control carbon emissions the way they control emissions of other air pollutants such as sulfur dioxide or oxides of nitrogen. Carbon capture technologies are still in the demonstration phase and while they show promise, they are still being tested in real-world conditions. These technologies could offer the potential to keep in operation existing generators that otherwise would need to be retired. APS will continue to monitor this emerging technology.
Regulatory Overview
On October 31, 2019, APS filed an application with the ACC seeking an annual increase in retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners SCR project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” in Note 4). It also reflects a net credit to base rates of approximately $115 million primarily due to the prospective inclusion of rate refunds currently provided through the TEAM. The proposed total annual
revenue increase in APS’s application is $184 million. The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%).
The principal provisions of APS’s application were:
•a test year comprised of twelve months ended June 30, 2019, adjusted as described below;
•an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;
•the following proposed capital structure and costs of capital:
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Capital Structure
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Cost of Capital
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Long-term debt
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45.3
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4.1
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Common stock equity
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54.7
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10.15
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Weighted-average cost of capital
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7.41
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%
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•a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;
•a Base Fuel Rate of $0.030168 per kWh;
•authorization to defer until APS’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;
•a number of proposed rate and program changes for residential customers, including:
▪a super off-peak period during the winter months for APS’s time-of-use with demand rates;
▪additional $1.25 million in funding for APS’s limited-income crisis bill program; and
▪a flat bill/subscription rate pilot program;
•proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;
•recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see Note 4 discussion of the 2017 Settlement Agreement); and
•continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Plant (see Note 4 for details related to the resulting regulatory asset).
APS requested that the increase become effective December 1, 2020.
On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC in this rate case. The ACC Staff recommends, among other things, a (i) $89.7 million revenue increase, (ii) average annual customer bill increase of 2.7%, (iii) return on equity of 9.4%, (iv) a 0.3% or, as an alternative, a 0% return on the increment of fair value rate base greater than original cost, (v) recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project. RUCO recommends, among other things, a (i) $20.8 million revenue decrease, (ii) average annual customer bill decrease of 0.63%, (iii) return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v) nonrecovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project.
The filed ACC Staff and intervenor testimony include additional recommendations, some of which materially differ from APS’s filed application. On November 6, 2020, APS filed its rebuttal testimony and the principal provisions which differ from its initial application include, among other things, a (i) $169 million revenue increase, (ii) average annual bill increase of 5.14%, (iii) return on equity of 10%, (iv) return on the increment of fair value rate base of 0.8%, (v) new cost recovery adjustor mechanism, the Advanced Energy Mechanism (“AEM”), to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) the CCT plan related to the closure or future closure of coal-fired generation facilities of which $25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.
The CCT plan includes the following proposed components: (i) $100 million that will be paid over 10 years to the Navajo Nation for a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $1.25 million that will be paid over five years to the Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners Power Plant through 2038, which would be funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Generating Station, which would primarily be funded by customers.
The hearing began January 14, 2021. Unfavorable ACC Staff and intervenor positions and recommendations could have a material impact on APS’s financial statements if ultimately adopted by the ACC. APS cannot predict the outcome of this proceeding.
See Note 4 for information regarding additional regulatory matters.
Arizona Attorney General Matter
APS received civil investigative demands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section (“Attorney General”) seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement results in APS paying $24.75 million, $24 million of which is being returned to customers as restitution. While this matter has been resolved with the Attorney General, APS cannot predict whether additional inquiries or actions may be taken by the ACC.
Financial Strength and Flexibility
Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities, and may readily access these facilities ensuring adequate liquidity for each company. Capital
expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.
Other Subsidiaries
Bright Canyon Energy. On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE. BCE’s strategy is to develop, own, operate and acquire energy infrastructure in a manner that leverages the Company’s core expertise in the electric energy industry. In 2014, BCE formed a 50/50 joint venture with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company. The joint venture, named TransCanyon, is pursuing independent electric transmission opportunities within the 11 states that comprise the Western Electricity Coordinating Council, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates.
On December 20, 2019, BCE acquired minority ownership positions in two wind farms under development by Tenaska Energy, Inc. and Tenaska Energy Holdings, LLC, the 242 MW Clear Creek wind farm in Missouri (“Clear Creek”) and the 250 MW Nobles 2 wind farm in Minnesota (“Nobles 2”). Clear Creek achieved commercial operation in May 2020 and Nobles 2 achieved commercial operation in December 2020. Both wind farms deliver power under long-term power purchase agreements. BCE indirectly owns 9.9% of Clear Creek and 5.1% of Nobles 2.
El Dorado. El Dorado is a wholly-owned subsidiary of Pinnacle West. El Dorado owns debt investments and minority interests in several energy-related investments and Arizona community-based ventures. El Dorado committed to a $25 million investment in the Energy Impact Partners fund, which is an organization that focuses on fostering innovation and supporting the transformation of the utility industry. The investment will be made by El Dorado as investments are selected by the Energy Impact Partners fund.
Key Financial Drivers
In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.
Electric Operating Revenues. For the years 2018 through 2020, retail electric revenues comprised approximately 95% of our total operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.
Actual and Projected Customer and Sales Growth. Retail customers in APS’s service territory increased 2.3% for the year ended December 31, 2020 compared with the prior-year period. For the three years 2018 through 2020, APS’s customer growth averaged 2.0% per year. We currently project annual customer growth to be 1.5% to 2.5% for 2021 and for 2021 through 2023 based on our assessment of steady population growth in Arizona.
Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 1.4% for the year ended December 31, 2020 compared with the prior-year period. While steady customer growth was offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives, the main drivers of positive sales for this period were continued strong residential sales due to work-from-home policies and a gradual improvement in sales to commercial and industrial customers. Though the total expected impact of COVID-19 on future sales is currently unknown, APS has experienced higher electric residential sales and lower electric commercial and industrial sales since the outset of the pandemic. From March 13, 2020 through December 31, 2020, the cumulative impact on weather-normalized usage was approximately a 1% increase. During that period, APS’s retail electric residential weather-normalized sales increased 5%, and its retail electric commercial and industrial weather-normalized sales decreased 4% in the aggregate. APS expects the reduction in electric demand from commercial and industrial customers and increased demand from residential customers to normalize somewhat into 2021 as business activity continues to recover and more people return to work.
For the three years 2018 through 2020, annual retail electricity sales were about flat, adjusted to exclude the effects of weather variations. We currently project that annual retail electricity sales in kWh will increase in the range of 0.5% to 1.5% for 2021 and increase on average in the range of 1.0% to 2.0% during 2021 through 2023, including the effects of customer conservation, energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations. This projected sales growth range now includes our estimated contributions of several large data centers, but not all, and we will continue to estimate contributions and evaluate sales guidance as these customers develop more usage history. These estimates could be further impacted by slower than expected growth of the Arizona economy, slower than expected ramp-up of the new data centers, or acceleration of the expected effects of customer conservation, energy efficiency, distributed renewable generation initiatives.
Consistent with our focus on continuously looking for improvement in our processes and procedures, we updated our weather normalization methodology in 2020 to better leverage available AMI data (smart meter data). While the prior method only used one to two months of daily usage data to estimate weather impacts, the new method utilizes a rolling four-year period of daily usage data, which improves the accuracy of estimated weather impacts on energy sales since many more data points are used for each calculation. Our 1.4% weather normalized sales growth for the year ended December 31, 2020 reflects this change in methodology. The impact to our 2018-2020 average normalized sales growth from this change in methodology is 0.2%.
Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and energy conservation, ramp-up of data centers, impacts of energy efficiency programs and growth in distributed generation, and responses to retail price changes. Based on past experience, a 1% variation in our annual kWh sales projections attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of approximately $20 million.
Weather. In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Historically, extreme weather variations have resulted in annual variations in net income in excess of $25 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $15 million.
Fuel and Purchased Power Costs. Fuel and purchased power costs included on our Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, changes in our generation resource allocation, our hedging program for managing such costs and PSA deferrals and the related amortization.
Operations and Maintenance Expenses. Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, unplanned outages, planned outages (typically scheduled in the spring and fall), renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors.
Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See “Liquidity and Capital Resources” below for information regarding the planned additions to our facilities.
Pension and Other Postretirement Non-Service Credits, Net. Pension and other postretirement non-service credits can be impacted by changes in our actuarial assumptions. The most relevant actuarial assumptions are the discount rate used to measure our net periodic costs/credit, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.
Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate in Arizona for APS, which owns essentially all of our property, was 10.8% of the assessed value for 2020, 10.9% for 2019 and 11.0% for 2018. We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units and transmission and distribution facilities.
Income Taxes. Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions and non-taxable items, such as AFUDC. In addition, income taxes may also be affected by the settlement of issues with taxing authorities. On December 22, 2017, the Tax Cuts and Jobs Act (the “Tax Act”) was enacted and was generally effective on January 1, 2018. Changes impacting the Company include a reduction in the corporate tax rate to 21%, revisions to the rules related to tax bonus depreciation, limitations on interest deductibility and an associated exception for certain public utilities, and requirements that certain excess deferred tax amounts of regulated utilities be normalized. (See Note 5 for details of the impacts on the Company as of December 31, 2020.) In APS’s 2017 Rate Case Decision, the ACC approved the TEAM, which is being used to pass through the income tax effects to retail customers of the Tax Act. (See Note 4 for details of the TEAM.)
Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 7). The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow. An allowance for borrowed funds used during construction offsets a portion of interest expense while capital projects are under construction. We stop accruing AFUDC on a project when it is placed in commercial operation.
RESULTS OF OPERATIONS
Pinnacle West’s only reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily sales supplied under traditional cost-based rate regulation) and related activities and includes electricity generation, transmission and distribution.
Operating Results – 2020 compared with 2019
Our consolidated net income attributable to common shareholders for the year ended December 31, 2020 was $551 million, compared with $538 million for the prior year. The results reflect an increase of approximately $13 million for the regulated electricity segment primarily due to higher revenue driven by the effects of weather and lower refunds in the current year related to the Tax Act, higher pension and other postretirement non-service credits and higher revenue from customer growth, partially offset by higher income taxes, including lower amortization of excess deferred taxes, higher depreciation and amortization expense, and higher other expenses. Weather had a significant impact on our result of operations due to the hotter than normal weather in 2020 compared to 2019.
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
|
|
2020
|
|
2019
|
|
Net change
|
|
(dollars in millions)
|
Regulated Electricity Segment:
|
|
|
|
|
|
Operating revenues less fuel and purchased power expenses
|
$
|
2,589
|
|
|
$
|
2,425
|
|
|
$
|
164
|
|
Operations and maintenance
|
(953)
|
|
|
(939)
|
|
|
(14)
|
|
Depreciation and amortization
|
(614)
|
|
|
(591)
|
|
|
(23)
|
|
Taxes other than income taxes
|
(225)
|
|
|
(219)
|
|
|
(6)
|
|
Pension and other postretirement non-service credits — net
|
56
|
|
|
23
|
|
|
33
|
|
All other income and expenses, net
|
26
|
|
|
61
|
|
|
(35)
|
|
Interest charges, net of allowance for borrowed funds used during construction
|
(229)
|
|
|
(217)
|
|
|
(12)
|
|
Income taxes (Note 5)
|
(78)
|
|
|
16
|
|
|
(94)
|
|
Less income related to noncontrolling interests (Note 18)
|
(19)
|
|
|
(19)
|
|
|
—
|
|
Regulated electricity segment income
|
553
|
|
|
540
|
|
|
13
|
|
All other
|
(2)
|
|
|
(2)
|
|
|
—
|
|
Net Income Attributable to Common Shareholders
|
$
|
551
|
|
|
$
|
538
|
|
|
$
|
13
|
|
Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $164 million higher for the year ended December 31, 2020 compared with the prior year. The following table summarizes the major components of this change:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
Operating
revenues
|
|
Fuel and
purchased
power expenses
|
|
Net change
|
|
(dollars in millions)
|
Effects of weather
|
$
|
165
|
|
|
$
|
40
|
|
|
$
|
125
|
|
Lower refunds in the current year related to the Tax Act (Note 4)
|
85
|
|
|
—
|
|
|
85
|
|
Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals
|
(78)
|
|
|
(85)
|
|
|
7
|
|
Lost fixed cost recovery
|
7
|
|
|
—
|
|
|
7
|
|
Lower renewable energy regulatory surcharges, offset by operations and maintenance costs
|
(9)
|
|
|
—
|
|
|
(9)
|
|
Lower retail revenue due to the impacts of energy efficiency, distributed generation and changes in customer usage patterns, partially offset by higher customer growth
|
(4)
|
|
|
6
|
|
|
(10)
|
|
Lower transmission revenues (Note 4)
|
(17)
|
|
|
—
|
|
|
(17)
|
|
Arizona Attorney General Matter (Note 11)
|
(24)
|
|
|
—
|
|
|
(24)
|
|
Miscellaneous items, net
|
(10)
|
|
|
(10)
|
|
|
—
|
|
Total
|
$
|
115
|
|
|
$
|
(49)
|
|
|
$
|
164
|
|
Operations and maintenance. Operations and maintenance expenses increased $14 million for the year ended December 31, 2020 compared with the prior-year period primarily because of:
•An increase of $25 million primarily related to COVID Customer Support Fund, personal protective equipment and other health and safety-related costs for COVID-19 response (see Note 4);
•An increase of $22 million related to employee benefits;
•An increase of $12 million related to customer bad debt expenses for the Summer Disconnection Moratorium and COVID-19 disconnect suspensions (see Note 4);
•An increase of $11 million for costs related to information technology;
•A decrease of $21 million in nuclear generation costs primarily related to an increased recovery from contributions of administrative and general costs from Palo Verde owners;
•A decrease of $14 million related to consulting costs;
•A decrease of $13 million primarily related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power;
•A decrease of $6 million for customer outreach costs; and
•A decrease of $2 million for corporate resources and other miscellaneous factors.
Depreciation and amortization. Depreciation and amortization expenses were $23 million higher for the year ended December 31, 2020 compared with the prior-year period primarily due to increased plant in service of $37 million, partially offset by the regulatory deferrals for the Ocotillo modernization project and the Four Corners SCR project of $17 million.
Taxes other than income taxes. Taxes other than income taxes were $6 million higher for the year ended December 31, 2020 compared with the prior-year period primarily due to higher property values.
Pension and other postretirement non-service credits, net. Pension and other postretirement non-service credits, net were $33 million higher for the year ended December 31, 2020 compared to the prior-year period, primarily due to higher market returns in 2019.
All other income and expenses, net. All other income and expenses, net were $35 million lower for the year ended December 31, 2020 compared to the prior-year period primarily due to the current year CCT and APS Foundation contributions.
Interest charges, net of allowance for borrowed funds used during construction. Interest charges, net of allowance for borrowed funds used during construction were $12 million higher for the year ended December 31, 2020 compared to the prior-year period primarily due to higher debt balances in the current period.
Income taxes. Income taxes were $94 million higher for the year ended December 31, 2020 compared with the prior-year period primarily due to higher pre-tax net income and lower amortization of excess deferred taxes, partially offset by higher tax credits.
LIQUIDITY AND CAPITAL RESOURCES
Overview
Pinnacle West’s primary cash needs are for dividends to our shareholders and principal and interest payments on our indebtedness. The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors and based on a number of factors, including our financial condition, payout ratio, free cash flow and other factors.
Our primary sources of cash are dividends from APS and external debt and equity issuances. An ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the related ACC order, the common equity ratio is defined as total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt. At December 31, 2020, APS’s common equity ratio, as defined, was 51%. Its total shareholder equity was approximately $6.2 billion, and total capitalization was approximately $12.2 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $4.9 billion, assuming APS’s total capitalization remains the same. This restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs or ability to pay dividends to shareholders.
APS’s capital requirements consist primarily of capital expenditures and maturities of long-term debt. APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financings and equity infusions from Pinnacle West.
Summary of Cash Flows
The following tables present net cash provided by (used for) operating, investing and financing activities for the years ended December 31, 2020 and 2019 (dollars in millions):
Pinnacle West Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
Net cash flow provided by operating activities
|
$
|
967
|
|
|
$
|
957
|
|
Net cash flow used for investing activities
|
(1,278)
|
|
|
(1,131)
|
|
Net cash flow provided by financing activities
|
361
|
|
|
179
|
|
Net increase in cash and cash equivalents
|
$
|
50
|
|
|
$
|
5
|
|
Arizona Public Service Company
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
Net cash flow provided by operating activities
|
$
|
929
|
|
|
$
|
1,007
|
|
Net cash flow used for investing activities
|
(1,286)
|
|
|
(1,136)
|
|
Net cash flow provided by financing activities
|
404
|
|
|
133
|
|
Net increase in cash and cash equivalents
|
$
|
47
|
|
|
$
|
4
|
|
Operating Cash Flows
2020 Compared with 2019. Pinnacle West’s consolidated net cash provided by operating activities was $967 million in 2020 compared to $957 million in 2019. The increase of $10 million in net cash provided is primarily due to higher cash receipts from electric revenues, lower payments for operations and maintenance, lower pension contributions, lower customer advances for construction, lower income tax payments and lower other taxes, partially offset by higher fuel and purchased power costs. The difference between APS and Pinnacle West’s net cash provided by operating activities primarily relates to APS’s income tax cash payments to Pinnacle West.
Retirement plans and other postretirement benefits. Pinnacle West sponsors a qualified defined benefit pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. The requirements of the Employee Retirement Income Security Act of 1974 (“ERISA”) require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under ERISA regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension benefit obligations. Under ERISA, the qualified pension plan was 124% funded as of January 1, 2021 and 117% as of January 1, 2020. Under accounting principles generally accepted in the United States of America ("GAAP"), the qualified pension plan was 104% funded as of January 1, 2021 and 97% funded as of January 1, 2020. (See Note 8 for additional details). The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $100 million in 2020, $150 million in 2019, and $50 million in 2018. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to $100 million in 2021 and zero thereafter. With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2020 and 2019. We do not expect to make
any contributions over the next three years to our other postretirement benefit plans. The Company was reimbursed $26 million in 2020, $30 million in 2019, and $72 million in 2018 for prior years retiree medical claims from the other postretirement benefit plan trust assets.
The Coronavirus Aid, Relief, and Economic Security (CARES) Act allows employers to defer payments of the employer share of Social Security payroll taxes that would have otherwise been owed from March 27, 2020 through December 31, 2020. We deferred the cash payment of the employer’s portion of Social Security payroll taxes for the period July 1, 2020 through December 31, 2020 that was approximately $18 million. We will pay half of this cash deferral by December 31, 2021 and the remainder by December 31, 2022.
Investing Cash Flows
2020 Compared with 2019. Pinnacle West’s consolidated net cash used for investing activities was $1,278 million in 2020 compared to $1,131 million in 2019. The increase of $147 million in net cash used primarily related to increased capital expenditures.
Capital Expenditures. The following table summarizes the estimated capital expenditures for the next three years:
Capital Expenditures
(dollars in millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated for the Year Ended
December 31,
|
|
2021
|
|
2022
|
|
2023
|
APS
|
|
|
|
|
|
Generation:
|
|
|
|
|
|
Clean:
|
|
|
|
|
|
Nuclear Generation
|
$
|
114
|
|
|
$
|
116
|
|
|
$
|
125
|
|
|
|
|
|
|
|
Renewables and Energy Storage Systems (“ESS”) (a)
|
200
|
|
|
276
|
|
|
281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Generation (b)
|
203
|
|
|
190
|
|
|
187
|
|
Distribution
|
577
|
|
|
556
|
|
|
549
|
|
Transmission
|
185
|
|
|
181
|
|
|
179
|
|
Other (c)
|
221
|
|
|
181
|
|
|
179
|
|
Total APS
|
$
|
1,500
|
|
|
$
|
1,500
|
|
|
$
|
1,500
|
|
(a)APS Solar Communities program, energy storage, renewable projects and other clean energy projects
(b)Includes generation environmental projects
(c)Primarily information systems and facilities projects
Generation capital expenditures are comprised of various additions and improvements to APS’s clean resources, including nuclear plants, renewables and ESS. Generation capital expenditures also include improvements to existing fossil plants. Examples of the types of projects included in the forecast of generation capital expenditures are additions of renewables and energy storage, and upgrades and capital replacements of various nuclear and fossil power plant equipment, such as turbines, boilers and
environmental equipment. We are monitoring the status of environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.
Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction. Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.
Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.
Financing Cash Flows and Liquidity
2020 Compared with 2019. Pinnacle West’s consolidated net cash provided by financing activities was $361 million in 2020 compared to $179 million of net cash provided in 2019, an increase of $182 million in net cash provided. The increase in net cash provided by financing activities includes $504 million in higher issuances of long-term debt partially offset by higher long-term debt repayments of $315 million, a net increase in short term borrowings of $16 million and higher dividend payments of $21 million.
APS’s consolidated net cash provided by financing activities was $404 million in 2020 compared to $133 million of net cash provided in 2019, an increase of $271 million in net cash provided. The increase in net cash provided by financing activities includes lower long-term debt repayments of $135 million and $8 million in higher issuances of long-term debt, higher equity infusion of $150 million and higher dividend payments of $21 million.
Significant Financing Activities. On December 16, 2020, the Pinnacle West Board of Directors declared a dividend of $0.83 per share of common stock, payable on March 1, 2021 to shareholders of record on February 1, 2021. During 2020, Pinnacle West increased its indicated annual dividend from $3.13 per share to $3.32 per share. For the year ended December 31, 2020, Pinnacle West’s total dividends paid per share of common stock were $3.18 per share, which resulted in dividend payments of $351 million.
On January 15, 2020, APS repaid at maturity the remaining $150 million of the $250 million aggregate principal amount of its 2.2% senior notes.
On May 22, 2020, APS issued $600 million of 3.35% unsecured senior notes that mature May 15, 2050. The net proceeds from the sale were used to repay early its $200 million term loan facility and to repay short-term indebtedness, consisting of commercial paper and revolver borrowings, and to replenish cash used to fund capital expenditures.
On June 17, 2020, Pinnacle West issued $500 million of 1.3% unsecured senior notes that mature June 15, 2025. The net proceeds from the sale were used to repay early its $150 million term loan facility set to mature on December 21, 2020, to repay short-term indebtedness consisting of commercial paper and replenish cash incurred or used to fund capital expenditures, to redeem prior to maturity our $300 million, 2.25% senior notes due November 30, 2020, and for general corporate purposes.
On September 11, 2020, APS issued $400 million of 2.65% unsecured senior notes that mature September 15, 2050. The net proceeds from the sale will be used to replenish cash used for previous eligible green expenditures and fund future eligible green expenditures.
On November 19, 2020, APS reopened its $300 million, 2.6% unsecured senior notes that mature on August 15, 2029, and issued an additional $105 million of 2.6% unsecured senior notes. The aggregate balance of $405 million will mature on August 15, 2029. The net proceeds from the sale, together with funds made available from other sources, were used to redeem, prior to maturity, no later than 20 days after the date that the new notes were issued, (i) the $49.4 million outstanding principal amount of 4.7% City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project), 1994 Series A, and (ii) the $65.75 million outstanding principal amount of 4.7% City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project), 1994 Series B.
On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that matures June 2022. The proceeds were received on January 4, 2021 and used for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 4, 2021.
On December 28, 2020, Pinnacle West contributed $150 million into APS in the form of an equity
infusion. APS used this contribution to repay short-term indebtedness.
Available Credit Facilities. Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper.
On May 5, 2020, Pinnacle West refinanced its 364-day $50 million term loan agreement that would have matured on May 7, 2020 with a new 364-day $31 million term loan agreement that matures May 4, 2021. Borrowings under the agreement bear interest at Eurodollar Rate plus 1.40% per annum. At December 31, 2020, Pinnacle West had $19 million in outstanding borrowings under the agreement.
At December 31, 2020, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings. The facility is available to support Pinnacle West’s $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At December 31, 2020, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $150 million of commercial paper borrowings.
At December 31, 2020, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2020, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding and no commercial paper borrowings. See “Financial Assurances” in Note 11 for a discussion of APS’s other outstanding letters of credit.
Other Financing Matters. See Note 16 for information related to the change in our margin and collateral accounts.
Debt Provisions
Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with these covenants. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2020, the ratio was approximately 54% for Pinnacle West and 49% for APS. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could “cross-default” other debt. See further discussion of “cross-default” provisions below.
Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.
See Note 7 for further discussions of liquidity matters.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of February 23, 2021 are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient available liquidity resources to respond to a downward revision to our credit ratings.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Moody’s
|
|
Standard & Poor’s
|
|
Fitch
|
Pinnacle West
|
|
|
|
|
|
Corporate credit rating
|
A3
|
|
A-
|
|
A-
|
Senior unsecured
|
A3
|
|
BBB+
|
|
A-
|
Commercial paper
|
P-2
|
|
A-2
|
|
F2
|
Outlook
|
Negative
|
|
Stable
|
|
Negative
|
|
|
|
|
|
|
|
|
|
|
|
|
APS
|
|
|
|
|
|
Corporate credit rating
|
A2
|
|
A-
|
|
A-
|
Senior unsecured
|
A2
|
|
A-
|
|
A
|
Commercial paper
|
P-1
|
|
A-2
|
|
F2
|
Outlook
|
Negative
|
|
Stable
|
|
Negative
|
Off-Balance Sheet Arrangements
See Note 18 for a discussion of the impacts on our financial statements of consolidating certain VIEs.
Contractual Obligations
The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2020 (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
|
2022-
2023
|
|
2024-
2025
|
|
Thereafter
|
|
Total
|
Long-term debt payments, including interest: (a)
|
|
|
|
|
|
|
|
|
|
APS
|
$
|
227
|
|
|
$
|
452
|
|
|
$
|
985
|
|
|
$
|
8,796
|
|
|
$
|
10,460
|
|
Pinnacle West
|
7
|
|
|
14
|
|
|
510
|
|
|
—
|
|
|
531
|
|
Total long-term debt payments, including interest
|
234
|
|
|
466
|
|
|
1,495
|
|
|
8,796
|
|
|
10,991
|
|
Short-term debt payments, including interest (b)
|
169
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
169
|
|
Fuel and purchased power commitments (c)
|
657
|
|
|
1,243
|
|
|
1,134
|
|
|
5,264
|
|
|
8,298
|
|
Renewable energy credits (d)
|
35
|
|
|
61
|
|
|
53
|
|
|
105
|
|
|
254
|
|
Purchase obligations (e)
|
115
|
|
|
60
|
|
|
22
|
|
|
185
|
|
|
382
|
|
Coal reclamation
|
16
|
|
|
35
|
|
|
39
|
|
|
69
|
|
|
159
|
|
Nuclear decommissioning funding requirements
|
2
|
|
|
4
|
|
|
4
|
|
|
48
|
|
|
58
|
|
Noncontrolling interests (f)
|
23
|
|
|
46
|
|
|
32
|
|
|
127
|
|
|
228
|
|
Operating lease payments (g)
|
14
|
|
|
20
|
|
|
11
|
|
|
37
|
|
|
82
|
|
Total contractual commitments
|
$
|
1,265
|
|
|
$
|
1,935
|
|
|
$
|
2,790
|
|
|
$
|
14,631
|
|
|
$
|
20,621
|
|
(a)The long-term debt matures at various dates through 2050 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2020 (see Note 7).
(b)See Note 6 for further details.
(c)Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation (see Notes 4 and 11).
(d)Contracts to purchase renewable energy credits in compliance with the RES (see Note 4).
(e)These contractual obligations include commitments for capital expenditures and other obligations.
(f)Payments to the noncontrolling interests relate to the Palo Verde sale leaseback (see Note 18).
(g)Commitments relating to purchased power lease contracts are included within the fuel and purchased power commitments line above (see Note 9).
This table excludes $46 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. In January 2021, approximately $391 million of new fuel and purchased power commitments have been executed, primarily relating to periods after 2025 (see Note 9). Estimated minimum required pension contributions are zero for 2021, 2022 and 2023 (see Note 8).
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those
judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.
Regulatory Accounting
Regulatory accounting allows for the actions of regulators, such as the ACC and FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers. Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings, except for pension benefits, which would be charged to OCI and result in lower future earnings. Management judgments also include assessing the impact of potential ACC or FERC Commission-ordered refunds to customers on regulatory liabilities. We had $1,426 million of regulatory assets and $2,679 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2020.
See Notes 1 and 4 for more information.
Pensions and Other Postretirement Benefit Accounting
Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit assets, liabilities and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2020 reported pension assets and liability on the Consolidated Balance Sheets and our 2020 reported pension expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
Actuarial Assumption (a)
|
|
Impact on
Pension
Plans
|
|
Impact on
Pension
Expense
|
Discount rate:
|
|
|
|
|
Increase 1%
|
|
$
|
(429)
|
|
|
$
|
(12)
|
|
Decrease 1%
|
|
522
|
|
|
12
|
|
Expected long-term rate of return on plan assets:
|
|
|
|
|
Increase 1%
|
|
—
|
|
|
(23)
|
|
Decrease 1%
|
|
—
|
|
|
23
|
|
(a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2020 other postretirement benefit obligation and our 2020 reported other postretirement benefit expense, after consideration of amounts capitalized or billed to electric plant participants, on Pinnacle West’s Consolidated Statements of Income (dollars in millions):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
Actuarial Assumption (a)
|
|
Impact on Other
Postretirement
Benefit
Plans
|
|
Impact on Other
Postretirement
Benefit Expense
|
Discount rate:
|
|
|
|
|
Increase 1%
|
|
$
|
(77)
|
|
|
$
|
(1)
|
|
Decrease 1%
|
|
98
|
|
|
4
|
|
Healthcare cost trend rate (b):
|
|
|
|
|
Increase 1%
|
|
86
|
|
|
8
|
|
Decrease 1%
|
|
(70)
|
|
|
(4)
|
|
Expected long-term rate of return on plan assets – pretax:
|
|
|
|
|
Increase 1%
|
|
—
|
|
|
(5)
|
|
Decrease 1%
|
|
—
|
|
|
5
|
|
(a)Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.
(b)This assumes a 1% change in the initial and ultimate healthcare cost trend rate.
See Note 8 for further details about our pension and other postretirement benefit plans.
Fair Value Measurements
We account for derivative instruments, investments held in our nuclear decommissioning trusts fund, investments held in our other special use funds, certain cash equivalents, and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use inputs, or assumptions that market participants would use, to determine fair market value. We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The significance of a particular input determines how the instrument is classified in a fair value hierarchy. The determination of fair value sometimes requires subjective and complex judgment. Our assessment of the inputs and the significance of a particular input to fair value measurement may affect the valuation of the instruments and their placement within a fair value hierarchy. Actual results could differ from our estimates of fair value. See Note 1 for a discussion of accounting policies and Note 13 for fair value measurement disclosures.
Asset Retirement Obligations
We recognize an ARO for the future decommissioning or retirement of our tangible long-lived assets for which a legal obligation exists. The ARO liability represents an estimate of the fair value of the current obligation related to decommissioning and the retirement of those assets. ARO measurements inherently involve uncertainty in the amount and timing of settlement of the liability. We use an expected cash flow approach to measure the amount we recognize as an ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the asset’s current license or lease term and expected decommissioning dates. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related assets. In addition, we accrete the ARO liability to reflect the passage of time. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets. In accordance with GAAP accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.
AROs as of December 31, 2020 are described further in Note 12.
OTHER ACCOUNTING MATTERS
On January 1, 2020, we adopted ASU 2016-13, and related amendments, pertaining to the measurement of credit losses on financial instruments. In 2020, we also adopted ASU 2018-14, related to defined benefit plan disclosures. (See Note 3 for additional information related to new accounting standards.)
MARKET AND CREDIT RISKS
Market Risks
Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust, other special use funds and benefit plan assets.
Interest Rate and Equity Risk
We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust, other special use funds (see Note 13 and Note 19), and benefit plan assets. The nuclear decommissioning trust, other special use funds and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments. Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.
The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2020 and 2019. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2020 and 2019 (dollars in millions):
Pinnacle West – Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-Term
Debt
|
|
Variable-Rate
Long-Term Debt
|
|
Fixed-Rate
Long-Term Debt
|
|
|
Interest
|
|
|
|
Interest
|
|
|
|
Interest
|
|
|
2020
|
|
Rates
|
|
Amount
|
|
Rates
|
|
Amount
|
|
Rates
|
|
Amount
|
2021
|
|
0.40
|
%
|
|
$
|
169
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
2022
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2023
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2024
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3.35
|
%
|
|
250
|
|
2025
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1.99
|
%
|
|
800
|
|
Years thereafter
|
|
—
|
|
|
—
|
|
|
0.18
|
%
|
|
36
|
|
|
3.95
|
%
|
|
5,280
|
|
Total
|
|
|
|
$
|
169
|
|
|
|
|
$
|
36
|
|
|
|
|
$
|
6,330
|
|
Fair value
|
|
|
|
$
|
169
|
|
|
|
|
$
|
36
|
|
|
|
|
$
|
7,577
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-Term
Debt
|
|
Variable-Rate
Long-Term Debt
|
|
Fixed-Rate
Long-Term Debt
|
|
|
Interest
|
|
|
|
Interest
|
|
|
|
Interest
|
|
|
2019
|
|
Rates
|
|
Amount
|
|
Rates
|
|
Amount
|
|
Rates
|
|
Amount
|
2020
|
|
2.06
|
%
|
|
$
|
115
|
|
|
2.16
|
%
|
|
$
|
350
|
|
|
2.23
|
%
|
|
$
|
450
|
|
2021
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2022
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2023
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2024
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3.78
|
%
|
|
365
|
|
Years thereafter
|
|
—
|
|
|
—
|
|
|
1.54
|
%
|
|
36
|
|
|
4.12
|
%
|
|
4,475
|
|
Total
|
|
|
|
$
|
115
|
|
|
|
|
$
|
386
|
|
|
|
|
$
|
5,290
|
|
Fair value
|
|
|
|
$
|
115
|
|
|
|
|
$
|
386
|
|
|
|
|
$
|
5,808
|
|
The tables below present contractual balances of APS’s long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2020 and 2019. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2020 and 2019 (dollars in millions):
APS — Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable-Rate
Long-Term Debt
|
|
Fixed-Rate
Long-Term Debt
|
|
|
|
|
|
|
Interest
|
|
|
|
Interest
|
|
|
2020
|
|
|
|
|
|
Rates
|
|
Amount
|
|
Rates
|
|
Amount
|
2021
|
|
|
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
$
|
—
|
|
2022
|
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2023
|
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2024
|
|
|
|
|
|
—
|
|
|
—
|
|
|
3.35
|
%
|
|
250
|
|
2025
|
|
|
|
|
|
—
|
|
|
—
|
|
|
3.15
|
%
|
|
300
|
|
Years thereafter
|
|
|
|
|
|
0.18
|
%
|
|
36
|
|
|
3.95
|
%
|
|
5,280
|
|
Total
|
|
|
|
|
|
|
|
$
|
36
|
|
|
|
|
$
|
5,830
|
|
Fair value
|
|
|
|
|
|
|
|
$
|
36
|
|
|
|
|
$
|
7,068
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable-Rate
Long-Term Debt
|
|
Fixed-Rate
Long-Term Debt
|
|
|
|
|
|
Interest
|
|
|
|
Interest
|
|
|
2019
|
|
|
|
|
Rates
|
|
Amount
|
|
Rates
|
|
Amount
|
2020
|
|
|
|
|
2.12
|
%
|
|
$
|
200
|
|
|
2.20
|
%
|
|
$
|
150
|
|
2021
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2022
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2023
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2024
|
|
|
|
|
—
|
|
|
—
|
|
|
3.78
|
%
|
|
365
|
|
Years thereafter
|
|
|
|
|
1.54
|
%
|
|
36
|
|
|
4.12
|
%
|
|
4,475
|
|
Total
|
|
|
|
|
|
|
$
|
236
|
|
|
|
|
$
|
4,990
|
|
Fair value
|
|
|
|
|
|
|
$
|
236
|
|
|
|
|
$
|
5,508
|
|
Commodity Price Risk
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity and natural gas. Our risk management committee, consisting of officers and key management personnel, oversees company-wide energy risk management activities to ensure compliance with our stated energy risk management policies. We manage risks associated with these market fluctuations by utilizing various commodity instruments that may qualify as derivatives, including futures, forwards, options and swaps. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity and natural gas. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities.
The following table shows the net pretax changes in mark-to-market of our derivative positions (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
Mark-to-market of net positions at beginning of year
|
$
|
(71)
|
|
|
$
|
(58)
|
|
Decrease (Increase) in regulatory asset
|
57
|
|
|
(15)
|
|
Recognized in OCI:
|
|
|
|
|
|
|
|
Mark-to-market losses realized during the period
|
1
|
|
|
2
|
|
Change in valuation techniques
|
—
|
|
|
—
|
|
Mark-to-market of net positions at end of year
|
$
|
(13)
|
|
|
$
|
(71)
|
|
The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2020 by maturities and by the type of valuation that is performed to calculate the fair values, classified in their entirety based on the lowest level of input that is significant to the fair value measurement. (See Note 1, “Derivative Accounting” and “Fair Value Measurements,” for more discussion of our valuation methods.)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Source of Fair Value
|
|
2021
|
|
2022
|
|
2023
|
|
2024
|
|
2025
|
|
Total
fair
value
|
Observable prices provided by other external sources
|
|
$
|
(2)
|
|
|
$
|
(3)
|
|
|
$
|
(5)
|
|
|
$
|
(2)
|
|
|
$
|
—
|
|
|
$
|
(12)
|
|
Prices based on unobservable inputs
|
|
(1)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1)
|
|
Total by maturity
|
|
$
|
(3)
|
|
|
$
|
(3)
|
|
|
$
|
(5)
|
|
|
$
|
(2)
|
|
|
$
|
—
|
|
|
$
|
(13)
|
|
The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management assets and liabilities included on Pinnacle West’s Consolidated Balance Sheets (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
Gain (Loss)
|
|
December 31, 2019
Gain (Loss)
|
|
Price Up 10%
|
|
Price Down 10%
|
|
Price Up 10%
|
|
Price Down 10%
|
Mark-to-market changes reported in:
|
|
|
|
|
|
|
|
Regulatory asset (liability) (a)
|
|
|
|
|
|
|
|
Electricity
|
$
|
4
|
|
|
$
|
(4)
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Natural gas
|
49
|
|
|
(49)
|
|
|
55
|
|
|
(55)
|
|
Total
|
$
|
53
|
|
|
$
|
(53)
|
|
|
$
|
55
|
|
|
$
|
(55)
|
|
(a)These contracts are economic hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties. (See Note 16 for a discussion of our credit valuation adjustment policy.)
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
See “Market and Credit Risks” in Item 7 above for a discussion of quantitative and qualitative disclosures about market risks.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULES
MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(PINNACLE WEST CAPITAL CORPORATION)
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Pinnacle West Capital Corporation. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2020. The effectiveness of our internal control over financial reporting as of December 31, 2020 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s consolidated financial statements.
February 24, 2021
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of
Pinnacle West Capital Corporation
Phoenix, Arizona
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Pinnacle West Capital Corporation and subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2020, the related notes and the schedules listed in the Index at Item 15 (collectively referred to as the “financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based
on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Accounting — Impact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 4 to the Financial Statements.
Critical Audit Matter Description
Arizona Public Service Company (“APS”), which is a wholly-owned subsidiary of the Company, is subject to rate regulation by the Arizona Corporation Commission (the “ACC”), which has jurisdiction with respect to the rates charged by public service utilities in Arizona. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; fuel and purchased power; operations and maintenance expense; and depreciation expense.
The ACC’s rate-making policies are premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the ACC in the future will impact the accounting for regulated operations, including decisions about the amount of allowable deferred costs and
return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the ACC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment. If future recovery of regulatory assets ceases to be probable or a disallowance becomes probable, it would result in a charge to earnings.
We identified Regulatory Accounting, specifically the impact of rate regulation on the financial statements, as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory rate orders on the financial statements. Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. Management judgments also include assessing the impact of potential ACC-ordered refunds to customers on regulatory liabilities. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the ACC, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the ACC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs of recently completed plant and costs deferred as regulatory assets and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to regulatory accounting, specifically the impact of rate regulation on the financial statements, including the balances recorded and regulatory developments.
•We read relevant regulatory rate orders issued by the ACC for APS and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the ACC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory assets and liabilities for completeness.
•We read management’s preliminary rate filings submitted and testimony given to the ACC regarding the 2019 Retail Rate Case filed in October 2019, and monitored activity by intervenors, the ACC and its staff and other testimony, as well as the Company’s rebuttal. The filing is still under review with the ACC. We read the filing and related testimony to assess the likelihood of recovery in future rates or of a future reduction in rates based on the information available as of our report date.
•We evaluated management’s assessment of the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities based on applicable regulatory orders or precedents set by the ACC under similar circumstances. For certain regulatory assets or liabilities where management’s assessment is based on precedents established by the ACC under similar circumstances and not specifically addressed in a regulatory order, we also obtained a letter from internal legal counsel regarding their assessment. We read the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment.
/s/ Deloitte & Touche LLP
Phoenix, Arizona
February 24, 2021
We have served as the Company’s auditor since 1932.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(dollars and shares in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
OPERATING REVENUES (NOTE 2)
|
$
|
3,586,982
|
|
|
$
|
3,471,209
|
|
|
$
|
3,691,247
|
|
OPERATING EXPENSES
|
|
|
|
|
|
Fuel and purchased power
|
993,419
|
|
|
1,042,237
|
|
|
1,076,116
|
|
Operations and maintenance
|
958,910
|
|
|
941,616
|
|
|
1,036,744
|
|
Depreciation and amortization
|
614,378
|
|
|
590,929
|
|
|
582,354
|
|
Taxes other than income taxes
|
224,835
|
|
|
218,579
|
|
|
212,849
|
|
Other expenses
|
7,288
|
|
|
5,888
|
|
|
9,497
|
|
Total
|
2,798,830
|
|
|
2,799,249
|
|
|
2,917,560
|
|
OPERATING INCOME
|
788,152
|
|
|
671,960
|
|
|
773,687
|
|
OTHER INCOME (DEDUCTIONS)
|
|
|
|
|
|
Allowance for equity funds used during construction (Note 1)
|
33,776
|
|
|
31,431
|
|
|
52,319
|
|
Pension and other postretirement non-service credits - net (Note 8)
|
56,341
|
|
|
22,989
|
|
|
49,791
|
|
Other income (Note 17)
|
56,703
|
|
|
50,263
|
|
|
24,896
|
|
Other expense (Note 17)
|
(57,776)
|
|
|
(17,880)
|
|
|
(17,966)
|
|
Total
|
89,044
|
|
|
86,803
|
|
|
109,040
|
|
INTEREST EXPENSE
|
|
|
|
|
|
Interest charges
|
247,501
|
|
|
235,251
|
|
|
243,465
|
|
Allowance for borrowed funds used during construction (Note 1)
|
(18,530)
|
|
|
(18,528)
|
|
|
(25,180)
|
|
Total
|
228,971
|
|
|
216,723
|
|
|
218,285
|
|
INCOME BEFORE INCOME TAXES
|
648,225
|
|
|
542,040
|
|
|
664,442
|
|
INCOME TAXES (Note 5)
|
78,173
|
|
|
(15,773)
|
|
|
133,902
|
|
NET INCOME
|
570,052
|
|
|
557,813
|
|
|
530,540
|
|
Less: Net income attributable to noncontrolling interests (Note 18)
|
19,493
|
|
|
19,493
|
|
|
19,493
|
|
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
|
$
|
550,559
|
|
|
$
|
538,320
|
|
|
$
|
511,047
|
|
|
|
|
|
|
|
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC
|
112,666
|
|
|
112,443
|
|
|
112,129
|
|
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED
|
112,942
|
|
|
112,758
|
|
|
112,550
|
|
|
|
|
|
|
|
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
|
|
|
|
|
|
Net income attributable to common shareholders — basic
|
$
|
4.89
|
|
|
$
|
4.79
|
|
|
$
|
4.56
|
|
Net income attributable to common shareholders — diluted
|
$
|
4.87
|
|
|
$
|
4.77
|
|
|
$
|
4.54
|
|
The accompanying notes are an integral part of the financial statements.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
NET INCOME
|
$
|
570,052
|
|
|
$
|
557,813
|
|
|
$
|
530,540
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
|
|
|
|
|
|
Derivative instruments:
|
|
|
|
|
|
Net unrealized loss, net of tax benefit (expense) of $662, $0, and $(78)
|
(2,089)
|
|
|
—
|
|
|
(78)
|
|
Reclassification of net realized gain, net of tax expense of $171, $375, and $473 (Note 16)
|
592
|
|
|
1,137
|
|
|
1,527
|
|
Pension and other postretirement benefits activity, net of tax benefit (expense) of $1,371, $3,452, and $(1,585) (Note 8)
|
(4,203)
|
|
|
(10,525)
|
|
|
4,397
|
|
Total other comprehensive income (loss)
|
(5,700)
|
|
|
(9,388)
|
|
|
5,846
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME
|
564,352
|
|
|
548,425
|
|
|
536,386
|
|
Less: Comprehensive income attributable to noncontrolling interests
|
19,493
|
|
|
19,493
|
|
|
19,493
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS
|
$
|
544,859
|
|
|
$
|
528,932
|
|
|
$
|
516,893
|
|
The accompanying notes are an integral part of the financial statements.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2020
|
|
2019
|
ASSETS
|
|
|
|
|
|
|
|
CURRENT ASSETS
|
|
|
|
Cash and cash equivalents
|
$
|
59,968
|
|
|
$
|
10,283
|
|
Customer and other receivables
|
313,576
|
|
|
266,426
|
|
Accrued unbilled revenues
|
132,197
|
|
|
128,165
|
|
Allowance for doubtful accounts
|
(19,782)
|
|
|
(8,171)
|
|
Materials and supplies (at average cost)
|
314,745
|
|
|
331,091
|
|
Fossil fuel (at average cost)
|
19,552
|
|
|
14,829
|
|
|
|
|
|
Income tax receivable (Note 5)
|
6,792
|
|
|
21,727
|
|
Assets from risk management activities (Note 16)
|
2,931
|
|
|
515
|
|
Deferred fuel and purchased power regulatory asset (Note 4)
|
175,835
|
|
|
70,137
|
|
Other regulatory assets (Note 4)
|
115,878
|
|
|
133,070
|
|
Other current assets
|
76,627
|
|
|
61,958
|
|
Total current assets
|
1,198,319
|
|
|
1,030,030
|
|
INVESTMENTS AND OTHER ASSETS
|
|
|
|
Nuclear decommissioning trust (Notes 13 and 19)
|
1,138,435
|
|
|
1,010,775
|
|
Other special use funds (Notes 13 and 19)
|
254,509
|
|
|
245,095
|
|
Other assets
|
92,922
|
|
|
96,953
|
|
Total investments and other assets
|
1,485,866
|
|
|
1,352,823
|
|
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)
|
|
|
|
Plant in service and held for future use
|
20,837,885
|
|
|
19,836,292
|
|
Accumulated depreciation and amortization
|
(7,110,310)
|
|
|
(6,637,857)
|
|
Net
|
13,727,575
|
|
|
13,198,435
|
|
Construction work in progress
|
937,384
|
|
|
808,133
|
|
Palo Verde sale leaseback, net of accumulated depreciation of $253,014 and $249,144 (Note 18)
|
98,036
|
|
|
101,906
|
|
Intangible assets, net of accumulated amortization of $698,500 and $647,276
|
282,570
|
|
|
290,564
|
|
Nuclear fuel, net of accumulated amortization of $137,207 and $137,330
|
113,645
|
|
|
123,500
|
|
Total property, plant and equipment
|
15,159,210
|
|
|
14,522,538
|
|
DEFERRED DEBITS
|
|
|
|
Regulatory assets (Notes 1, 4 and 5)
|
1,133,987
|
|
|
1,304,073
|
|
Operating lease right-of-use assets (Note 9)
|
505,064
|
|
|
145,813
|
|
Assets for pension and other postretirement benefits (Note 8)
|
502,992
|
|
|
90,570
|
|
Other
|
34,983
|
|
|
33,400
|
|
Total deferred debits
|
2,177,026
|
|
|
1,573,856
|
|
TOTAL ASSETS
|
$
|
20,020,421
|
|
|
$
|
18,479,247
|
|
The accompanying notes are an integral part of the financial statements.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2020
|
|
2019
|
LIABILITIES AND EQUITY
|
|
|
|
CURRENT LIABILITIES
|
|
|
|
Accounts payable
|
$
|
318,585
|
|
|
$
|
346,448
|
|
Accrued taxes
|
159,551
|
|
|
144,899
|
|
Accrued interest
|
56,962
|
|
|
53,534
|
|
Common dividends payable
|
93,531
|
|
|
87,982
|
|
Short-term borrowings (Note 6)
|
169,000
|
|
|
114,675
|
|
Current maturities of long-term debt (Note 7)
|
—
|
|
|
800,000
|
|
Customer deposits
|
48,340
|
|
|
64,908
|
|
Liabilities from risk management activities (Note 16)
|
7,557
|
|
|
38,946
|
|
Liabilities for asset retirements (Note 12)
|
15,586
|
|
|
11,025
|
|
|
|
|
|
Operating lease liabilities (Note 9)
|
74,785
|
|
|
12,713
|
|
Regulatory liabilities (Note 4)
|
229,088
|
|
|
234,912
|
|
Other current liabilities
|
187,448
|
|
|
168,323
|
|
Total current liabilities
|
1,360,433
|
|
|
2,078,365
|
|
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 7)
|
6,314,266
|
|
|
4,832,558
|
|
DEFERRED CREDITS AND OTHER
|
|
|
|
Deferred income taxes (Note 5)
|
2,135,403
|
|
|
1,992,339
|
|
Regulatory liabilities (Notes 1, 4, 5 and 8)
|
2,450,169
|
|
|
2,267,835
|
|
Liabilities for asset retirements (Note 12)
|
689,497
|
|
|
646,193
|
|
Liabilities for pension benefits (Note 8)
|
166,484
|
|
|
280,185
|
|
Liabilities from risk management activities (Note 16)
|
11,062
|
|
|
33,186
|
|
Customer advances
|
221,032
|
|
|
215,330
|
|
Coal mine reclamation
|
170,097
|
|
|
165,695
|
|
Deferred investment tax credit
|
191,372
|
|
|
196,468
|
|
Unrecognized tax benefits (Note 5)
|
5,834
|
|
|
6,189
|
|
Operating lease liabilities (Note 9)
|
361,336
|
|
|
51,872
|
|
Other
|
190,643
|
|
|
159,844
|
|
Total deferred credits and other
|
6,592,929
|
|
|
6,015,136
|
|
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
|
|
|
|
EQUITY
|
|
|
|
Common stock, no par value; authorized 150,000,000 shares, 112,760,051 and 112,540,126 issued at respective dates
|
2,677,482
|
|
|
2,659,561
|
|
Treasury stock at cost; 72,006 shares at end of 2020 and 103,546 shares at end of 2019
|
(6,289)
|
|
|
(9,427)
|
|
Total common stock
|
2,671,193
|
|
|
2,650,134
|
|
Retained earnings
|
3,025,106
|
|
|
2,837,610
|
|
Accumulated other comprehensive loss (Note 20)
|
(62,796)
|
|
|
(57,096)
|
|
Total shareholders’ equity
|
5,633,503
|
|
|
5,430,648
|
|
Noncontrolling interests (Note 18)
|
119,290
|
|
|
122,540
|
|
Total equity
|
5,752,793
|
|
|
5,553,188
|
|
TOTAL LIABILITIES AND EQUITY
|
$
|
20,020,421
|
|
|
$
|
18,479,247
|
|
The accompanying notes are an integral part of the financial statements.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
Net Income
|
$
|
570,052
|
|
|
$
|
557,813
|
|
|
$
|
530,540
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
Depreciation and amortization including nuclear fuel
|
686,253
|
|
|
664,140
|
|
|
650,955
|
|
Deferred fuel and purchased power
|
(93,651)
|
|
|
(82,481)
|
|
|
(78,277)
|
|
Deferred fuel and purchased power amortization
|
(12,047)
|
|
|
49,508
|
|
|
116,750
|
|
Allowance for equity funds used during construction
|
(33,776)
|
|
|
(31,431)
|
|
|
(52,319)
|
|
Deferred income taxes
|
69,469
|
|
|
(1,479)
|
|
|
117,355
|
|
Deferred investment tax credit
|
(5,096)
|
|
|
(3,938)
|
|
|
(5,170)
|
|
|
|
|
|
|
|
Stock compensation
|
18,292
|
|
|
18,376
|
|
|
19,547
|
|
Changes in current assets and liabilities:
|
|
|
|
|
|
Customer and other receivables
|
(18,191)
|
|
|
(12,789)
|
|
|
37,530
|
|
Accrued unbilled revenues
|
(4,032)
|
|
|
9,005
|
|
|
(24,736)
|
|
Materials, supplies and fossil fuel
|
11,623
|
|
|
(51,826)
|
|
|
(6,103)
|
|
Income tax receivable
|
14,935
|
|
|
(21,727)
|
|
|
—
|
|
Other current assets
|
(30,640)
|
|
|
(3,507)
|
|
|
33,844
|
|
Accounts payable
|
(6,059)
|
|
|
50,641
|
|
|
(14,602)
|
|
Accrued taxes
|
14,652
|
|
|
(9,920)
|
|
|
6,597
|
|
Other current liabilities
|
22,520
|
|
|
(84,651)
|
|
|
28,174
|
|
Change in margin and collateral accounts — assets
|
404
|
|
|
(247)
|
|
|
143
|
|
Change in margin and collateral accounts — liabilities
|
100
|
|
|
(125)
|
|
|
(2,211)
|
|
|
|
|
|
|
|
Change in unrecognized tax benefits
|
2,220
|
|
|
2,704
|
|
|
(1,235)
|
|
Change in long-term regulatory liabilities
|
13,017
|
|
|
124,221
|
|
|
(109,284)
|
|
Change in other long-term assets
|
(67,453)
|
|
|
(82,895)
|
|
|
78,604
|
|
Change in other long-term liabilities
|
(186,227)
|
|
|
(132,666)
|
|
|
(48,958)
|
|
Net cash flow provided by operating activities
|
966,365
|
|
|
956,726
|
|
|
1,277,144
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
Capital expenditures
|
(1,326,584)
|
|
|
(1,191,447)
|
|
|
(1,178,169)
|
|
Contributions in aid of construction
|
62,503
|
|
|
70,693
|
|
|
27,716
|
|
Allowance for borrowed funds used during construction
|
(18,530)
|
|
|
(18,528)
|
|
|
(25,180)
|
|
Proceeds from nuclear decommissioning trust sales and other special use funds
|
819,518
|
|
|
719,034
|
|
|
653,033
|
|
Investment in nuclear decommissioning trust and other special use funds
|
(822,608)
|
|
|
(722,181)
|
|
|
(672,165)
|
|
Other
|
7,883
|
|
|
11,452
|
|
|
1,941
|
|
Net cash flow used for investing activities
|
(1,277,818)
|
|
|
(1,130,977)
|
|
|
(1,192,824)
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
Issuance of long-term debt
|
1,596,672
|
|
|
1,092,188
|
|
|
445,245
|
|
Repayment of long-term debt
|
(915,150)
|
|
|
(600,000)
|
|
|
(182,000)
|
|
Short-term borrowings and (repayments) — net
|
73,325
|
|
|
54,275
|
|
|
(7,000)
|
|
Short-term debt borrowings under revolving credit facility
|
751,690
|
|
|
49,000
|
|
|
45,000
|
|
Short-term debt repayments under revolving credit facility
|
(770,690)
|
|
|
(65,000)
|
|
|
(57,000)
|
|
Dividends paid on common stock
|
(350,577)
|
|
|
(329,643)
|
|
|
(308,892)
|
|
Common stock equity issuance and purchases — net
|
(1,389)
|
|
|
692
|
|
|
(5,055)
|
|
Distributions to noncontrolling interests
|
(22,743)
|
|
|
(22,744)
|
|
|
(22,744)
|
|
Net cash flow provided by (used for) financing activities
|
361,138
|
|
|
178,768
|
|
|
(92,446)
|
|
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
49,685
|
|
|
4,517
|
|
|
(8,126)
|
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
10,283
|
|
|
5,766
|
|
|
13,892
|
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
$
|
59,968
|
|
|
$
|
10,283
|
|
|
$
|
5,766
|
|
The accompanying notes are an integral part of the financial statements.
PINNACLE WEST CAPITAL CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(dollars in thousands, except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
Treasury Stock
|
|
Retained Earnings
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Noncontrolling Interests
|
|
Total
|
|
Shares
|
|
Amount
|
|
Shares
|
|
Amount
|
|
|
|
|
|
|
|
|
Balance, December 31, 2017
|
111,816,170
|
|
|
$
|
2,614,805
|
|
|
(64,463)
|
|
|
$
|
(5,624)
|
|
|
$
|
2,442,511
|
|
|
$
|
(45,002)
|
|
|
$
|
129,040
|
|
|
$
|
5,135,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
—
|
|
|
|
|
—
|
|
|
511,047
|
|
|
—
|
|
|
19,493
|
|
|
530,540
|
|
Other comprehensive income
|
|
|
—
|
|
|
|
|
—
|
|
|
—
|
|
|
5,846
|
|
|
—
|
|
|
5,846
|
|
Dividends on common stock ($2.87 per share)
|
|
|
—
|
|
|
|
|
—
|
|
|
(320,927)
|
|
|
—
|
|
|
—
|
|
|
(320,927)
|
|
Issuance of common stock
|
343,726
|
|
|
19,460
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19,460
|
|
Purchase of treasury stock (a)
|
|
|
—
|
|
|
(129,903)
|
|
|
(10,338)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(10,338)
|
|
Reissuance of treasury stock for stock-based compensation and other
|
|
|
—
|
|
|
136,231
|
|
|
11,137
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,137
|
|
Capital activities by noncontrolling interests
|
|
|
—
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(22,743)
|
|
|
(22,743)
|
|
Reclassification of income tax effects related to new tax reform (b)
|
|
|
—
|
|
|
|
|
—
|
|
|
8,552
|
|
|
(8,552)
|
|
|
—
|
|
|
—
|
|
Balance, December 31, 2018
|
112,159,896
|
|
|
2,634,265
|
|
|
(58,135)
|
|
|
(4,825)
|
|
|
2,641,183
|
|
|
(47,708)
|
|
|
125,790
|
|
|
5,348,705
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
—
|
|
|
|
|
—
|
|
|
538,320
|
|
|
—
|
|
|
19,493
|
|
|
557,813
|
|
Other comprehensive loss
|
|
|
—
|
|
|
|
|
—
|
|
|
—
|
|
|
(9,388)
|
|
|
—
|
|
|
(9,388)
|
|
Dividends on common stock ($3.04 per share)
|
|
|
—
|
|
|
|
|
—
|
|
|
(341,893)
|
|
|
—
|
|
|
—
|
|
|
(341,893)
|
|
Issuance of common stock
|
380,230
|
|
|
25,296
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25,296
|
|
Purchase of treasury stock (a)
|
|
|
—
|
|
|
(121,493)
|
|
|
(11,202)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,202)
|
|
Reissuance of treasury stock for stock-based compensation and other
|
|
|
—
|
|
|
76,082
|
|
|
6,600
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,600
|
|
Capital activities by noncontrolling interests
|
|
|
—
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(22,743)
|
|
|
(22,743)
|
|
Balance, December 31, 2019
|
112,540,126
|
|
|
2,659,561
|
|
|
(103,546)
|
|
|
(9,427)
|
|
|
2,837,610
|
|
|
(57,096)
|
|
|
122,540
|
|
|
5,553,188
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
—
|
|
|
|
|
—
|
|
|
550,559
|
|
|
—
|
|
|
19,493
|
|
|
570,052
|
|
Other comprehensive loss
|
|
|
—
|
|
|
|
|
—
|
|
|
—
|
|
|
(5,700)
|
|
|
—
|
|
|
(5,700)
|
|
Dividends on common stock ($3.23 per share)
|
|
|
—
|
|
|
|
|
—
|
|
|
(363,063)
|
|
|
—
|
|
|
—
|
|
|
(363,063)
|
|
Issuance of common stock
|
219,925
|
|
|
17,921
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
17,921
|
|
Purchase of treasury stock (a)
|
|
|
—
|
|
|
(81,256)
|
|
|
(7,181)
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(7,181)
|
|
Reissuance of treasury stock for stock-based compensation and other
|
|
|
—
|
|
|
112,796
|
|
|
10,319
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital activities by noncontrolling interests
|
|
|
—
|
|
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(22,743)
|
|
|
(22,743)
|
|
Balance, December 31, 2020
|
112,760,051
|
|
|
$
|
2,677,482
|
|
|
(72,006)
|
|
|
$
|
(6,289)
|
|
|
$
|
3,025,106
|
|
|
$
|
(62,796)
|
|
|
$
|
119,290
|
|
|
$
|
5,752,793
|
|
(a) Primarily represents shares of common stock withheld from certain stock awards for tax purposes.
(b) In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) on items within accumulated other comprehensive income to retained earnings.
The accompanying notes are an integral part of the financial statements.
MANAGEMENT’S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
(ARIZONA PUBLIC SERVICE COMPANY)
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f), for Arizona Public Service Company. Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework (2013), our management concluded that our internal control over financial reporting was effective as of December 31, 2020. The effectiveness of our internal control over financial reporting as of December 31, 2020 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein and also relates to the Company’s financial statements.
February 24, 2021
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholder and the Board of Directors of
Arizona Public Service Company
Phoenix, Arizona
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Arizona Public Service Company and subsidiaries (the “Company”) as of December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows, for each of the three years in the period ended December 31, 2020, the related notes and the schedule listed in the Index at Item 15 (collectively referred to as the “financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based
on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Regulatory Accounting – Impact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 4 to the financial statements
Critical Audit Matter Description
The Company is subject to rate regulation by the Arizona Corporation Commission (the “ACC”), which has jurisdiction with respect to the rates charged by public service utilities in Arizona. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant and equipment; regulatory assets and liabilities; operating revenues; fuel and purchased power; operations and maintenance expense; and depreciation expense.
The ACC’s rate-making policies are premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the ACC in the future will impact the accounting for regulated operations, including decisions about the amount of allowable deferred costs and
return on invested capital included in rates and any refunds that may be required. While the Company has indicated it expects to recover costs from customers through regulated rates, there is a risk that the ACC will not approve: (1) full recovery of the costs of providing utility service, or (2) full recovery of all amounts invested in the utility business and a reasonable return on that investment. If future recovery of regulatory assets ceases to be probable or a disallowance becomes probable, it would result in a charge to earnings.
We identified Regulatory Accounting, specifically the impact of rate regulation on the financial statements, as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory rate orders on the financial statements. Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. Management judgments also include assessing the impact of potential ACC-ordered refunds to customers on regulatory liabilities. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the ACC, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the ACC included the following, among others:
•We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs of recently completed plant and costs deferred as regulatory assets and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We also tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.
•We evaluated the Company’s disclosures related to regulatory accounting, specifically the impact of rate regulation on the financial statements, including the balances recorded and regulatory developments.
•We read relevant regulatory rate orders issued by the ACC for the Company and other public utilities in Arizona, regulatory statutes, interpretations, procedural memorandums, filings made by interveners, and other publicly available information to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedents of the ACC’s treatment of similar costs under similar circumstances. We evaluated the external information and compared to management’s recorded regulatory assets and liabilities for completeness.
•We read management’s preliminary rate filings submitted and testimony given to the ACC regarding the 2019 Retail Rate Case filed in October 2019, and monitored activity by intervenors, the ACC and its staff and other testimony, as well as the Company’s rebuttal. The filing is still under review with the ACC. We read the filing and related testimony to assess the likelihood of recovery in future rates or of a future reduction in rates based on the information available as of our report date.
•We evaluated management’s assessment of the probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities based on applicable regulatory orders or precedents set by the ACC under similar circumstances. For certain regulatory assets or liabilities where management’s assessment is based on precedents established by the ACC under similar circumstances and not specifically addressed in a regulatory order, we also obtained a letter from internal legal counsel regarding their assessment. We read the minutes of the Boards of Directors of the Company for discussions of changes in legal, regulatory, or business factors which could impact management’s assessment.
/s/ Deloitte & Touche LLP
Phoenix, Arizona
February 24, 2021
We have served as the Company’s auditor since 1932.
ARIZONA PUBLIC SERVICE COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
OPERATING REVENUES (NOTE 2)
|
$
|
3,586,982
|
|
|
$
|
3,471,209
|
|
|
$
|
3,688,342
|
|
|
|
|
|
|
|
OPERATING EXPENSES
|
|
|
|
|
|
Fuel and purchased power
|
993,419
|
|
|
1,042,237
|
|
|
1,094,020
|
|
Operations and maintenance
|
945,181
|
|
|
926,716
|
|
|
969,227
|
|
Depreciation and amortization
|
614,293
|
|
|
590,844
|
|
|
580,694
|
|
Taxes other than income taxes
|
224,790
|
|
|
218,540
|
|
|
212,136
|
|
Other expense
|
7,288
|
|
|
5,888
|
|
|
2,497
|
|
Total
|
2,784,971
|
|
|
2,784,225
|
|
|
2,858,574
|
|
OPERATING INCOME
|
802,011
|
|
|
686,984
|
|
|
829,768
|
|
OTHER INCOME (DEDUCTIONS)
|
|
|
|
|
|
Allowance for equity funds used during construction (Note 1)
|
33,776
|
|
|
31,431
|
|
|
52,319
|
|
Pension and other postretirement non-service credits - net (Note 8)
|
57,359
|
|
|
24,529
|
|
|
51,242
|
|
Other income (Note 17)
|
51,755
|
|
|
46,884
|
|
|
22,746
|
|
Other expense (Note 17)
|
(53,694)
|
|
|
(12,990)
|
|
|
(15,292)
|
|
Total
|
89,196
|
|
|
89,854
|
|
|
111,015
|
|
INTEREST EXPENSE
|
|
|
|
|
|
Interest charges
|
233,452
|
|
|
220,174
|
|
|
231,391
|
|
Allowance for borrowed funds used during construction (Note 1)
|
(18,530)
|
|
|
(18,528)
|
|
|
(25,180)
|
|
Total
|
214,922
|
|
|
201,646
|
|
|
206,211
|
|
INCOME BEFORE INCOME TAXES
|
676,285
|
|
|
575,192
|
|
|
734,572
|
|
INCOME TAXES (Note 5)
|
88,764
|
|
|
(9,572)
|
|
|
144,814
|
|
NET INCOME
|
587,521
|
|
|
584,764
|
|
|
589,758
|
|
Less: Net income attributable to noncontrolling interests
(Note 18)
|
19,493
|
|
|
19,493
|
|
|
19,493
|
|
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
|
$
|
568,028
|
|
|
$
|
565,271
|
|
|
$
|
570,265
|
|
The accompanying notes are an integral part of the financial statements.
ARIZONA PUBLIC SERVICE COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
NET INCOME
|
$
|
587,521
|
|
|
$
|
584,764
|
|
|
$
|
589,758
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
|
|
|
|
|
|
Derivative instruments:
|
|
|
|
|
|
Net unrealized loss, net of tax benefit (expense) of $(18), $0, and $(78)
|
(18)
|
|
|
—
|
|
|
(78)
|
|
Reclassification of net realized gain, net of tax expense of $171, $375, and $473 (Note 16)
|
592
|
|
|
1,137
|
|
|
1,527
|
|
Pension and other postretirement benefits activity, net of tax benefit (expense) of $1,955, $3,136, and $(1,159) (Note 8)
|
(5,970)
|
|
|
(9,552)
|
|
|
3,465
|
|
Total other comprehensive income (loss)
|
(5,396)
|
|
|
(8,415)
|
|
|
4,914
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME
|
582,125
|
|
|
576,349
|
|
|
594,672
|
|
Less: Comprehensive income attributable to noncontrolling interests
|
19,493
|
|
|
19,493
|
|
|
19,493
|
|
|
|
|
|
|
|
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDER
|
$
|
562,632
|
|
|
$
|
556,856
|
|
|
$
|
575,179
|
|
The accompanying notes are an integral part of the financial statements.
ARIZONA PUBLIC SERVICE COMPANY
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2020
|
|
2019
|
ASSETS
|
|
|
|
PROPERTY, PLANT AND EQUIPMENT (Notes 1, 7 and 10)
|
|
|
|
Plant in service and held for future use
|
$
|
20,834,424
|
|
|
$
|
19,832,805
|
|
Accumulated depreciation and amortization
|
(7,107,058)
|
|
|
(6,634,597)
|
|
Net
|
13,727,366
|
|
|
13,198,208
|
|
Construction work in progress
|
937,384
|
|
|
808,133
|
|
Palo Verde sale leaseback, net of accumulated depreciation of $253,014 and $249,144 (Note 18)
|
98,036
|
|
|
101,906
|
|
Intangible assets, net of accumulated amortization of $697,366 and $646,142
|
282,415
|
|
|
290,409
|
|
Nuclear fuel, net of accumulated amortization of $137,207 and $137,330
|
113,645
|
|
|
123,500
|
|
Total property, plant and equipment
|
15,158,846
|
|
|
14,522,156
|
|
INVESTMENTS AND OTHER ASSETS
|
|
|
|
Nuclear decommissioning trust (Notes 13 and 19)
|
1,138,435
|
|
|
1,010,775
|
|
Other special use funds (Notes 13 and 19)
|
254,509
|
|
|
245,095
|
|
Other assets
|
46,010
|
|
|
43,781
|
|
Total investments and other assets
|
1,438,954
|
|
|
1,299,651
|
|
CURRENT ASSETS
|
|
|
|
Cash and cash equivalents
|
57,310
|
|
|
10,169
|
|
Customer and other receivables
|
312,644
|
|
|
255,479
|
|
Accrued unbilled revenues
|
132,197
|
|
|
128,165
|
|
Allowance for doubtful accounts
|
(19,782)
|
|
|
(8,171)
|
|
Materials and supplies (at average cost)
|
314,745
|
|
|
331,091
|
|
Fossil fuel (at average cost)
|
19,552
|
|
|
14,829
|
|
Income tax receivable (Note 5)
|
—
|
|
|
7,313
|
|
Assets from risk management activities (Note 16)
|
2,931
|
|
|
515
|
|
Deferred fuel and purchased power regulatory asset (Note 4)
|
175,835
|
|
|
70,137
|
|
Other regulatory assets (Note 4)
|
115,878
|
|
|
133,070
|
|
|
|
|
|
Other current assets
|
47,593
|
|
|
38,895
|
|
Total current assets
|
1,158,903
|
|
|
981,492
|
|
DEFERRED DEBITS
|
|
|
|
Regulatory assets (Notes 1, 4, and 5)
|
1,133,987
|
|
|
1,304,073
|
|
Operating lease right-of-use assets (Note 9)
|
503,475
|
|
|
144,024
|
|
Assets for pension and other postretirement benefits (Note 8)
|
495,673
|
|
|
86,736
|
|
Other
|
34,413
|
|
|
32,591
|
|
Total deferred debits
|
2,167,548
|
|
|
1,567,424
|
|
TOTAL ASSETS
|
$
|
19,924,251
|
|
|
$
|
18,370,723
|
|
The accompanying notes are an integral part of the financial statements.
ARIZONA PUBLIC SERVICE COMPANY
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2020
|
|
2019
|
LIABILITIES AND EQUITY
|
|
|
|
CAPITALIZATION
|
|
|
|
Common stock
|
$
|
178,162
|
|
|
$
|
178,162
|
|
Additional paid-in capital
|
2,871,696
|
|
|
2,721,696
|
|
Retained earnings
|
3,216,955
|
|
|
3,011,927
|
|
Accumulated other comprehensive loss (Note 20)
|
(40,918)
|
|
|
(35,522)
|
|
Total shareholder equity
|
6,225,895
|
|
|
5,876,263
|
|
Noncontrolling interests (Note 18)
|
119,290
|
|
|
122,540
|
|
Total equity
|
6,345,185
|
|
|
5,998,803
|
|
Long-term debt less current maturities (Note 7)
|
5,817,945
|
|
|
4,833,133
|
|
Total capitalization
|
12,163,130
|
|
|
10,831,936
|
|
CURRENT LIABILITIES
|
|
|
|
|
|
|
|
Current maturities of long-term debt (Note 7)
|
—
|
|
|
350,000
|
|
Accounts payable
|
311,699
|
|
|
338,006
|
|
Accrued taxes
|
148,970
|
|
|
136,328
|
|
Accrued interest
|
56,322
|
|
|
52,619
|
|
Common dividends payable
|
93,500
|
|
|
88,000
|
|
Customer deposits
|
48,340
|
|
|
64,908
|
|
|
|
|
|
Liabilities from risk management activities (Note 16)
|
7,557
|
|
|
38,946
|
|
Liabilities for asset retirements (Note 12)
|
15,586
|
|
|
11,025
|
|
|
|
|
|
Operating lease liabilities (Note 9)
|
74,695
|
|
|
12,549
|
|
Regulatory liabilities (Note 4)
|
229,088
|
|
|
234,912
|
|
Other current liabilities
|
190,420
|
|
|
164,736
|
|
Total current liabilities
|
1,176,177
|
|
|
1,492,029
|
|
DEFERRED CREDITS AND OTHER
|
|
|
|
Deferred income taxes (Note 5)
|
2,143,673
|
|
|
2,033,096
|
|
Regulatory liabilities (Notes 1, 4, 5 and 8)
|
2,450,169
|
|
|
2,267,835
|
|
Liabilities for asset retirements (Note 12)
|
689,497
|
|
|
646,193
|
|
Liabilities for pension benefits (Note 8)
|
148,943
|
|
|
262,243
|
|
Liabilities from risk management activities (Note 16)
|
11,062
|
|
|
33,186
|
|
Customer advances
|
221,032
|
|
|
215,330
|
|
Coal mine reclamation
|
170,097
|
|
|
165,695
|
|
Deferred investment tax credit
|
191,372
|
|
|
196,468
|
|
Unrecognized tax benefits (Note 5)
|
39,410
|
|
|
40,188
|
|
Operating lease liabilities (Note 9)
|
359,653
|
|
|
50,092
|
|
Other
|
160,036
|
|
|
136,432
|
|
Total deferred credits and other
|
6,584,944
|
|
|
6,046,758
|
|
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
|
|
|
|
TOTAL LIABILITIES AND EQUITY
|
$
|
19,924,251
|
|
|
$
|
18,370,723
|
|
The accompanying notes are an integral part of the financial statements.
ARIZONA PUBLIC SERVICE COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
CASH FLOWS FROM OPERATING ACTIVITIES
|
|
|
|
|
|
Net income
|
$
|
587,521
|
|
|
$
|
584,764
|
|
|
$
|
589,758
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
Depreciation and amortization including nuclear fuel
|
686,168
|
|
|
664,055
|
|
|
649,295
|
|
Deferred fuel and purchased power
|
(93,651)
|
|
|
(82,481)
|
|
|
(78,277)
|
|
Deferred fuel and purchased power amortization
|
(12,047)
|
|
|
49,508
|
|
|
116,750
|
|
Allowance for equity funds used during construction
|
(33,776)
|
|
|
(31,431)
|
|
|
(52,319)
|
|
Deferred income taxes
|
36,462
|
|
|
48,367
|
|
|
59,927
|
|
Deferred investment tax credit
|
(5,096)
|
|
|
(3,938)
|
|
|
(5,170)
|
|
|
|
|
|
|
|
Changes in current assets and liabilities:
|
|
|
|
|
|
Customer and other receivables
|
(28,206)
|
|
|
(12,075)
|
|
|
35,406
|
|
Accrued unbilled revenues
|
(4,032)
|
|
|
9,005
|
|
|
(24,736)
|
|
Materials, supplies and fossil fuel
|
11,623
|
|
|
(51,826)
|
|
|
(6,206)
|
|
Income tax receivable
|
7,313
|
|
|
(7,313)
|
|
|
—
|
|
Other current assets
|
(24,669)
|
|
|
(1,461)
|
|
|
31,707
|
|
Accounts payable
|
(4,503)
|
|
|
53,258
|
|
|
(15,608)
|
|
Accrued taxes
|
12,642
|
|
|
(40,029)
|
|
|
19,008
|
|
Other current liabilities
|
29,587
|
|
|
(82,138)
|
|
|
25,070
|
|
Change in margin and collateral accounts — assets
|
404
|
|
|
(247)
|
|
|
143
|
|
Change in margin and collateral accounts — liabilities
|
100
|
|
|
(125)
|
|
|
(2,211)
|
|
|
|
|
|
|
|
Change in unrecognized tax benefits
|
2,220
|
|
|
2,704
|
|
|
(1,235)
|
|
Change in long-term regulatory liabilities
|
13,017
|
|
|
124,221
|
|
|
(109,284)
|
|
Change in other long-term assets
|
(65,139)
|
|
|
(85,725)
|
|
|
77,952
|
|
Change in other long-term liabilities
|
(186,871)
|
|
|
(129,682)
|
|
|
(55,169)
|
|
Net cash flow provided by operating activities
|
929,067
|
|
|
1,007,411
|
|
|
1,254,801
|
|
CASH FLOWS FROM INVESTING ACTIVITIES
|
|
|
|
|
|
Capital expenditures
|
(1,326,584)
|
|
|
(1,191,447)
|
|
|
(1,169,061)
|
|
Contributions in aid of construction
|
62,503
|
|
|
70,693
|
|
|
27,716
|
|
Allowance for borrowed funds used during construction
|
(18,530)
|
|
|
(18,528)
|
|
|
(25,180)
|
|
Proceeds from nuclear decommissioning trust sales and other special use funds
|
819,518
|
|
|
719,034
|
|
|
653,033
|
|
Investment in nuclear decommissioning trust and other special use funds
|
(822,608)
|
|
|
(722,181)
|
|
|
(672,165)
|
|
Other
|
(554)
|
|
|
6,336
|
|
|
(1,789)
|
|
Net cash flow used for investing activities
|
(1,286,255)
|
|
|
(1,136,093)
|
|
|
(1,187,446)
|
|
CASH FLOWS FROM FINANCING ACTIVITIES
|
|
|
|
|
|
Issuance of long-term debt
|
1,099,722
|
|
|
1,092,188
|
|
|
295,245
|
|
Repayment of long-term debt
|
(465,150)
|
|
|
(600,000)
|
|
|
(182,000)
|
|
|
|
|
|
|
|
Short-term debt borrowings under revolving credit facility
|
540,000
|
|
|
—
|
|
|
25,000
|
|
Short-term debt repayments under revolving credit facility
|
(540,000)
|
|
|
—
|
|
|
(25,000)
|
|
Dividends paid on common stock
|
(357,500)
|
|
|
(336,300)
|
|
|
(316,000)
|
|
Equity infusion from Pinnacle West
|
150,000
|
|
|
—
|
|
|
150,000
|
|
Noncontrolling interests
|
(22,743)
|
|
|
(22,744)
|
|
|
(22,744)
|
|
Net cash flow provided by (used for) financing activities
|
404,329
|
|
|
133,144
|
|
|
(75,499)
|
|
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
|
47,141
|
|
|
4,462
|
|
|
(8,144)
|
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR
|
10,169
|
|
|
5,707
|
|
|
13,851
|
|
CASH AND CASH EQUIVALENTS AT END OF YEAR
|
$
|
57,310
|
|
|
$
|
10,169
|
|
|
$
|
5,707
|
|
The accompanying notes are an integral part of the financial statements.
ARIZONA PUBLIC SERVICE COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
Additional Paid-In Capital
|
|
Retained Earnings
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Noncontrolling Interests
|
|
Total
|
|
Shares
|
|
Amount
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2017
|
71,264,947
|
|
|
$
|
178,162
|
|
|
$
|
2,571,696
|
|
|
$
|
2,533,954
|
|
|
$
|
(26,983)
|
|
|
$
|
129,040
|
|
|
$
|
5,385,869
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity infusion from Pinnacle West
|
|
|
—
|
|
|
150,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
150,000
|
|
Net income
|
|
|
—
|
|
|
—
|
|
|
570,265
|
|
|
—
|
|
|
19,493
|
|
|
589,758
|
|
Other comprehensive income
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,914
|
|
|
—
|
|
|
4,914
|
|
Dividends on common stock
|
|
|
—
|
|
|
—
|
|
|
(321,001)
|
|
|
—
|
|
|
—
|
|
|
(321,001)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassifications of income tax effects related to new tax reform (a)
|
|
|
—
|
|
|
—
|
|
|
5,038
|
|
|
(5,038)
|
|
|
—
|
|
|
—
|
|
Capital activities by noncontrolling interests
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(22,743)
|
|
|
(22,743)
|
|
Balance, December 31, 2018
|
71,264,947
|
|
|
178,162
|
|
|
2,721,696
|
|
|
2,788,256
|
|
|
(27,107)
|
|
|
125,790
|
|
|
5,786,797
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
—
|
|
|
—
|
|
|
565,271
|
|
|
—
|
|
|
19,493
|
|
|
584,764
|
|
Other comprehensive loss
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,415)
|
|
|
—
|
|
|
(8,415)
|
|
Dividends on common stock
|
|
|
—
|
|
|
—
|
|
|
(341,600)
|
|
|
—
|
|
|
—
|
|
|
(341,600)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital activities by noncontrolling interests
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(22,743)
|
|
|
(22,743)
|
|
Balance, December 31, 2019
|
71,264,947
|
|
|
178,162
|
|
|
2,721,696
|
|
|
3,011,927
|
|
|
(35,522)
|
|
|
122,540
|
|
|
5,998,803
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity infusion from Pinnacle West
|
|
|
—
|
|
|
150,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
150,000
|
|
Net income
|
|
|
—
|
|
|
—
|
|
|
568,028
|
|
|
—
|
|
|
19,493
|
|
|
587,521
|
|
Other comprehensive loss
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(5,396)
|
|
|
—
|
|
|
(5,396)
|
|
Dividends on common stock
|
|
|
—
|
|
|
—
|
|
|
(363,000)
|
|
|
—
|
|
|
—
|
|
|
(363,000)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital activities by noncontrolling interests
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(22,743)
|
|
|
(22,743)
|
|
Balance, December 31, 2020
|
71,264,947
|
|
|
$
|
178,162
|
|
|
$
|
2,871,696
|
|
|
$
|
3,216,955
|
|
|
$
|
(40,918)
|
|
|
$
|
119,290
|
|
|
$
|
6,345,185
|
|
(a)In 2018, the Company adopted new accounting guidance and elected to reclassify income tax effects of the Tax Act on items within accumulated other comprehensive income to retained earnings.
The accompanying notes are an integral part of the financial statements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Description of Business and Basis of Presentation
Pinnacle West is a holding company that conducts business through its subsidiaries, APS, El Dorado, BCE and 4CA. APS, our wholly-owned subsidiary, is a vertically-integrated electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS accounts for essentially all of our revenues and earnings, and is expected to continue to do so. El Dorado is an investment firm. BCE is a subsidiary that was formed in 2014 that focuses on growth opportunities that leverage the Company’s core expertise in the electric energy industry. 4CA is a subsidiary that was formed in 2016 as a result of the purchase of El Paso’s 7% interest in Four Corners. (See Note 11 for more information on 4CA matters.)
Pinnacle West’s Consolidated Financial Statements include the accounts of Pinnacle West and our subsidiaries: APS, El Dorado, BCE and 4CA. APS’s Consolidated Financial Statements include the accounts of APS and certain VIEs relating to the Palo Verde sale leaseback. Intercompany accounts and transactions between the consolidated companies have been eliminated.
We consolidate VIEs for which we are the primary beneficiary. We determine whether we are the primary beneficiary of a VIE through a qualitative analysis that identifies which variable interest holder has the controlling financial interest in the VIE. In performing our primary beneficiary analysis, we consider all relevant facts and circumstances, including the design and activities of the VIE, the terms of the contracts the VIE has entered into, and which parties participated significantly in the design or redesign of the entity. We continually evaluate our primary beneficiary conclusions to determine if changes have occurred which would impact our primary beneficiary assessments. We have determined that APS is the primary beneficiary of certain VIE lessor trusts relating to the Palo Verde sale leaseback, and therefore APS consolidates these entities. (See Note 18 for additional information.)
Our consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments, except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.
Accounting Records and Use of Estimates
Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory Accounting
APS is regulated by the ACC and FERC. The accompanying financial statements reflect the rate-making policies of these commissions. As a result, we capitalize certain costs that would be included as expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers.
Management judgments include continually assessing the likelihood of future recovery of regulatory assets and/or a disallowance of part of the cost of recently completed plant, by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. Management judgments also include assessing the impact of potential Commission-ordered refunds to customers on regulatory liabilities.
See Note 4 for additional information.
Electric Revenues
Revenues primarily consist of activities that are classified as revenues from contracts with customers. Our electric revenues generally represent a single performance obligation delivered over time. We have elected to apply the practical expedient that allows us to recognize revenue based on the amount to which we have a right to invoice for services performed.
We derive electric revenues primarily from sales of electricity to our regulated retail customers. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. Unbilled revenues are estimated by applying an average revenue/kWh by customer class to the number of estimated kWhs delivered but not billed. Differences historically between the actual and estimated unbilled revenues are immaterial. We exclude sales taxes and franchise fees on electric revenues from both revenue and taxes other than income taxes.
Revenues from our regulated retail customers and non-derivative instruments are reported on a gross basis on Pinnacle West’s Consolidated Statements of Income. In the electricity business, some contracts to purchase electricity are netted against other contracts to sell electricity. This is called a “book-out” and usually occurs for contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow. We net these book-outs, which reduces both wholesale revenues and fuel and purchased power costs.
Some of our cost recovery mechanisms are alternative revenue programs. For alternative revenue programs that meet specified accounting criteria, we recognize revenues when the specific events permitting billing of the additional revenues have been completed.
See Notes 2 and 4 for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Allowance for Doubtful Accounts
The allowance for doubtful accounts represents our best estimate of accounts receivable and accrued unbilled revenues that will ultimately be uncollectible due to credit loss risk. The allowance includes a write-off component that is calculated by applying an estimated write-off factor to retail electric revenues. The write-off factor used to estimate uncollectible accounts is based upon consideration of historical collections experience, the current and forecasted economic environment, changes to our collection policies, and management’s best estimate of future collections success. (See Note 2.)
Property, Plant and Equipment
Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission and distribution facilities. We report utility plant at its original cost, which includes:
•material and labor;
•contractor costs;
•capitalized leases;
•construction overhead costs (where applicable); and
•allowance for funds used during construction.
Pinnacle West’s property, plant and equipment included in the December 31, 2020 and 2019 Consolidated Balance Sheets is composed of the following (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment:
|
2020
|
|
2019
|
Generation
|
$
|
9,199,012
|
|
|
$
|
8,916,872
|
|
Transmission
|
3,290,477
|
|
|
3,095,907
|
|
Distribution
|
7,107,007
|
|
|
6,690,697
|
|
General plant
|
1,241,389
|
|
|
1,132,816
|
|
Plant in service and held for future use
|
20,837,885
|
|
|
19,836,292
|
|
Accumulated depreciation and amortization
|
(7,110,310)
|
|
|
(6,637,857)
|
|
Net
|
13,727,575
|
|
|
13,198,435
|
|
Construction work in progress
|
937,384
|
|
|
808,133
|
|
Palo Verde sale leaseback, net of accumulated depreciation
|
98,036
|
|
|
101,906
|
|
Intangible assets, net of accumulated amortization
|
282,570
|
|
|
290,564
|
|
Nuclear fuel, net of accumulated amortization
|
113,645
|
|
|
123,500
|
|
Total property, plant and equipment
|
$
|
15,159,210
|
|
|
$
|
14,522,538
|
|
Property, plant and equipment balances and classes for APS are not materially different than Pinnacle West.
We expense the costs of plant outages, major maintenance and routine maintenance as incurred. We charge retired utility plant to accumulated depreciation. Liabilities associated with the retirement of tangible long-lived assets are recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense, and the capitalized cost is depreciated over the useful life of the long-lived asset. (See Note 12 for additional information.)
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
APS records a regulatory liability for the excess that has been recovered in regulated rates over the amount calculated in accordance with guidance on accounting for asset retirement obligations. APS believes it is probable it will recover in regulated rates, the costs calculated in accordance with this accounting guidance.
We record depreciation and amortization on utility plant on a straight-line basis over the remaining useful life of the related assets. The approximate remaining average useful lives of our utility property at December 31, 2020 were as follows:
•Fossil plant — 17 years;
•Nuclear plant — 20 years;
•Other generation — 20 years;
•Transmission — 38 years;
•Distribution — 34 years; and
•General plant — 7 years.
Depreciation of utility property, plant and equipment is computed on a straight-line, remaining-life basis. Depreciation expense was $553 million in 2020, $522 million in 2019, and $486 million in 2018. For the years 2018 through 2020, the depreciation rates ranged from a low of 0.18% to a high of 32.43%. The weighted-average depreciation rate was 2.84% in 2020, 2.81% in 2019, and 2.81% in 2018.
Asset Retirement Obligations
APS has asset retirement obligations for its Palo Verde nuclear facilities and certain other generation assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements APS reached with the ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term and coal ash pond closures. Some of APS’s transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that APS expects to continue. As a result, APS cannot reasonably estimate the fair value of the asset retirement obligation related to such transmission and distribution assets. Additionally, APS has aquifer protection permits for some of its generation sites that require the closure of certain facilities at those sites.
See Note 12 for further information on Asset Retirement Obligations.
Allowance for Funds Used During Construction
AFUDC represents the approximate net composite interest cost of borrowed funds and an allowed return on the equity funds used for construction of regulated utility plant. Both the debt and equity components of AFUDC are non-cash amounts within the Consolidated Statements of Income. Plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into commercial operation.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
AFUDC was calculated by using a composite rate of 6.72% for 2020, 6.98% for 2019, and 7.03% for 2018. APS compounds AFUDC semi-annually and ceases to accrue AFUDC when construction work is completed and the property is placed in service.
On June 30, 2020, the United States Federal Energy Regulatory Commission (“FERC”) issued an order granting a waiver request related to the existing Allowance for Funds Used During Construction (“AFUDC”) rate calculation beginning March 1, 2020 through February 28, 2021. The order provides a simplified approach that companies may elect to implement in order to minimize the significant distorted effect on the AFUDC formula resulting from increased short-term debt financing during the COVID-19 pandemic. APS has adopted this simplified approach to computing the AFUDC composite rate by using a simple average of the actual historical short-term debt balances for 2019, instead of current period short-term debt balances, and has left all other aspects of the AFUDC formula composite rate calculation unchanged. This change impacts the AFUDC composite rate in 2020 but does not impact prior years. Furthermore, the change in the composite rate calculation does not impact our accounting treatment for these costs. The change did not have a material impact on our financial statements.
Materials and Supplies
APS values materials, supplies and fossil fuel inventory using a weighted-average cost method. APS materials, supplies and fossil fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of market) will be recovered.
Fair Value Measurements
We apply recurring fair value measurements to cash equivalents, derivative instruments, investments held in the nuclear decommissioning trust and other special use funds. On an annual basis, we apply fair value measurements to plan assets held in our retirement and other benefits plans. Due to the short-term nature of short-term borrowings, the carrying values of these instruments approximate fair value. Fair value measurements may also be applied on a nonrecurring basis to other assets and liabilities in certain circumstances such as impairments. We also disclose fair value information for our long-term debt, which is carried at amortized cost. (See Note 7 for additional information.)
Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market which we can access for the asset or liability in an orderly transaction between willing market participants on the measurement date. Inputs to fair value may include observable and unobservable data. We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
We determine fair market value using observable inputs such as actively-quoted prices for identical instruments when available. When actively-quoted prices are not available for the identical instruments, we use other observable inputs, such as prices for similar instruments, other corroborative market information, or prices provided by other external sources. For options, long-term contracts and other contracts for which observable price data are not available, we use models and other valuation methods, which may incorporate unobservable inputs to determine fair market value.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods.
See Note 13 for additional information about fair value measurements.
Derivative Accounting
We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and in interest rates. We manage risks associated with market volatility by utilizing various physical and financial instruments including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. We also enter into derivative instruments for economic hedging purposes. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power expenses in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
We account for our derivative contracts in accordance with derivatives and hedging guidance, which requires all derivatives not qualifying for a scope exception to be measured at fair value on the balance sheet as either assets or liabilities. Transactions with counterparties that have master netting arrangements are reported net on the balance sheet. (See Note 16 for additional information about our derivative instruments.)
Loss Contingencies and Environmental Liabilities
Pinnacle West and APS are involved in certain legal and environmental matters that arise in the normal course of business. Contingent losses and environmental liabilities are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Pinnacle West and APS record a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred.
Retirement Plans and Other Postretirement Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan for the employees of Pinnacle West and its subsidiaries, in addition to a non-qualified pension plan. We also sponsor another postretirement benefit plan for the employees of Pinnacle West and its subsidiaries that provides medical and life insurance benefits to retired employees. Pension and other postretirement benefit expense are determined by actuarial valuations, based on assumptions that are evaluated annually. (See Note 8 for additional information on pension and other postretirement benefits.)
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Nuclear Fuel
APS amortizes nuclear fuel by using the unit-of-production method. The unit-of-production method is based on actual physical usage. APS divides the cost of the fuel by the estimated number of thermal units it expects to produce with that fuel. APS then multiplies that rate by the number of thermal units produced within the current period. This calculation determines the current period nuclear fuel expense.
APS also charges nuclear fuel expense for the interim storage and permanent disposal of spent nuclear fuel. The DOE is responsible for the permanent disposal of spent nuclear fuel and charged APS $0.001 per kWh of nuclear generation through May 2014, at which point the DOE reduced the fee to zero. In accordance with a settlement agreement with the DOE in August 2014 for interim storage, we now accrue a receivable and an offsetting regulatory liability through the settlement period ending December of 2022. (See Note 11 for information on spent nuclear fuel disposal costs.)
Income Taxes
Income taxes are provided using the asset and liability approach prescribed by guidance relating to accounting for income taxes and are based on currently enacted tax rates. We file our federal income tax return on a consolidated basis, and we file our state income tax returns on a consolidated or unitary basis. In accordance with our intercompany tax sharing agreement, federal and state income taxes are allocated to each first-tier subsidiary as though each first-tier subsidiary filed a separate income tax return. Any difference between that method and the consolidated (and unitary) income tax liability is attributed to the parent company. The income tax accounts reflect the tax and interest associated with management’s estimate of the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement for all known and measurable tax exposures. (See Note 5 for additional discussion.)
Cash and Cash Equivalents
We consider cash equivalents to be highly liquid investments with a remaining maturity of three months or less at acquisition.
The following table summarizes supplemental Pinnacle West cash flow information for each of the last three years (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
Cash paid (received) during the period for:
|
|
|
|
|
|
Income taxes, net of refunds
|
$
|
(3,019)
|
|
|
$
|
12,535
|
|
|
$
|
21,173
|
|
Interest, net of amounts capitalized
|
216,951
|
|
|
218,664
|
|
|
208,479
|
|
Significant non-cash investing and financing activities:
|
|
|
|
|
|
Accrued capital expenditures
|
$
|
113,502
|
|
|
$
|
141,297
|
|
|
$
|
132,620
|
|
Dividends declared but not paid
|
93,531
|
|
|
87,982
|
|
|
82,675
|
|
|
|
|
|
|
|
Sale of 4CA 7% interest in Four Corners
|
—
|
|
|
—
|
|
|
68,907
|
|
|
|
|
|
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes supplemental APS cash flow information for each of the last three years (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
Cash paid (received) during the period for:
|
|
|
|
|
|
Income taxes, net of refunds
|
$
|
41,176
|
|
|
$
|
(15,042)
|
|
|
$
|
77,942
|
|
Interest, net of amounts capitalized
|
206,328
|
|
|
204,261
|
|
|
196,419
|
|
Significant non-cash investing and financing activities:
|
|
|
|
|
|
Accrued capital expenditures
|
$
|
113,502
|
|
|
$
|
141,297
|
|
|
$
|
132,620
|
|
Dividends declared but not paid
|
93,500
|
|
|
88,000
|
|
|
82,700
|
|
|
|
|
|
|
|
Intangible Assets
We have no goodwill recorded and have separately disclosed other intangible assets, primarily APS’s software, on Pinnacle West’s Consolidated Balance Sheets. The intangible assets are amortized over their finite useful lives. Amortization expense was $70 million in 2020, $66 million in 2019, and $68 million in 2018. Estimated amortization expense on existing intangible assets over the next five years is $68 million in 2021, $56 million in 2022, $48 million in 2023, $33 million in 2024, and $25 million in 2025. At December 31, 2020, the weighted-average remaining amortization period for intangible assets was 7 years.
Investments
El Dorado holds investments in both debt and equity securities. Investments in debt securities are generally accounted for as held-to-maturity and investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence).
Bright Canyon holds investments in equity securities. Investments in equity securities are accounted for using either the equity method (if significant influence) or the measurement alternative for investments without readily determinable fair values (if less than 20% ownership and no significant influence).
Our investments in the nuclear decommissioning trusts, coal reclamation escrow accounts and active union employee medical account, are accounted for in accordance with guidance on accounting for investments in debt and equity securities. (See Notes 13 and 19 for more information on these investments.)
Leases
We determine if an agreement is a lease at contract inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. To control the use of an identified asset an entity must have both a right to obtain substantially all of the benefits from the use of the asset and the right to direct the use of the asset. If we determine an agreement is a lease, and we are the lessee, we recognize a right-of-use lease asset and a lease liability at the lease commencement date. Lease liabilities are recognized based on the present value
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of the fixed lease payments over the lease term. To present value lease liabilities we use the implicit rate in the lease if the information is readily available, otherwise we use our incremental borrowing rate determined at lease commencement. Our incremental borrowing rate is based on the rate of interest we would have to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment. When measuring right-of-use assets and lease liabilities we exclude variable lease payments, other than those that depend on an index or rate or are in-substance fixed payments. For short-term leases with terms of 12 months or less, we do not recognize a right-of-use lease asset or lease liability. We recognize operating lease expense using a straight-line pattern over the periods of use.
APS enters into purchased power contracts that may contain leases. This occurs when a purchased power agreement designates a specific power plant, APS obtains substantially all of the economic benefits from the use of the plant and has the right to direct the use of the plant. Lease costs relating to purchased power lease contracts are reported in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4). We also may enter into lease agreements related to vehicles, office space, land, and other equipment. (See Note 9 for information on our lease agreements.)
Business Segments
Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution. All other segment activities are insignificant.
Preferred Stock
At December 31, 2020, Pinnacle West had 10 million shares of serial preferred stock authorized with no par value, none of which was outstanding, and APS had 15,535,000 shares of various types of preferred stock authorized with $25, $50 and $100 par values, none of which was outstanding.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2. Revenue
Sources of Revenue
The following table provides detail of Pinnacle West’s consolidated revenue disaggregated by revenue sources (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
Retail Electric Service
|
|
|
|
|
|
Residential
|
$
|
1,929,178
|
|
(a)
|
$
|
1,761,122
|
|
|
$
|
1,867,370
|
|
Non-Residential
|
1,486,098
|
|
|
1,509,514
|
|
|
1,628,891
|
|
Wholesale Energy Sales
|
93,345
|
|
|
121,805
|
|
|
109,198
|
|
Transmission Services for Others
|
65,859
|
|
|
62,460
|
|
|
60,261
|
|
Other Sources
|
12,502
|
|
|
16,308
|
|
|
25,527
|
|
Total Operating Revenues
|
$
|
3,586,982
|
|
|
$
|
3,471,209
|
|
|
$
|
3,691,247
|
|
(a) Residential revenues for the year ended December 31, 2020 reflect a $24 million reduction related to the Arizona Attorney General matter. (See Note 11).
Retail Electric Revenue. Pinnacle West’s retail electric revenue is generated by our wholly owned regulated subsidiary APS’s sale of electricity to our regulated customers within the authorized service territory at tariff rates approved by the ACC and based on customer usage. Revenues related to the sale of electricity are generally recognized when service is rendered or electricity is delivered to customers. The billing of electricity sales to individual customers is based on the reading of their meters. We obtain customers’ meter data on a systematic basis throughout the month, and generally bill customers within a month from when service was provided. Customers are generally required to pay for services within 15 days of when the services are billed. See “Allowance for Doubtful Accounts” discussion below for additional details regarding payment terms.
Wholesale Energy Sales and Transmission Services for Others. Revenues from wholesale energy sales and transmission services for others represent energy and transmission sales to wholesale customers. These activities primarily consist of managing fuel and purchased power risks in connection with the cost of serving our retail customers’ energy requirements. We may also sell into the wholesale markets generation that is not needed for APS’s retail load. Our wholesale activities and tariff rates are regulated by FERC.
Revenue Activities
Our revenues primarily consist of activities that are classified as revenues from contracts with customers. We derive our revenues from contracts with customers primarily from sales of electricity to our regulated retail customers. Revenues from contracts with customers also include wholesale and transmission activities. Our revenues from contracts with customers for the year ended December 31, 2020, 2019 and 2018 were $3,533 million, $3,415 million and $3,644 million, respectively.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We have certain revenues that do not meet the specific accounting criteria to be classified as revenues from contracts with customers. For the year ended December 31, 2020, 2019 and 2018, our revenues that do not qualify as revenue from contracts with customers were $54 million, $56 million and $47 million, respectively. This relates primarily to certain regulatory cost recovery mechanisms that are considered alternative revenue programs. We recognize revenue associated with alternative revenue programs when specific events permitting recognition are completed. Certain amounts associated with alternative revenue programs will subsequently be billed to customers; however, we do not reclassify billed amounts into revenue from contracts with customers. (See Note 4 for a discussion of our regulatory cost recovery mechanisms.)
Contract Assets and Liabilities from Contracts with Customers
There were no material contract assets, contract liabilities, or deferred contract costs recorded on the Consolidated Balance Sheets as of December 31, 2020 and 2019.
Allowance for Doubtful Accounts
On March 13, 2020, due to the COVID-19 pandemic we voluntarily suspended disconnections of customers for nonpayment. The suspension of customer disconnections was extended from March 13, 2020 through December 31, 2020. Our disconnection policies are also impacted by the Summer Disconnection Moratorium. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and certain customers with past due balances were placed on eight-month payment arrangements. These circumstances and the on-going COVID-19 pandemic have impacted our allowance for doubtful accounts including our write-off factor. We continue to monitor the impacts of COVID-19, our disconnection policies, payment arrangements, among other considerations impacting our estimated write-off factor and allowance for doubtful accounts. (See Note 1 for our accounting policies on allowance for doubtful accounts. See Note 4 for additional discussion on the COVID-19 pandemic and the Summer Disconnection Moratorium.)
The following table provides a rollforward of Pinnacle West’s allowance for doubtful accounts all of which primarily relates to APS (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2020
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
Allowance for doubtful accounts, balance at beginning of period
|
|
$
|
8,171
|
|
|
$
|
4,069
|
|
|
$
|
2,513
|
|
Bad debt expense
|
|
20,633
|
|
|
11,819
|
|
|
10,870
|
|
Actual write-offs
|
|
(9,022)
|
|
|
(7,717)
|
|
|
(9,314)
|
|
Allowance for doubtful accounts, balance at end of period
|
|
$
|
19,782
|
|
|
$
|
8,171
|
|
|
$
|
4,069
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3. New Accounting Standards
Standards Adopted in 2020
ASU 2016-13, Financial Instruments: Measurement of Credit Losses
In June 2016, a new accounting standard was issued that amends the measurement of credit losses on certain financial instruments. The new standard requires entities to use a current expected credit loss model to measure impairment of certain investments in debt securities, trade accounts receivables and other financial instruments. Since the issuance of the new standard, various guidance has been issued that amends the new standard, including clarifications of certain aspects of the standard and targeted transition relief, among other changes. The new standard and related amendments were effective for us on January 1, 2020, and must be adopted using a modified retrospective approach for certain aspects of the standard, and a prospective approach for other aspects of the standard. We adopted the standard on January 1, 2020 using primarily the modified retrospective approach. While the adoption of this guidance changed our process and methodology for determining credit losses and resulted in additional disclosures, these changes did not have a material impact on our financial statements. (See Note 2 for allowance for doubtful accounts related credit loss disclosures.)
ASU 2018-14, Retirement Benefits: Changes to the Disclosure Requirements for Defined Benefit Plans
In August 2018, a new accounting standard was issued that amends certain disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendments remove disclosures that are no longer considered beneficial, clarifies specific disclosure requirements and adds new disclosure requirements relating to defined benefit plans. The new standard is effective for fiscal years ending after December 15, 2020. We adopted and implemented the standard on a retrospective basis in our financial statements for the year ended December 31, 2020. While the adoption of this guidance modified the disclosure requirements relating to defined benefit plans, these changes did not have a material impact on our financial statements. (See Note 8 for Retirement Plans and Other Postretirement Benefits disclosure.)
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
4. Regulatory Matters
COVID-19 Pandemic
Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020. In addition, APS waived all late payment fees during this suspension period. On September 14, 2020, APS extended this suspension of disconnection of customers for nonpayment and waiver of late payment fees until December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until October 15, 2021. APS has experienced and is continuing to experience an increase in bad debt expense associated with the COVID-19 pandemic. The Summer Disconnection Moratorium (see below for discussion of the Summer Disconnection Moratorium), the suspension of disconnections during the COVID-19 pandemic and the increased bad debt expense associated with both events resulted in a negative impact to its 2020 operating results of approximately $23 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. Additionally, due to COVID-19, APS delayed the reset of the EIS adjustor and suspended the discontinuation of TEAM Phase II to the first billing cycle in May 2020 rather than April 2020 and also delayed the reset of the PSA to the first billing cycle of April 2021 rather than February 2021 (see below for discussion of EIS, TEAM Phase II and PSA).
On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. As of December 31, 2020, APS had refunded approximately $43 million to customers. The additional $7 million over the approved amount of $36 million was the result of the kWh credit being based on historic consumption, which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings (see below for discussion of the DSM Adjustor Charge).
APS has spent more than $15 million to assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic, with $12.4 million of these dollars directly committed to bill assistance programs (the “COVID Customer Support Fund”). The COVID Customer Support Fund was comprised of a series of voluntary commitments of funds that are not recoverable through rates throughout 2020 of approximately $8.8 million. An additional $3.6 million in bill credits for limited income customers was ordered by the ACC in December 2020 of which 50%, up to a maximum of $2.5 million, was committed to be funds that are not recoverable through rates with the remaining being deferred for potential future recovery in rates. Included in the COVID Customer Support Fund were programs that assisted customers that had a delinquency of two or more months with a one-time credit of $100, an expanded credit of $300 for limited income customers, programs to assist extra small and small non-residential customers with a one-time credit of $1,000, and other targeted programs allocated to assist with other COVID-19 needs in support of utility bill assistance. The December 2020 ACC order further assisted delinquent limited income customers with an additional bill credit of up to $250 or their delinquent balance, whichever was less. As of December 31, 2020, APS had distributed all funds for all COVID Customer Support Fund programs combined. Beyond the COVID Customer Support Fund, APS
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
has also provided $2.7 million to assist local non-profits and community organizations working to mitigate the impacts of the COVID-19 pandemic.
2019 Retail Rate Case Filing with the Arizona Corporation Commission
In accordance with the requirements of the 2019 rate review order described below, APS filed an application with the ACC on October 31, 2019 seeking an annual increase in retail base rates of $69 million. This amount includes recovery of the deferral and rate base effects of the Four Corners selective catalytic reduction (“SCR”) project that is currently the subject of a separate proceeding (see “SCR Cost Recovery” below). It also reflects a net credit to base rates of approximately $115 million primarily due to the prospective inclusion of rate refunds currently provided through the TEAM. The proposed total annual revenue increase in APS’s application is $184 million. The average annual customer bill impact of APS’s request is an increase of 5.6% (the average annual bill impact for a typical APS residential customer is 5.4%).
The principal provisions of APS’s application were:
•a test year comprised of twelve months ended June 30, 2019, adjusted as described below;
•an original cost rate base of $8.87 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits;
•the following proposed capital structure and costs of capital:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Structure
|
|
Cost of Capital
|
|
Long-term debt
|
|
45.3
|
|
%
|
4.10
|
|
%
|
Common stock equity
|
|
54.7
|
|
%
|
10.15
|
|
%
|
Weighted-average cost of capital
|
|
|
|
7.41
|
|
%
|
•a 1% return on the increment of fair value rate base above APS’s original cost rate base, as provided for by Arizona law;
•a rate of $0.030168 per kWh for the portion of APS’s retail base rates attributable to fuel and purchased power costs (“Base Fuel Rate”);
•authorization to defer until APS’s next general rate case the increase or decrease in its Arizona property taxes attributable to tax rate changes after the date the rate application is adjudicated;
•a number of proposed rate and program changes for residential customers, including:
▪a super off-peak period during the winter months for APS’s time-of-use with demand rates;
▪additional $1.25 million in funding for APS’s limited-income crisis bill program; and
▪a flat bill/subscription rate pilot program;
•proposed rate design changes for commercial customers, including an experimental program designed to provide access to market pricing for up to 200 MW of medium and large commercial customers;
•recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project (see discussion below of the 2017 Settlement Agreement); and
•continued recovery of the remaining investment and other costs related to the retirement and closure of the Navajo Plant (see “Navajo Plant” below).
APS requested that the increase become effective December 1, 2020.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On October 2, 2020, the ACC Staff, the Residential Utility Consumer Office (“RUCO”) and other intervenors filed their initial written testimony with the ACC in this rate case. The ACC Staff recommends, among other things, a (i) $89.7 million revenue increase, (ii) average annual customer bill increase of 2.7%, (iii) return on equity of 9.4%, (iv) a 0.3% or, as an alternative, a 0% return on the increment of fair value rate base greater than original cost, (v) recovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project and (vi) recovery of the rate base effects of the construction and ongoing consideration of the deferral of the Ocotillo modernization project. RUCO recommends, among other things, a (i) $20.8 million revenue decrease, (ii) average annual customer bill decrease of 0.63%, (iii) return on equity of 8.74%, (iv) a 0% return on the increment of fair value rate base, (v) nonrecovery of the deferral and rate base effects of the construction and operating costs of the Four Corners SCR project pending further consideration, and (vi) recovery of the deferral and rate base effects of the construction and operating costs of the Ocotillo modernization project.
The filed ACC Staff and intervenor testimony include additional recommendations, some of which materially differ from APS’s filed application. On November 6, 2020, APS filed its rebuttal testimony and the principal provisions which differ from its initial application include, among other things, a (i) $169 million revenue increase, (ii) average annual bill increase of 5.14%, (iii) return on equity of 10%, (iv) return on the increment of fair value rate base of 0.8%, (v) new cost recovery adjustor mechanism, the Advanced Energy Mechanism (“AEM”), to enable more timely recovery of clean investments as APS pursues its clean energy commitment, (vi) recognition that securitization is a potentially useful financing tool to recover the remaining book value of retiring assets and effectuate a transition to a cleaner energy future that APS intends to pursue, provided legislative hurdles are addressed, and (vii) a Coal Community Transition (“CCT”) plan related to the closure or future closure of coal-fired generation facilities, of which $25 million would be funds that are not recoverable through rates with a proposal that the remainder be funded by customers over 10 years.
The CCT plan includes the following proposed components: (i) $100 million that will be paid over 10 years to the Navajo Nation for a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $1.25 million that will be paid over five years to the Navajo Nation to fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 million to facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 million per year in transmission revenue sharing to be paid to the Navajo Nation beginning after the closure of the Four Corners Power Plant through 2038, which would be funds not recoverable through rates, (v) $12 million that will be paid over five years to the Navajo County Communities surrounding Cholla Power Plant, which would primarily be funded by customers, and (vi) $3.7 million that will be paid over five years to the Hopi Tribe related to APS’s ownership interests in the Navajo Generating Station, which would primarily be funded by customers. The commitment of funds that would not be recoverable through rates of $25 million were recognized in our December 31, 2020 financials.
The hearing began January 14, 2021. Unfavorable ACC Staff and intervenor positions and recommendations could have a material impact on APS’s financial statements if ultimately adopted by the ACC. APS cannot predict the outcome of this proceeding.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2016 Retail Rate Case Filing with the Arizona Corporation Commission
On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates. On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed a settlement agreement (the “2017 Settlement Agreement”) and filed it with the ACC. The 2017 Settlement Agreement provides for a net retail base rate increase of $94.6 million, excluding the transfer of adjustor balances, consisting of: (1) a non-fuel, non-depreciation, base rate increase of $87.2 million per year; (2) a base rate decrease of $53.6 million attributable to reduced fuel and purchased power costs; and (3) a base rate increase of $61.0 million due to changes in depreciation schedules. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as an increase of 4.54%).
Other key provisions of the agreement include the following:
•an authorized return on common equity of 10.0%;
•a capital structure comprised of 44.2% debt and 55.8% common equity;
•a cost deferral order for potential future recovery in APS’s next general retail rate case for the construction and operating costs APS incurs for its Ocotillo modernization project;
•a cost deferral and procedure to allow APS to request rate adjustments prior to its next general retail rate case related to its share of the construction costs associated with installing SCR equipment at Four Corners;
•a deferral for future recovery (or credit to customers) of the Arizona property tax expense above or below a specified test year level caused by changes to the applicable Arizona property tax rate;
•an expansion of the PSA to include certain environmental chemical costs and third-party energy storage costs;
•a new AZ Sun II program (now known as APS Solar Communities) for utility-owned solar distributed generation (“DG”) with the purpose of expanding access to rooftop solar for low and moderate income Arizonans, recoverable through the RES, to be no less than $10 million per year in capital costs, and not more than $15 million per year in capital costs;
•an increase to the per kWh cap for the environmental improvement surcharge from $0.00016 to $0.00050 and the addition of a balancing account;
•rate design changes, including:
▪a change in the on-peak time of use period from noon-7 p.m. to 3 p.m.-8 p.m. Monday through Friday, excluding holidays;
▪non-grandfathered DG customers would be required to select a rate option that has time of use rates and either a new grid access charge or demand component;
▪a Resource Comparison Proxy (“RCP”) for exported energy of 12.9 cents per kWh in year one; and
•an agreement by APS not to pursue any new self-build generation (with certain exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units), unless expressly authorized by the ACC.
Through a separate agreement, APS, industry representatives, and solar advocates committed to stand by the 2017 Settlement Agreement and refrain from seeking to undermine it through ballot initiatives, legislation or advocacy at the ACC.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications. On August 18, 2017, the ACC issued a final written Opinion and Order reflecting its decision in APS’s general retail rate case (the “2017 Rate Case Decision”), which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017.
On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the ACC Staff to be a complaint filed pursuant to Arizona Revised Statute §40-246 (the “Complaint”). The Complaint was later amended alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The ACC held a hearing on this matter, and the Administrative Law Judge issued a Recommended Opinion and Order recommending that the Complaint be dismissed. On July 3, 2019, the Administrative Law Judge issued an amendment to the Recommended Opinion and Order that incorporated the requirements of the rate review of the 2017 Rate Case Decision (see below discussion regarding the rate review). On July 10, 2019, the ACC adopted the Administrative Law Judge’s amended Recommended Opinion and Order along with several ACC Commissioner amendments and an amendment incorporating the results of the rate review and resolved the Complaint.
See “Rate Plan Comparison Tool and Investigation” below for information regarding a review and investigation pertaining to the rate plan comparison tool offered to APS customers and other related issues.
ACC Review of APS 2017 Rate Case Decision
On December 24, 2018, certain ACC Commissioners filed a letter stating that because the ACC had received a substantial number of complaints that the rate increase authorized by the 2017 Rate Case Decision was much more than anticipated, they believe there is a possibility that APS is earning more than was authorized by the 2017 Rate Case Decision. Accordingly, the ACC Commissioners requested the ACC Staff to perform a rate review of APS using calendar year 2018 as a test year. The ACC Commissioners also asked the ACC Staff to evaluate APS’s efforts to educate its customers regarding the new rates approved in the 2017 Rate Case Decision.
On June 4, 2019, the ACC Staff filed a proposed order regarding the rate review of the 2017 Rate Case Decision. On June 11, 2019, the ACC Commissioners approved the proposed ACC Staff order with amendments. The key provisions of the amended order include the following:
•APS must file a rate case no later than October 31, 2019, using a June 30, 2019 test-year;
•until the conclusion of the rate case being filed no later than October 31, 2019, APS must provide information on customer bills that shows how much a customer would pay on their most economical rate given their actual usage during each month;
•APS customers can switch rate plans during an open enrollment period of six months;
•APS must identify customers whose bills have increased by more than 9% and that are not on the most economical rate and provide such customers with targeted education materials and an opportunity to switch rate plans;
•APS must provide grandfathered net metering customers on legacy demand rates an opportunity to switch to another legacy rate to enable such customers to fully benefit from legacy net metering rates;
•APS must fund and implement a supplemental customer education and outreach program to be developed with and administered by ACC Staff and a third-party consultant; and
•APS must fund and organize, along with the third-party consultant, a stakeholder group to suggest better ways to communicate the impact of changes to adjustor cost recovery mechanisms (see
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
below for discussion on cost recovery mechanisms), including more effective ways to educate customers on rate plans and to reduce energy usage.
APS filed its rate case on October 31, 2019 (see “2019 Retail Rate Case Filing with the Arizona Corporation Commission” above for more information). APS does not believe that the implementation of the other key provisions of the amended order regarding the rate review will have a material impact on its financial position, results of operations or cash flows.
On May 19, 2020, the ACC Staff filed a third-party consultant’s report which evaluated the effectiveness of APS’s customer outreach and education program related to the 2017 Rate Case Decision. On May 29, 2020, the Chairman of the ACC filed a letter with the ACC in response to this report and is alleging that APS is out of compliance with the 2017 Rate Case Decision and is over-earning. The Chairman proposed that the current rates should be classified as interim rates and customers held harmless if APS’s activities have caused the rates set in the 2017 Rate Case Decision to not be just and reasonable. Also, on May 29, 2020, a second commissioner filed a letter with the ACC agreeing with the Chairman’s assertions and further asserting that the 2017 Rate Case Decision should be re-opened. On June 18, 2020, at an ACC Open Meeting, the matters raised in these letters were discussed. The ACC did not vote to move forward with any adjustments to APS’s current rates. APS is monitoring this matter, but believes that the proposals are not legal and further that APS has not over-earned. The ACC voted to administratively close this docket on November 4, 2020.
Cost Recovery Mechanisms
APS has received regulatory decisions that allow for more timely recovery of certain costs outside of a general retail rate case through the following recovery mechanisms.
Renewable Energy Standard. In 2006, the ACC approved the RES. Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects. Each year, APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget. In 2015, the ACC revised the RES rules to allow the ACC to consider all available information, including the number of rooftop solar arrays in a utility’s service territory, to determine compliance with the RES.
On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a 3-year program authorizing APS to spend $10 million to $15 million in capital costs each year to install utility-owned DG systems for low to moderate income residential homes, non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $89.9 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. On October 29, 2019, the ACC approved the 2019 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2019 implementation year.
On July 1, 2019, APS filed its 2020 RES Implementation Plan and proposed a budget of approximately $86.3 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2020 contained in the RES rules. On September 23, 2020, the ACC approved the 2020 RES Implementation Plan including a waiver of the residential distributed energy requirements for the 2020 implementation year. In addition, the ACC approved the implementation of a new pilot program that incentivizes Arizona households to install at-home battery systems. Recovery of the costs associated with the pilot will be addressed in the 2021 DSM Plan.
On July 1, 2020, APS filed its 2021 RES Implementation Plan and proposed a budget of approximately $84.7 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2021 contained in the RES rules. In the 2021 RES Implementation Plan, APS requests $4.5 million to meet revenue requirements associated with the APS Solar Communities program to complete installations delayed as a result of the COVID-19 pandemic in 2020. The ACC has not yet ruled on the 2021 RES Implementation Plan.
On July 15, 2020, ACC Staff issued final draft rules which, if approved, would require APS to meet certain clean energy standards, obtain approval for its action plan included in its IRP, and seek cost recovery in a rate process. APS cannot predict the outcome of this matter. See “Energy Modernization Plan” below for more information.
Demand Side Management Adjustor Charge. The ACC EES requires APS to submit a Demand Side Management Implementation Plan (“DSM Plan”) annually for review by and approval of the ACC. Verified energy savings from APS’s resource savings projects can be counted toward compliance with the Electric Energy Efficiency Standards; however, APS is not allowed to count savings from systems savings projects toward determination of the achievement of performance incentives, nor may APS include savings from these system savings projects in the calculation of its LFCR mechanism (see below for discussion of the LFCR).
On September 1, 2017, APS filed its 2018 DSM Plan, which proposed modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan sought a requested budget of $52.6 million and requested a waiver of the Electric Energy Efficiency Standard for 2018. On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million.
On December 31, 2018, APS filed its 2019 DSM Plan, which requested a budget of $34.1 million and focused on DSM strategies to better meet system and customer needs, such as peak demand reduction, load shifting, storage and electrification strategies.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On December 31, 2019, APS filed its 2020 DSM Plan, which requested a budget of $51.9 million and continued APS’s focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The 2020 DSM Plan addressed all components of the pending 2018 and 2019 DSM plans, which enabled the ACC to review the 2020 DSM Plan only. On May 15, 2020, APS filed an amended 2020 DSM Plan to provide assistance to customers experiencing economic impacts of the COVID-19 pandemic. The amended 2020 DSM Plan requested the same budget amount of $51.9 million. On September 23, 2020, the ACC approved the amended 2020 DSM Plan.
On April 17, 2020, APS filed an application with the ACC requesting a COVID-19 emergency relief package to provide additional assistance to its customers. On May 5, 2020, the ACC approved APS returning $36 million that had been collected through the DSM Adjustor Charge, but not allocated for current DSM programs, directly to customers through a bill credit in June 2020. As of December 31, 2020, APS had refunded approximately $43 million to customers. The additional $7 million over the approved amount was the result of the kWh credit being based on historic consumption which was different than actual consumption in the refund period. This difference was recorded to the DSM balancing account and will be addressed in subsequent DSM filings. See “COVID-19 Pandemic” above for more information.
On December 31, 2020, APS filed its 2021 DSM Plan, which requested a budget of $63.7 million and continues APS’s focus on DSM strategies, such as peak demand reduction, load shifting, storage and electrification strategies, as well as enhanced assistance to customers impacted economically by COVID-19. The ACC has not yet ruled on the APS 2021 DSM Plan.
Power Supply Adjustor Mechanism and Balance. The PSA provides for the adjustment of retail rates to reflect variations primarily in retail fuel and purchased power costs. The PSA is subject to specified parameters and procedures, including the following:
•APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the Base Fuel Rate;
•an adjustment to the PSA rate is made annually each February 1 (unless otherwise approved by the ACC) and goes into effect automatically unless suspended by the ACC;
•the PSA uses a forward-looking estimate of fuel and purchased power costs to set the annual PSA rate, which is reconciled to actual costs experienced for each PSA Year (February 1 through January 31) (see the following bullet point);
•the PSA rate includes (a) a “Forward Component,” under which APS recovers or refunds differences between expected fuel and purchased power costs for the upcoming calendar year and those embedded in the Base Fuel Rate; (b) a “Historical Component,” under which differences between actual fuel and purchased power costs and those recovered or refunded through the combination of the Base Fuel Rate and the Forward Component are recovered during the next PSA Year; and (c) a “Transition Component,” under which APS may seek mid-year PSA changes due to large variances between actual fuel and purchased power costs and the combination of the Base Fuel Rate and the Forward Component; and
•the PSA rate may not be increased or decreased more than $0.004 per kWh in a year without permission of the ACC.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2020 and 2019 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended
December 31,
|
|
2020
|
|
2019
|
Beginning balance
|
$
|
70,137
|
|
|
$
|
37,164
|
|
Deferred fuel and purchased power costs — current period
|
93,651
|
|
|
82,481
|
|
Amounts refunded/(charged) to customers
|
12,047
|
|
|
(49,508)
|
|
Ending balance
|
$
|
175,835
|
|
|
$
|
70,137
|
|
The PSA rate for the PSA year beginning February 1, 2019 was $0.001658 per kWh, as compared to the $0.004555 per kWh for the prior year. This rate was comprised of a forward component of $0.000536 per kWh and a historical component of $0.001122 per kWh. This represented a $0.002897 per kWh decrease compared to 2018. These rates went into effect as filed on February 1, 2019.
On November 27, 2019, APS filed its PSA rate for the PSA year beginning February 1, 2020. That rate was $(0.000456) per kWh and consisted of a forward component of $(0.002086) per kWh and a historical component of $0.001630 per kWh. The 2020 PSA rate is a $0.002115 per kWh decrease compared to the 2019 PSA year. These rates went into effect as filed on February 1, 2020.
On November 30, 2020, APS filed its PSA rate for the PSA year beginning February 1, 2021. That rate was $0.003544 per kWh and consisted of a forward component of $0.003434 per kWh and a historical component of $0.000110 per kWh. The 2021 PSA rate is a $0.004 per kWh increase compared to the 2020 PSA year. These rates were to be effective on February 1, 2021 but APS delayed the effectiveness of these rates until the first billing cycle of April 2021.
On March 15, 2019, APS filed an application with the ACC requesting approval to recover the costs related to two energy storage power purchase tolling agreements through the PSA. On December 29, 2020, the ACC Staff filed its report and recommended the storage costs be included in the PSA once the systems are in-service. On January 12, 2021, the ACC approved this application.
Environmental Improvement Surcharge (“EIS”). The EIS permits APS to recover the capital carrying costs (rate of return, depreciation and taxes) plus incremental operations and maintenance expenses associated with environmental improvements made outside of a test year to comply with environmental standards set by federal, state, tribal, or local laws and regulations. A filing is made on or before February 1 for qualified environmental improvements made during the prior calendar year, and the new charge becomes effective April 1 unless suspended by the ACC. There is an overall cap of $0.0005 per kWh (approximately $13 million to 14 million per year). APS’s February 1, 2021 application requested an increase in the charge to $10.3 million, or $1.5 million over the charge in effect for the 2020-2021 rate effective year.
Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters. In July 2008, FERC approved a modification to APS’s Open Access Transmission Tariff to allow APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services. A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”). In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA. Under the terms of the settlement agreement entered into in 2012 regarding APS’s rate case (“2012 Settlement Agreement”), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.
The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year. Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items. The resolution of proposed adjustments can result in significant volatility in the revenues to be collected. APS reviews the proposed formula rate filing amounts with the ACC Staff. Any items or adjustments which are not agreed to by APS and the ACC Staff can remain in dispute until settled or litigated at FERC. Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charges because any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.
On March 7, 2018, APS made a filing to make modifications to its annual transmission formula to provide transmission customers the benefit of the reduced federal corporate income tax rate resulting from the Tax Act beginning in its 2018 annual transmission formula rate update filing. These modifications were approved by FERC on May 22, 2018 and reduced APS’s transmission rates compared to the rate that would have gone into effect absent these changes. On March 17, 2020, APS made a filing to make further modifications to its annual transmission formula to provide additional transparency for excess and deficient Accumulated Deferred Income Taxes resulting from the Tax Act, as well as for future local, state, and federal statutory tax rate changes. This filing is pending with FERC.
Effective June 1, 2018, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $22.7 million for the twelve-month period beginning June 1, 2018 in accordance with the FERC-approved formula. Of this amount, retail customer rates decreased by approximately $26.9 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2018.
Effective June 1, 2019, APS's annual wholesale transmission rates for all users of its transmission system increased by approximately $25.8 million for the twelve-month period beginning June 1, 2019 in accordance with the FERC-approved formula. Of this amount, retail customer rates increased by approximately $4.7 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2019.
Effective June 1, 2020, APS’s annual wholesale transmission rates for all users of its transmission system decreased by approximately $6.1 million for the twelve-month period beginning June 1, 2020 in accordance with the FERC-approved formula. Of this amount, retail customer rates decreased by approximately $10.9 million. An adjustment to APS’s retail rates to recover FERC approved transmission charges went into effect automatically on June 1, 2020.
Lost Fixed Cost Recovery Mechanism. The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to DG such as rooftop solar arrays. The fixed costs recoverable by the LFCR mechanism are currently 2.5 cents for both lost residential and non-residential kWh as set forth in the 2017 Settlement Agreement. The LFCR adjustment has a year-over-year cap of 1%
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of retail revenues. Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year. The kWhs lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs. DG sales losses are determined from the metered output from the DG units.
On February 15, 2018, APS filed its 2018 annual LFCR adjustment, requesting that effective May 1, 2018, the LFCR be adjusted to $60.7 million. On February 6, 2019, the ACC approved the 2018 annual LFCR adjustment to become effective March 1, 2019. On February 15, 2019, APS filed its 2019 annual LFCR adjustment, requesting that effective May 1, 2019, the annual LFCR recovery amount be reduced to $36.2 million (a $24.5 million decrease from previous levels). On July 10, 2019, the ACC approved APS’s 2019 LFCR adjustment as filed, effective with the next billing cycle of July 2019. On February 14, 2020, APS filed its 2020 annual LFCR adjustment, requesting that effective May 1, 2020, the annual LFCR recovery amount be reduced to $26.6 million (a $9.6 million decrease from previous levels). On April 14, 2020, the ACC approved the 2020 LFCR adjustment as filed, effective with the first billing cycle in May 2020. On February 15, 2021, APS filed its 2021 annual LFCR adjustment, requesting that effective May 1, 2021, the annual LFCR recovery amount be increased to $38.5 million (an $11.8 million increase from previous levels).
Tax Expense Adjustor Mechanism. As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. The TEAM expressly applies to APS’s retail rates with the exception of a small subset of customers taking service under specially-approved tariffs. On December 22, 2017, the Tax Act was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.
On January 8, 2018, APS filed an application with the ACC that addressed the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and reduced rates by $119.1 million annually through an equal cents per kWh credit (“TEAM Phase I”). On February 22, 2018, the ACC approved the reduction of rates through an equal cents per kWh credit. The rate reduction was effective for the first billing cycle in March 2018.
The impact of the TEAM Phase I, over time, is expected to be earnings neutral. However, on a quarterly basis, there is a difference between the timing and amount of the income tax benefit and the reduction in revenues refunded through the TEAM Phase I related to the lower federal income tax rate. The amount of the benefit of the lower federal income tax rate is based on quarterly pre-tax results, while the reduction in revenues refunded through the TEAM Phase I is based on a per kWh sales credit which follows our seasonal kWh sales pattern and is not impacted by earnings of the Company.
On August 13, 2018, APS filed a second request with the ACC that addressed the return of an additional $86.5 million in tax savings to customers related to the amortization of non-depreciation related excess deferred taxes previously collected from customers (“TEAM Phase II”). The ACC approved this request on March 13, 2019, effective the first billing cycle in April 2019 through the last billing cycle in March 2020. On March 19, 2020, due to the COVID-19 pandemic, APS delayed the discontinuation of TEAM Phase II until the first billing cycle in May 2020. Amounts credited to customers after the last billing cycle in March 2020 will be recorded as a part of the balancing account and will be addressed for recovery as part of APS’s 2019 retail rate case. Both the timing of the reduction in revenues refunded through TEAM Phase II and the offsetting income tax benefit are recognized based upon our seasonal kWh sales pattern.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On April 10, 2019, APS filed a third request with the ACC that addressed the amortization of depreciation related excess deferred taxes over a 28.5 year period consistent with IRS normalization rules (“TEAM Phase III”). On October 29, 2019, the ACC approved TEAM Phase III providing both (i) a one-time bill credit of $64 million which was credited to customers on their December 2019 bills, and (ii) a monthly bill credit effective the first billing cycle in December 2019 which will provide an additional benefit of $39.5 million to customers through December 31, 2020. On November 20, 2020, APS filed an application to continue the TEAM Phase III monthly bill credit through the earlier of December 31, 2021, or at the conclusion of APS’s 2019 pending rate case. On December 9, 2020, the ACC approved this request. Both the timing of the reduction in revenues refunded through the TEAM Phase III monthly bill credit and the offsetting income tax benefit are recognized based upon APS’s seasonal kWh sales pattern.
Net Metering
APS’s 2017 Rate Case Decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a RCP methodology, a method that is based on the most recent five-year rolling average price that APS pays for utility-scale solar projects, while a forecasted avoided cost methodology is being developed. The price established by this RCP method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS’s subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.
In addition, the ACC made the following determinations:
•customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, based on APS’s 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility;
•customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and
•once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years.
This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh was included in the 2017 Settlement Agreement and became effective on September 1, 2017.
In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018. This price reflected the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2018. APS filed its request for a third-year export energy price of 10.5 cents per kWh on May 1, 2019. This price also reflects the 10% annual reduction discussed above. The new rate rider became effective on October 1, 2019. APS filed its request for a fourth-year export energy price of 9.4 cents per kWh on May 1, 2020, with a requested effective date of September 1, 2020. This price reflects the 10% annual reduction discussed above. On
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
September 23, 2020, the ACC approved the annual reduction of the export energy price but voted to delay the effectiveness of the reduction in export prices until October 1, 2021. APS’s export energy price will remain at 10.5 cents per kWh until October 1, 2021.
On January 23, 2017, The Alliance for Solar Choice (“TASC”) sought rehearing of the ACC’s decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Arizona Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.
See “2016 Retail Rate Case Filing with the Arizona Corporation Commission” above for information regarding an ACC order in connection with the rate review of the 2017 Rate Case Decision requiring APS to provide grandfathered net metering customers on legacy demand rates with an opportunity to switch to another legacy rate to enable such customers to benefit from legacy net metering rates.
Subpoena from Former Arizona Corporation Commissioner Robert Burns
On August 25, 2016, then-Commissioner Robert Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.
On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS’s obligations to comply with the subpoenas and decline to decide APS’s motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.
On February 7, 2017, Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC Staff. As part of this docket, Burns set March 24, 2017 as a deadline for the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Burns’ suit against APS and Pinnacle West. In response to the motion to dismiss, the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
court stayed the suit and ordered Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel.
On August 4, 2017, Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the amended complaint. On February 15, 2018, the Superior Court dismissed Burns’ amended complaint. On March 6, 2018, Burns filed an objection to the proposed final order from the Superior Court and a motion to further amend his complaint. The Superior Court permitted Burns to amend his complaint to add a claim regarding his attempted investigation into whether his fellow commissioners should have been disqualified from voting on APS’s 2017 rate case. Burns filed his second amended complaint, and all defendants filed responses opposing the second amended complaint and requested that it be dismissed. Oral argument occurred in November 2018 regarding the motion to dismiss. On December 18, 2018, the trial court granted the defendants’ motions to dismiss and entered final judgment on January 18, 2019.
On February 13, 2019, Burns filed a notice of appeal. On July 12, 2019, Burns filed his opening brief in the Arizona Court of Appeals. APS filed its answering brief on October 21, 2019. The Arizona Court of Appeals originally granted the request for oral argument; however, on March 31, 2020, the court vacated the date scheduled for oral argument given the COVID-19 pandemic. The court determined that the matter could be submitted without oral argument and has taken the matter under advisement and will issue a decision without oral argument.
Burns’ position as an ACC commissioner ended on January 4, 2021. Nevertheless, Burns filed a motion with the Court of Appeals arguing that the appeal was not mooted by this fact and the court should decide the matter. Both APS and the ACC filed responses opposing the motion and asserting that the matter is moot. Pinnacle West and APS cannot predict the outcome of this matter.
Information Requests from Arizona Corporation Commissioners
On January 14, 2019, ACC Commissioner Kennedy opened a docket to investigate campaign expenditures and political participation of APS and Pinnacle West. In addition, on February 27, 2019, ACC Commissioners Burns and Dunn opened a new docket and requested documents from APS and Pinnacle West related to ACC elections and charitable contributions related to the ACC. On March 1, 2019, ACC Commissioner Kennedy issued a subpoena to APS seeking several categories of information for both Pinnacle West and APS including political contributions, lobbying expenditures, marketing and advertising expenditures, and contributions made to 501(c)(3) and 501(c)(4) entities, for the years 2013-2018. Pinnacle West and APS voluntarily responded to both sets of requests on March 29, 2019. APS also received and responded to various follow-on requests from ACC Commissioners on these matters. Pinnacle West and APS cannot predict the outcome of these matters. The Company’s CEO, Mr. Guldner, appeared at the ACC’s January 14, 2020 Open Meeting regarding ACC Commissioners’ questions about political spending. Mr. Guldner committed to the ACC that during his tenure, Pinnacle West and APS, and any of their affiliated companies, will not participate in ACC campaign elections through financial contributions or in-kind contributions.
Energy Modernization Plan
On January 30, 2018, former ACC Commissioner Tobin proposed the Energy Modernization Plan, which consisted of a series of energy policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the integrated resource plan
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(“IRP”) process. In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals. The rulemaking will consider possible modifications to existing ACC rules, such as the RES, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics.
On April 25, 2019, the ACC Staff issued an initial set of draft energy rules and held various workshops to incorporate feedback from stakeholders and ACC Commissioners from April 2019 through July 2020. At the March 11-12, 2020 workshop, the ACC Staff committed to filing a final draft of proposed rules by July 2020. On July 30, 2020, the ACC Staff issued final draft energy rules which proposed 100% of retail kWh sales from clean energy resources by the end of 2050. Nuclear is defined as a clean energy resource. The proposed rules also require 50% of retail energy served be renewable by the end of 2035. A new energy efficiency standard was not included in the proposed rules. APS would be required to obtain approval of its action plan included in its IRP and seek recovery of prudently incurred costs in a rate process. If approved by the ACC Commissioners, the rules would require utilities to file a Clean Energy Implementation Plan and Energy Efficiency Report as part of their IRP every three years beginning in 2023. In addition, the ACC Staff proposed changing the IRP planning horizon from 15 years to 10 years.
The ACC has discussed the final draft energy rules at several different meetings in 2020. On October 14, 2020, the ACC passed one amendment to ACC Staff’s final draft energy rules that will require electric utilities to obtain 35% of peak load (as measured in 2020) by 2030 from DSM resources, including traditional energy efficiency, demand response and other programs aimed at reducing energy usage, peak demand management and load shifting. This standard aligns with the proposed rules’ three-year resource planning cycle and allows recovery of costs through existing mechanisms until the ACC issues a decision in a future rate proceeding. On October 29, 2020, the ACC approved an amendment that will require electric utilities to reduce their carbon emissions over 2016-2018 levels by 50% by 2032; 75% by 2040; and 100% by 2050. The ACC also approved an amendment that will require utilities to install energy storage systems with an aggregate capacity equal to 5% of each utility’s 2020 peak demand by 2035, of which 40% must be derived from customer-owned or customer-leased distributed storage. Another approved amendment modifies the resource planning process, including requirements for the ACC to approve a utility’s load forecast and resource plan, and for a utility to perform an all-source request for information to guide its resource plan. On November 13, 2020, the ACC approved a final draft energy rules package, and additional procedural steps in the rulemaking process are required to be completed before the rules may take effect. APS cannot predict the outcome of this matter.
Integrated Resource Planning
ACC rules require utilities to develop 15-year IRPs which describe how the utility plans to serve customer load in the plan timeframe. The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged. In March of 2018, the ACC reviewed the 2017 IRPs of its jurisdictional utilities and voted to not acknowledge any of the plans. APS does not believe that this lack of acknowledgment will have a material impact on our financial position, results of operations or cash flows. Based on an ACC decision, APS was originally required to file its next IRP by April 1, 2020. On February 20, 2020, the ACC extended the deadline for all utilities to file their IRP’s from April 1, 2020 to June 26, 2020. On June 26, 2020, APS filed its final IRP. On July 15, 2020, the ACC extended the schedule for final ACC review of utility IRPs to February 2021. The ACC has taken no
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
action on APS’s IRP. APS cannot predict the outcome of this matter. See “Energy Modernization Plan” above for information regarding proposed changes to the IRP filings.
Public Utility Regulatory Policies Act
Under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), qualifying facilities are provided the right to sell energy and/or capacity to utilities and are granted relief from certain regulatory burdens. On December 17, 2019, the ACC mandated a minimum contract length of 18 years for qualifying facilities over 100 kW in Arizona, and established that the rate paid to qualifying facilities must be based on the long-term avoided cost. “Avoided cost” is generally defined as the price at which the utility could purchase or produce the same amount of power from sources other than the qualifying facility on a long-term basis. During calendar year 2020, APS entered into two 18-year power purchase agreements with qualified facilities, each for 80 MW solar facilities. These agreements are pending ACC approval.
On July 16, 2020, FERC issued a final rule revising FERC’s regulations implementing PURPA. The final rule went into effect on December 31, 2020. APS is evaluating how the revised regulations may impact its operations.
Residential Electric Utility Customer Service Disconnections
On June 13, 2019, APS voluntarily suspended electric disconnections for residential customers who had not paid their bills. On June 20, 2019, the ACC voted to enact emergency rule amendments to prevent residential electric utility customer service disconnections during the period June 1 through October 15 (“Summer Disconnection Moratorium”). During the Summer Disconnection Moratorium, APS could not charge late fees and interest on amounts that were past due from customers. Customer deposits must also be used to pay delinquent amounts before disconnection can occur and customers will have four months to pay back their deposit and any remaining delinquent amounts. In accordance with the emergency rules, APS began putting delinquent customers on a mandatory four-month payment plan beginning on October 16, 2019. Although the emergency rules expired in December 2019, the Summer Disconnection Moratorium will remain in effect through utility tariffs for 2021 and beyond until the ACC adopts permanent rules or determines otherwise.
In June 2019, the ACC began a formal regular rulemaking process to allow stakeholder input and time for consideration of permanent rule changes. The ACC further ordered that each regulated electric utility serving retail customers in Arizona update its service conditions by incorporating the emergency rule amendments, restore power to any customers who were disconnected during the month of June 2019 and credit any fees that were charged for a reconnection. The ACC Staff issued draft amendments to the customer service disconnections rules. Stakeholders submitted initial comments to the draft amendments on September 23, 2019. ACC stakeholder meetings were held in September 2019, October 2019 and January 2020 regarding the customer service disconnections rules.
Due to the COVID-19 pandemic, APS voluntarily suspended disconnections of customers for nonpayment beginning March 13, 2020. On September 14, 2020, APS extended this suspension of disconnection of customers for nonpayment until December 31, 2020. The suspension of disconnection of customers for nonpayment ended on January 1, 2021 and customers were placed automatically on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75 or greater. APS will continue to waive late payment fees until October 15, 2021. The Summer Disconnection Moratorium, the suspension of disconnections during the COVID-19 pandemic and the increased bad debt
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
expense associated with both events resulted in a negative impact to its 2020 operating results of approximately $23 million pre-tax above the impact of disconnections on its operating results for years that did not have the Summer Disconnection Moratorium or COVID-19 pandemic. See “COVID-19 Pandemic” above for more information.
Retail Electric Competition Rules
On November 17, 2018, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. An ACC special open meeting workshop was held on December 3, 2018. No substantive action was taken, but interested parties were asked to submit written comments and respond to a list of questions from ACC Staff. On July 1 and July 2, 2019, ACC Staff issued a report and initial proposed draft rules regarding possible modifications to the ACC’s retail electric competition rules. Interested parties filed comments to the ACC Staff report and a stakeholder meeting and workshop to discuss the retail electric competition rules was held on July 30, 2019. ACC Commissioners submitted additional questions regarding this matter. On February 10, 2020, two ACC Commissioners filed two sets of draft proposed retail electric competition rules. On February 12, 2020, ACC Staff issued its second report regarding possible modifications to the ACC’s retail electric competition rules. The ACC held a workshop on February 25-26, 2020 on further consideration and discussion of the retail electric competition rules. During a July 15, 2020 ACC Staff meeting, the ACC Commissioners discussed the possible development of a retail competition pilot program, but no action was taken. The ACC Commissioners are continuing to explore the retail electric competition rules. APS cannot predict whether these efforts will result in any changes and, if changes to the rules results, what impact these rules would have on APS.
Rate Plan Comparison Tool and Investigation
On November 14, 2019, APS learned that its rate plan comparison tool was not functioning as intended due to an integration error between the tool and APS’s meter data management system. APS immediately removed the tool from its website and notified the ACC. The purpose of the tool was to provide customers with a rate plan recommendation based upon historical usage data. Upon investigation, APS determined that the error may have affected rate plan recommendations to customers between February 4, 2019 and November 14, 2019. By the middle of May 2020, APS provided refunds to approximately 13,000 potentially impacted customers equal to the difference between what they paid for electricity and the amount they would have paid had they selected their most economical rate, as applicable, and a $25 payment for any inconvenience that the customer may have experienced. The refunds and payment for inconvenience being provided did not have a material impact on APS’s financial statements. APS developed a new tool for comparing customers’ rate plan options. APS had an independent third party verify that the new rate comparison tool works correctly. In February 2020, APS launched the new online rate comparison tool, which is now available for its customers. The ACC hired an outside consultant to evaluate the extent of the error and the overall effectiveness of the tool. On August 20, 2020, ACC Staff filed the outside consultant’s report on APS’s rate comparison tool. The report concluded APS’s new rate comparison tool is working as intended. The report also identified a small population of additional customers that may have been affected by the error and APS has provided refunds and the $25 inconvenience payment to approximately 3,800 additional customers. These additional refunds and payment for inconvenience did not have a material impact on APS’s financial statements. On September 28, 2020, the ACC discussed this report but did not take any action. APS cannot predict if any action will be taken by the ACC at this time.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
APS received civil investigative demands from the Office of the Arizona Attorney General, Civil Litigation Division, Consumer Protection & Advocacy Section (“Attorney General”) seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement results in APS paying $24.75 million, $24 million of which is being returned to customers as restitution. While this matter has been resolved with the Attorney General, APS cannot predict whether additional inquiries or actions may be taken by the ACC.
Four Corners SCR Cost Recovery
On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5. APS filed the SCR Adjustment request in April 2018. Consistent with the 2017 Rate Case Decision, the request was narrow in scope and addressed only costs associated with this specific environmental compliance equipment. The SCR Adjustment request provided that there would be a $67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers. Also, as provided for in the 2017 Rate Case Decision, APS requested that the adjustment become effective no later than January 1, 2019. The hearing for this matter occurred in September 2018. At the hearing, APS accepted ACC Staff’s recommendation of a lower annual revenue impact of approximately $58.5 million. The Administrative Law Judge issued a Recommended Opinion and Order finding that the costs for the SCR project were prudently incurred and recommending authorization of the $58.5 million annual revenue requirement related to the installation and operation of the SCRs. Exceptions to the Recommended Opinion and Order were filed by the parties and intervenors on December 7, 2018. The ACC has not issued a decision on this matter. APS included the costs for the SCR project in the retail rate base in its 2019 Retail Rate Case filing with the ACC. On March 18, 2020, the ACC agreed to take administrative notice to include in the pending rate case portions of the record in this prior proceeding that are relevant to the SCRs. APS cannot predict the outcome or timing of the decision on this matter. APS may be required to record a charge to its results of operations if the ACC issues an unfavorable decision (see SCR deferral in the Regulatory Assets and Liabilities table below).
Cholla
On September 11, 2014, APS announced that it would close Unit 2 of Cholla and cease burning coal at the other APS-owned units (Units 1 and 3) at the plant by the mid-2020s, if EPA approved a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS’s plan to retire Unit 2, without expressing any view on the future recoverability of APS’s remaining investment in the unit. APS closed Unit 2 on October 1, 2015. In early 2017, EPA approved a final rule incorporating APS’s compromise proposal, which took effect on April 26, 2017. In December 2019, PacifiCorp notified APS that it planned to retire Cholla Unit 4 by the end of 2020. Cholla Unit 4 was retired on December 24, 2020.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Previously, APS estimated Cholla Unit 2’s end of life to be 2033. APS has been recovering a return on and of the net book value of the unit in base rates. Pursuant to the 2017 Settlement Agreement described above, APS will be allowed continued recovery of the net book value of the unit and the unit’s decommissioning and other retirement-related costs ($57 million as of December 31, 2020), in addition to a return on its investment. In accordance with GAAP, in the third quarter of 2014, Unit 2’s remaining net book value was reclassified from property, plant and equipment to a regulatory asset. The 2017 Settlement Agreement also shortened the depreciation lives of Cholla Units 1 and 3 to 2025.
Navajo Plant
The Navajo Plant ceased operations in November 2019. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that allows for decommissioning activities to begin after the plant ceased operations.
APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($72 million as of December 31, 2020) plus a return on the net book value as well as other costs related to retirement and closure, including the Navajo coal reclamation regulatory asset ($18 million as of December 31, 2020). APS believes it will be allowed recovery of the net book value, in addition to a return on its investment. In accordance with GAAP, in the second quarter of 2017, APS’s remaining net book value of its interest in the Navajo Plant was reclassified from property, plant and equipment to a regulatory asset. If the ACC does not allow full recovery of the remaining net book value of this interest, all or a portion of the regulatory asset will be written off and APS’s net income, cash flows, and financial position will be negatively impacted.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory Assets and Liabilities
The detail of regulatory assets is as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S
|
|
|
December 31, 2020
|
|
December 31, 2019
|
|
Amortization Through
|
|
Current
|
|
Non-Current
|
|
Current
|
|
Non-Current
|
Pension
|
(a)
|
|
$
|
—
|
|
|
$
|
469,953
|
|
|
$
|
—
|
|
|
$
|
660,223
|
|
Deferred fuel and purchased power (b) (c)
|
2021
|
|
175,835
|
|
|
—
|
|
|
70,137
|
|
|
—
|
|
Income taxes — AFUDC equity
|
2050
|
|
7,169
|
|
|
158,776
|
|
|
6,800
|
|
|
154,974
|
|
Retired power plant costs
|
2033
|
|
28,181
|
|
|
114,214
|
|
|
28,182
|
|
|
142,503
|
|
Ocotillo deferral
|
N/A
|
|
—
|
|
|
95,723
|
|
|
—
|
|
|
38,144
|
|
SCR deferral
|
N/A
|
|
—
|
|
|
81,307
|
|
|
—
|
|
|
52,644
|
|
Deferred property taxes
|
2027
|
|
8,569
|
|
|
49,626
|
|
|
8,569
|
|
|
58,196
|
|
Lost fixed cost recovery (b)
|
2021
|
|
41,807
|
|
|
—
|
|
|
26,067
|
|
|
—
|
|
Deferred compensation
|
2036
|
|
—
|
|
|
36,195
|
|
|
—
|
|
|
36,464
|
|
Four Corners cost deferral
|
2024
|
|
8,077
|
|
|
24,075
|
|
|
8,077
|
|
|
32,152
|
|
Income taxes — investment tax credit basis adjustment
|
2049
|
|
1,113
|
|
|
24,291
|
|
|
1,098
|
|
|
24,981
|
|
Palo Verde VIEs (Note 18)
|
2046
|
|
—
|
|
|
21,255
|
|
|
—
|
|
|
20,635
|
|
Coal reclamation
|
2026
|
|
1,068
|
|
|
16,999
|
|
|
1,546
|
|
|
17,688
|
|
Deferred fuel and purchased power — mark-to-market (Note 16)
|
2024
|
|
3,341
|
|
|
9,244
|
|
|
36,887
|
|
|
33,185
|
|
Loss on reacquired debt
|
2038
|
|
1,689
|
|
|
10,877
|
|
|
1,637
|
|
|
12,031
|
|
Mead-Phoenix transmission line — contributions in aid of construction
|
2050
|
|
332
|
|
|
9,380
|
|
|
332
|
|
|
9,712
|
|
Demand side management (b)
|
2022
|
|
—
|
|
|
7,268
|
|
|
—
|
|
|
—
|
|
Tax expense adjustor mechanism (b)
|
2021
|
|
6,226
|
|
|
—
|
|
|
1,612
|
|
|
—
|
|
Tax expense of Medicare subsidy
|
2024
|
|
1,235
|
|
|
3,704
|
|
|
1,235
|
|
|
4,940
|
|
PSA interest
|
2021
|
|
4,355
|
|
|
—
|
|
|
1,917
|
|
|
—
|
|
TCA balancing account (b)
|
2021
|
|
—
|
|
|
—
|
|
|
6,324
|
|
|
2,885
|
|
Other
|
Various
|
|
2,716
|
|
|
1,100
|
|
|
2,787
|
|
|
2,716
|
|
Total regulatory assets (d)
|
|
|
$
|
291,713
|
|
|
$
|
1,133,987
|
|
|
$
|
203,207
|
|
|
$
|
1,304,073
|
|
(a)This asset represents the future recovery of pension benefit obligations through retail rates. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future revenues. (See Note 8 for further discussion.)
(b)See “Cost Recovery Mechanisms” discussion above.
(c)Subject to a carrying charge.
(d)There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base. FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The detail of regulatory liabilities is as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
|
Amortization Through
|
|
Current
|
|
Non-Current
|
|
Current
|
|
Non-Current
|
Excess deferred income taxes - ACC — Tax Cuts and Jobs Act (a)
|
2046
|
|
$
|
41,330
|
|
|
$
|
1,012,583
|
|
|
$
|
59,918
|
|
|
$
|
1,054,053
|
|
Excess deferred income taxes - FERC — Tax Cuts and Jobs Act (a)
|
2058
|
|
7,240
|
|
|
229,147
|
|
|
6,302
|
|
|
237,357
|
|
Asset retirement obligations
|
2057
|
|
—
|
|
|
506,049
|
|
|
—
|
|
|
418,423
|
|
Other postretirement benefits
|
(d)
|
|
37,705
|
|
|
349,588
|
|
|
37,575
|
|
|
139,634
|
|
Removal costs
|
(c)
|
|
52,844
|
|
|
103,008
|
|
|
47,356
|
|
|
136,072
|
|
Income taxes — change in rates
|
2050
|
|
2,839
|
|
|
66,553
|
|
|
2,797
|
|
|
68,265
|
|
Four Corners coal reclamation
|
2038
|
|
5,460
|
|
|
49,435
|
|
|
1,059
|
|
|
51,704
|
|
Spent nuclear fuel
|
2027
|
|
6,768
|
|
|
44,221
|
|
|
6,676
|
|
|
51,019
|
|
Income taxes — deferred investment tax credit
|
2049
|
|
2,231
|
|
|
48,648
|
|
|
2,202
|
|
|
50,034
|
|
Renewable energy standard (b)
|
2021
|
|
39,442
|
|
|
103
|
|
|
39,287
|
|
|
10,300
|
|
Sundance maintenance
|
2031
|
|
2,989
|
|
|
11,508
|
|
|
5,698
|
|
|
11,319
|
|
Property tax deferral
|
N/A
|
|
—
|
|
|
13,856
|
|
|
—
|
|
|
7,046
|
|
Demand side management (b)
|
2021
|
|
10,819
|
|
|
—
|
|
|
15,024
|
|
|
24,146
|
|
FERC transmission true up
|
2022
|
|
6,598
|
|
|
3,008
|
|
|
1,045
|
|
|
2,004
|
|
TCA balancing account (b)
|
2022
|
|
2,902
|
|
|
4,672
|
|
|
—
|
|
|
—
|
|
Tax expense adjustor mechanism (b) (e)
|
2021
|
|
7,089
|
|
|
—
|
|
|
7,018
|
|
|
—
|
|
Active union medical trust
|
N/A
|
|
—
|
|
|
6,057
|
|
|
—
|
|
|
2,041
|
|
Deferred gains on utility property
|
2022
|
|
2,423
|
|
|
1,544
|
|
|
2,423
|
|
|
4,163
|
|
Other
|
Various
|
|
409
|
|
|
189
|
|
|
532
|
|
|
255
|
|
Total regulatory liabilities
|
|
|
$
|
229,088
|
|
|
$
|
2,450,169
|
|
|
$
|
234,912
|
|
|
$
|
2,267,835
|
|
(a)For purposes of presentation on the Statement of Cash Flows, amortization of the regulatory liabilities for excess deferred income taxes are reflected as “Deferred income taxes” under Cash Flows From Operating Activities.
(b)See “Cost Recovery Mechanisms” discussion above.
(c)In accordance with regulatory accounting, APS accrues removal costs for its regulated assets, even if there is no legal obligation for removal.
(d)See Note 8.
(e)Pursuant to Decision 77852, the ACC has authorized APS to return to customers up to $7 million of liability recorded to the TEAM balancing account through December 31, 2021. Should new base rates become effective prior to December 31, 2021, any remaining unreturned balance is anticipated to be included in the new base rates.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. Income Taxes
Certain assets and liabilities are reported differently for income tax purposes than they are for financial statement purposes. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using currently enacted income tax rates.
APS has recorded regulatory assets and regulatory liabilities related to income taxes on its Consolidated Balance Sheets in accordance with accounting guidance for regulated operations. The regulatory assets are for certain temporary differences, primarily the allowance for equity funds used during construction, investment tax credit (“ITC”) basis adjustment and tax expense of Medicare subsidy. The regulatory liabilities primarily relate to the change in income tax rates and deferred taxes resulting from ITCs.
The Tax Act reduced the corporate tax rate to 21% effective January 1, 2018. As a result of this rate reduction, the Company recognized a $1.14 billion reduction in its net deferred income tax liabilities as of December 31, 2017. In accordance with accounting for regulated companies, the effect of this rate reduction was substantially offset by a net regulatory liability.
Federal income tax laws require the amortization of a majority of this net regulatory liability over the remaining regulatory life of the related property. As a result of the modifications made to the annual transmission formula rate during the second quarter of 2018, the Company began amortization of FERC jurisdictional net excess deferred tax liabilities in 2018. On March 13, 2019, the ACC approved the Company’s proposal to amortize non-depreciation related net excess deferred tax liabilities subject to its jurisdiction over a twelve-month period. As a result, the Company began amortization in March 2019. The Company recorded $14 million and $57 million of income tax benefit related to the amortization of these non-depreciation related net excess deferred tax liabilities in 2020 and 2019, respectively. On October 29, 2019, the ACC approved the Company’s proposal to amortize depreciation related net excess deferred tax liabilities subject to its jurisdiction over a 28.5-year period with amortization to retroactively begin as of January 1, 2018. The Company recorded $31 million and $62 million of income tax benefit related to amortization of these depreciation related liabilities in 2020 and 2019, respectively. (See Note 4 for more details.)
In August 2018, U.S. Treasury proposed regulations that clarified bonus depreciation transition rules under the Tax Act for regulated public utility property placed in service after September 27, 2017 and before January 1, 2018. However, these proposed regulations were ambiguous with respect to regulated public utility property placed in service on or after January 1, 2018. In September 2019, U.S. Treasury issued final regulations, which replaced the August 2018 proposed regulations. These final regulations did not materially impact any tax position taken by the Company for property placed in service after September 27, 2017 and before January 1, 2018.
In September 2020, U.S. Treasury issued final regulations, which clarify bonus depreciation transition rules under the Tax Act for property placed in service by regulated public utilities after December 31, 2017. The final regulations provide that certain regulated public utility property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020 continues to be eligible for bonus depreciation under the rules and bonus depreciation phase-downs in effect prior to enactment of the Tax Act. These final regulations do not materially impact any tax position taken by the Company for property which was under construction prior to September 28, 2017 and placed in service between January 1, 2018 and December 31, 2020.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In accordance with regulatory requirements, APS ITCs are deferred and are amortized over the life of the related property with such amortization applied as a credit to reduce current income tax expense in the Statements of Income.
Net income associated with the Palo Verde sale leaseback VIEs is not subject to tax. As a result, there is no income tax expense associated with the VIEs recorded on the Pinnacle West Consolidated and APS Consolidated Statements of Income. (See Note 18 for additional details related to the Palo Verde sale leaseback VIEs.)
The following is a tabular reconciliation of the total amounts of unrecognized tax benefits, excluding interest and penalties, at the beginning and end of the year that are included in accrued taxes and unrecognized tax benefits (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pinnacle West Consolidated
|
|
APS Consolidated
|
|
2020
|
|
2019
|
|
2018
|
|
2020
|
|
2019
|
|
2018
|
Total unrecognized tax benefits, January 1
|
$
|
43,435
|
|
|
$
|
40,731
|
|
|
$
|
41,966
|
|
|
$
|
43,435
|
|
|
$
|
40,731
|
|
|
$
|
41,966
|
|
Additions for tax positions of the current year
|
3,418
|
|
|
3,373
|
|
|
3,436
|
|
|
3,418
|
|
|
3,373
|
|
|
3,436
|
|
Additions for tax positions of prior years
|
1,431
|
|
|
1,843
|
|
|
2,696
|
|
|
1,431
|
|
|
1,843
|
|
|
2,696
|
|
Reductions for tax positions of prior years for:
|
|
|
|
|
|
|
|
|
|
|
|
Changes in judgment
|
(1,965)
|
|
|
(2,078)
|
|
|
(1,764)
|
|
|
(1,965)
|
|
|
(2,078)
|
|
|
(1,764)
|
|
Settlements with taxing authorities
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Lapses of applicable statute of limitations
|
(664)
|
|
|
(434)
|
|
|
(5,603)
|
|
|
(664)
|
|
|
(434)
|
|
|
(5,603)
|
|
Total unrecognized tax benefits, December 31
|
$
|
45,655
|
|
|
$
|
43,435
|
|
|
$
|
40,731
|
|
|
$
|
45,655
|
|
|
$
|
43,435
|
|
|
$
|
40,731
|
|
Included in the balances of unrecognized tax benefits are the following tax positions that, if recognized, would decrease our effective tax rate (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pinnacle West Consolidated
|
|
APS Consolidated
|
|
2020
|
|
2019
|
|
2018
|
|
2020
|
|
2019
|
|
2018
|
Tax positions, that if recognized, would decrease our effective tax rate
|
$
|
25,714
|
|
|
$
|
22,813
|
|
|
$
|
19,504
|
|
|
$
|
25,714
|
|
|
$
|
22,813
|
|
|
$
|
19,504
|
|
As of the balance sheet date, the tax year ended December 31, 2017 and all subsequent tax years remain subject to examination by the IRS. With a few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 2016.
We reflect interest and penalties, if any, on unrecognized tax benefits in the Pinnacle West Consolidated and APS Consolidated Statements of Income as income tax expense. The amount of interest expense or benefit recognized related to unrecognized tax benefits are as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pinnacle West Consolidated
|
|
APS Consolidated
|
|
2020
|
|
2019
|
|
2018
|
|
2020
|
|
2019
|
|
2018
|
Unrecognized tax benefit interest expense/(benefit) recognized
|
$
|
266
|
|
|
$
|
459
|
|
|
$
|
(780)
|
|
|
$
|
266
|
|
|
$
|
459
|
|
|
$
|
(780)
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Following are the total amount of accrued liabilities for interest recognized related to unrecognized benefits that could reverse and decrease our effective tax rate to the extent matters are settled favorably (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pinnacle West Consolidated
|
|
APS Consolidated
|
|
2020
|
|
2019
|
|
2018
|
|
2020
|
|
2019
|
|
2018
|
Unrecognized tax benefit interest accrued
|
$
|
1,855
|
|
|
$
|
1,589
|
|
|
$
|
1,130
|
|
|
$
|
1,855
|
|
|
$
|
1,589
|
|
|
$
|
1,130
|
|
Additionally, as of December 31, 2020, we have recognized less than $1 million of interest expense to be paid on the underpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS.
The components of income tax expense are as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pinnacle West Consolidated
|
|
APS Consolidated
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
|
2020
|
|
2019
|
|
2018
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
$
|
11,869
|
|
|
$
|
(13,551)
|
|
|
$
|
18,375
|
|
|
$
|
57,299
|
|
|
$
|
(54,697)
|
|
|
$
|
88,180
|
|
State
|
1,932
|
|
|
3,195
|
|
|
3,342
|
|
|
99
|
|
|
695
|
|
|
1,877
|
|
Total current
|
13,801
|
|
|
(10,356)
|
|
|
21,717
|
|
|
57,398
|
|
|
(54,002)
|
|
|
90,057
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
53,398
|
|
|
(14,982)
|
|
|
94,721
|
|
|
15,122
|
|
|
29,321
|
|
|
32,436
|
|
State
|
10,974
|
|
|
9,565
|
|
|
17,464
|
|
|
16,244
|
|
|
15,109
|
|
|
22,321
|
|
Total deferred
|
64,372
|
|
|
(5,417)
|
|
|
112,185
|
|
|
31,366
|
|
|
44,430
|
|
|
54,757
|
|
Income tax expense/(benefit)
|
$
|
78,173
|
|
|
$
|
(15,773)
|
|
|
$
|
133,902
|
|
|
$
|
88,764
|
|
|
$
|
(9,572)
|
|
|
$
|
144,814
|
|
The following chart compares pretax income at the 21% statutory federal income tax rate to income tax expense (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pinnacle West Consolidated
|
|
APS Consolidated
|
|
Year Ended December 31,
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
|
2020
|
|
2019
|
|
2018
|
Federal income tax expense at statutory rate
|
$
|
136,127
|
|
|
$
|
113,828
|
|
|
$
|
139,533
|
|
|
$
|
142,020
|
|
|
$
|
120,790
|
|
|
$
|
154,260
|
|
Increases (reductions) in tax expense resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
State income tax net of federal income tax benefit
|
19,146
|
|
|
18,599
|
|
|
23,115
|
|
|
20,124
|
|
|
19,267
|
|
|
24,531
|
|
State income tax credits net of federal income tax benefit
|
(8,951)
|
|
|
(8,519)
|
|
|
(6,704)
|
|
|
(7,213)
|
|
|
(6,781)
|
|
|
(5,440)
|
|
Nondeductible expenditures associated with ballot initiative
|
—
|
|
|
—
|
|
|
7,879
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock compensation
|
34
|
|
|
(2,252)
|
|
|
(1,804)
|
|
|
183
|
|
|
(1,054)
|
|
|
(780)
|
|
Excess deferred income taxes — Tax Cuts and Jobs Act
|
(50,543)
|
|
|
(124,082)
|
|
|
(6,725)
|
|
|
(50,543)
|
|
|
(124,082)
|
|
|
(4,715)
|
|
Allowance for equity funds used during construction (see Note 1)
|
(2,747)
|
|
|
(2,476)
|
|
|
(7,231)
|
|
|
(2,747)
|
|
|
(2,476)
|
|
|
(7,231)
|
|
Palo Verde VIE noncontrolling interest (see Note 18)
|
(4,094)
|
|
|
(4,094)
|
|
|
(4,094)
|
|
|
(4,094)
|
|
|
(4,094)
|
|
|
(4,094)
|
|
Investment tax credit amortization
|
(7,510)
|
|
|
(6,851)
|
|
|
(6,742)
|
|
|
(7,510)
|
|
|
(6,851)
|
|
|
(6,742)
|
|
Other
|
(3,289)
|
|
|
74
|
|
|
(3,325)
|
|
|
(1,456)
|
|
|
(4,291)
|
|
|
(4,975)
|
|
Income tax expense/(benefit)
|
$
|
78,173
|
|
|
$
|
(15,773)
|
|
|
$
|
133,902
|
|
|
$
|
88,764
|
|
|
$
|
(9,572)
|
|
|
$
|
144,814
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of the net deferred income tax liability were as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pinnacle West Consolidated
|
|
APS Consolidated
|
|
December 31,
|
|
December 31,
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
DEFERRED TAX ASSETS
|
|
|
|
|
|
|
|
Risk management activities
|
$
|
4,287
|
|
|
$
|
17,552
|
|
|
$
|
4,287
|
|
|
$
|
17,552
|
|
Regulatory liabilities:
|
|
|
|
|
|
|
|
Excess deferred income taxes — Tax Cuts and Jobs Act
|
319,091
|
|
|
335,877
|
|
|
319,091
|
|
|
335,877
|
|
Asset retirement obligation and removal costs
|
157,470
|
|
|
143,011
|
|
|
157,470
|
|
|
143,011
|
|
Unamortized investment tax credits
|
50,879
|
|
|
52,236
|
|
|
50,879
|
|
|
52,236
|
|
Other postretirement benefits
|
95,778
|
|
|
43,841
|
|
|
95,778
|
|
|
43,841
|
|
Other
|
43,551
|
|
|
52,382
|
|
|
43,551
|
|
|
52,382
|
|
Operating lease liabilities
|
107,853
|
|
|
15,497
|
|
|
107,414
|
|
|
15,497
|
|
Pension liabilities
|
45,853
|
|
|
73,210
|
|
|
40,168
|
|
|
67,976
|
|
Coal reclamation liabilities
|
42,065
|
|
|
40,837
|
|
|
42,065
|
|
|
40,837
|
|
Renewable energy incentives
|
25,355
|
|
|
28,066
|
|
|
25,355
|
|
|
28,066
|
|
Credit and loss carryforwards
|
26,460
|
|
|
54,795
|
|
|
8,034
|
|
|
10,992
|
|
Other
|
78,113
|
|
|
47,605
|
|
|
78,113
|
|
|
55,451
|
|
Total deferred tax assets
|
996,755
|
|
|
904,909
|
|
|
972,205
|
|
|
863,718
|
|
DEFERRED TAX LIABILITIES
|
|
|
|
|
|
|
|
Plant-related
|
(2,489,899)
|
|
|
(2,448,458)
|
|
|
(2,489,899)
|
|
|
(2,448,458)
|
|
Risk management activities
|
(1,174)
|
|
|
(27)
|
|
|
(1,174)
|
|
|
(27)
|
|
Pension and other postretirement assets
|
(123,462)
|
|
|
(21,892)
|
|
|
(122,580)
|
|
|
(21,458)
|
|
Other special use funds
|
(42,927)
|
|
|
(44,507)
|
|
|
(42,927)
|
|
|
(44,507)
|
|
Operating lease right-of-use assets
|
(107,853)
|
|
|
(15,497)
|
|
|
(107,414)
|
|
|
(15,497)
|
|
Regulatory assets:
|
|
|
|
|
|
|
|
Allowance for equity funds used during construction
|
(41,038)
|
|
|
(40,023)
|
|
|
(41,038)
|
|
|
(40,023)
|
|
Deferred fuel and purchased power
|
(47,673)
|
|
|
(35,162)
|
|
|
(47,673)
|
|
|
(35,162)
|
|
Pension benefits
|
(116,219)
|
|
|
(163,339)
|
|
|
(116,219)
|
|
|
(163,339)
|
|
Retired power plant costs
|
(35,214)
|
|
|
(42,228)
|
|
|
(35,214)
|
|
|
(42,228)
|
|
Other
|
(106,227)
|
|
|
(82,722)
|
|
|
(106,227)
|
|
|
(82,722)
|
|
Other
|
(20,472)
|
|
|
(3,393)
|
|
|
(5,513)
|
|
|
(3,393)
|
|
Total deferred tax liabilities
|
(3,132,158)
|
|
|
(2,897,248)
|
|
|
(3,115,878)
|
|
|
(2,896,814)
|
|
Deferred income taxes — net
|
$
|
(2,135,403)
|
|
|
$
|
(1,992,339)
|
|
|
$
|
(2,143,673)
|
|
|
$
|
(2,033,096)
|
|
As of December 31, 2020, PNW Consolidated deferred tax assets for credit and loss carryforwards relate to federal general business credits of approximately $35 million, which first begin to expire in 2036 and state credit carryforwards net of federal benefit of $33 million, which first begin to expire in 2023. PNW Consolidated credit and loss carryforwards amount above has been reduced by $42 million of unrecognized tax benefits.
As of December 31, 2020, APS Consolidated deferred tax assets for credit and loss carryforwards relate to state credit carryforwards net of federal benefit of $16 million, which first begin to expire in 2024. APS Consolidated credit and loss carryforwards amount above has been reduced by $8 million of unrecognized tax benefits.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. Lines of Credit and Short-Term Borrowings
Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs, to refinance indebtedness, and for other general corporate purposes.
The table below presents the consolidated credit facilities and the amounts available and outstanding as of December 31, 2020 and 2019 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
|
Pinnacle West
|
APS
|
Total
|
|
Pinnacle West
|
APS
|
Total
|
Commitments under Credit Facilities
|
$
|
231,000
|
|
$
|
1,000,000
|
|
$
|
1,231,000
|
|
|
$
|
250,000
|
|
$
|
1,000,000
|
|
$
|
1,250,000
|
|
Outstanding Commercial Paper, Term Loan and Revolving Credit Facility Borrowings
|
(169,000)
|
|
—
|
|
(169,000)
|
|
|
(114,675)
|
|
—
|
|
(114,675)
|
|
Amount of Credit Facilities Available
|
$
|
62,000
|
|
$
|
1,000,000
|
|
$
|
1,062,000
|
|
|
$
|
135,325
|
|
$
|
1,000,000
|
|
$
|
1,135,325
|
|
|
|
|
|
|
|
|
|
Weighted-Average Commitment Fees
|
0.125%
|
0.100%
|
|
|
0.125%
|
0.100%
|
|
Pinnacle West
On May 5, 2020, Pinnacle West refinanced its 364-day $50 million term loan agreement that would have matured on May 7, 2020 with a new 364-day $31 million term loan agreement that matures May 4, 2021. Borrowings under the agreement bear interest at Eurodollar Rate plus 1.40% per annum. At December 31, 2020, Pinnacle West had $19 million in outstanding borrowings under the agreement.
At December 31, 2020, Pinnacle West had a $200 million revolving credit facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on Pinnacle West’s senior unsecured debt credit ratings. The facility is available to support Pinnacle West’s $200 million commercial paper program, for bank borrowings or for issuances of letters of credits. At December 31, 2020, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $150 million of commercial paper borrowings.
APS
At December 31, 2020, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and a $500 million facility that matures in July 2023. APS may increase the amount of each facility up to a maximum of $700 million, for a total of $1.4 billion, upon the satisfaction of certain conditions and with the consent of the lenders. Interest rates are based on APS’s senior unsecured debt credit ratings. These facilities are available to support APS’s $500 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2020, APS had no outstanding borrowings under its revolving credit facilities, no letters of credit outstanding or commercial paper borrowings.
See “Financial Assurances” in Note 11 for a discussion of APS’s other outstanding letters of credit.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Debt Provisions
On December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s short-term debt authorization equal to a sum of (i) 7% of APS’s capitalization, and (ii) $500 million (which is required to be used for costs relating to purchases of natural gas and power). (See Note 7 for additional long-term debt provisions.)
7. Long-Term Debt and Liquidity Matters
All of Pinnacle West’s and APS’s debt is unsecured. The following table presents the components of long-term debt on the Consolidated Balance Sheets outstanding at December 31, 2020 and 2019 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity
|
|
Interest
|
|
December 31,
|
|
Dates (a)
|
|
Rates
|
|
2020
|
|
2019
|
APS
|
|
|
|
|
|
|
|
Pollution control bonds:
|
|
|
|
|
|
|
|
Variable
|
2029
|
|
(b)
|
|
$
|
35,975
|
|
|
$
|
35,975
|
|
Fixed
|
2024
|
|
4.70%
|
|
—
|
|
|
115,150
|
|
Total pollution control bonds
|
|
|
|
|
35,975
|
|
|
151,125
|
|
Senior unsecured notes
|
2024-2050
|
|
2.55%-6.88%
|
|
5,830,000
|
|
|
4,875,000
|
|
Term loans
|
|
|
(c)
|
|
—
|
|
|
200,000
|
|
Unamortized discount
|
|
|
|
|
(15,900)
|
|
|
(12,434)
|
|
Unamortized premium
|
|
|
|
|
14,781
|
|
|
7,423
|
|
Unamortized debt issuance cost
|
|
|
|
|
(46,911)
|
|
|
(37,981)
|
|
Total APS long-term debt
|
|
|
|
|
5,817,945
|
|
|
5,183,133
|
|
Less current maturities
|
|
|
|
|
—
|
|
|
350,000
|
|
Total APS long-term debt less current maturities
|
|
|
|
|
5,817,945
|
|
|
4,833,133
|
|
Pinnacle West
|
|
|
|
|
|
|
|
Senior unsecured notes
|
2025
|
|
1.3%
|
|
500,000
|
|
|
300,000
|
|
Term loan
|
|
|
(d)
|
|
—
|
|
|
150,000
|
|
Unamortized discount
|
|
|
|
|
(44)
|
|
|
(57)
|
|
Unamortized debt issuance cost
|
|
|
|
|
(3,635)
|
|
|
(518)
|
|
Total Pinnacle West long-term debt
|
|
|
|
|
496,321
|
|
|
449,425
|
|
Less current maturities
|
|
|
|
|
—
|
|
|
450,000
|
|
Total Pinnacle West long-term debt less current maturities
|
|
|
|
|
496,321
|
|
|
(575)
|
|
TOTAL LONG-TERM DEBT LESS CURRENT MATURITIES
|
|
|
|
|
$
|
6,314,266
|
|
|
$
|
4,832,558
|
|
(a) This schedule does not reflect the timing of redemptions that may occur prior to maturities.
(b) The weighted-average rate for the variable rate pollution control bonds was 0.18% at December 31, 2020 and 1.54% at December 31, 2019.
(c) The weighted-average interest rate was 2.12% at December 31, 2019. This term loan was repaid on May 26, 2020. See additional details below.
(d) The weighted-average interest rate was 2.20% at December 31, 2019. This term loan was repaid on June 19, 2020. See additional details below.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows principal payments due on Pinnacle West’s and APS’s total long-term debt (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Consolidated
Pinnacle West
|
|
Consolidated
APS
|
2021
|
|
$
|
—
|
|
|
$
|
—
|
|
2022
|
|
—
|
|
|
—
|
|
2023
|
|
—
|
|
|
—
|
|
2024
|
|
250,000
|
|
|
250,000
|
|
2025
|
|
800,000
|
|
|
300,000
|
|
Thereafter
|
|
5,315,975
|
|
|
5,315,975
|
|
Total
|
|
$
|
6,365,975
|
|
|
$
|
5,865,975
|
|
Debt Fair Value
Our long-term debt fair value estimates are classified within Level 2 of the fair value hierarchy. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
December 31, 2020
|
|
As of
December 31, 2019
|
|
Carrying
Amount
|
|
Fair Value
|
|
Carrying
Amount
|
|
Fair Value
|
Pinnacle West
|
$
|
496,321
|
|
|
$
|
509,050
|
|
|
$
|
449,425
|
|
|
$
|
450,822
|
|
APS
|
5,817,945
|
|
|
7,103,791
|
|
|
5,183,133
|
|
|
5,743,570
|
|
Total
|
$
|
6,314,266
|
|
|
$
|
7,612,841
|
|
|
$
|
5,632,558
|
|
|
$
|
6,194,392
|
|
Credit Facilities and Debt Issuances
Pinnacle West
On June 17, 2020, Pinnacle West issued $500 million of 1.3% unsecured senior notes that mature June 15, 2025. The net proceeds from the sale were used to repay early its $150 million term loan facility set to mature on December 21, 2020, to repay short-term indebtedness consisting of commercial paper and replenish cash incurred or used to fund capital expenditures, to redeem prior to maturity our $300 million, 2.25% senior notes due November 30, 2020, and for general corporate purposes.
On December 23, 2020, Pinnacle West entered into a $150 million term loan facility that matures June 2022. The proceeds were received on January 4, 2021 and used for general corporate purposes. We recognized the term loan facility as long-term debt upon settlement on January 4, 2021.
APS
On January 15, 2020, APS repaid at maturity the remaining $150 million of the $250 million aggregate principal amount of its 2.2% senior notes.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On May 22, 2020, APS issued $600 million of 3.35% unsecured senior notes that mature May 15, 2050. The net proceeds from the sale were used to repay early its $200 million term loan facility and to repay short-term indebtedness, consisting of commercial paper and revolver borrowings, and to replenish cash used to fund capital expenditures.
On September 11, 2020, APS issued $400 million of 2.65% unsecured senior notes that mature September 15, 2050. The net proceeds from the sale will be used to replenish cash used for previous eligible green expenditures and fund future eligible green expenditures.
On November 19, 2020, APS reopened its $300 million, 2.6% unsecured senior notes that mature on August 15, 2029, and issued an additional $105 million of 2.6% unsecured senior notes. The aggregate balance of $405 million will mature on August 15, 2029. The net proceeds from the sale, together with funds made available from other sources, were used to redeem, prior to maturity, no later than 20 days after the date that the new notes were issued, (i) the $49.4 million outstanding principal amount of 4.7% City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project), 1994 Series A, and (ii) the $65.75 million outstanding principal amount of 4.7% City of Farmington, New Mexico Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Four Corners Project), 1994 Series B.
On December 28, 2020, Pinnacle West contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness.
See “Lines of Credit and Short-Term Borrowings” in Note 6 and “Financial Assurances” in Note 11 for discussion of APS’s separate outstanding letters of credit.
Debt Provisions
Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2020, the ratio was approximately 54% for Pinnacle West and 49% for APS. Failure to comply with such covenant levels would result in an event of default, which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.
Neither Pinnacle West’s nor APS’s financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, our bank credit agreements contain a pricing grid in which the interest rates we pay for borrowings thereunder are determined by our current credit ratings.
All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’s bank agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for credit facility borrowings.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Although provisions in APS’s articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On December 17, 2020, the ACC issued a financing order in which, subject to specified parameters and procedures, it approved APS’s long-term debt authorization from $5.9 billion to $7.5 billion in light of the projected growth of APS and its customer base and the resulting projected financing needs. (See Note 6 for additional short-term debt provisions.)
8. Retirement Plans and Other Postretirement Benefits
Pinnacle West sponsors a qualified defined benefit and account balance pension plan (The Pinnacle West Capital Corporation Retirement Plan) and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and its subsidiaries. All new employees participate in the account balance plan. Defined benefit plans specify the amount of benefits a plan participant is to receive using information about the participant. The pension plan covers nearly all employees. The supplemental excess benefit retirement plan covers officers of the Company and highly compensated employees designated for participation by the Board of Directors. Our employees do not contribute to the plans. We calculate the benefits based on age, years of service and pay.
Pinnacle West also sponsors other postretirement benefit plans (Pinnacle West Capital Corporation Group Life and Medical Plan and Pinnacle West Capital Corporation Post-65 Retiree Health Reimbursement Arrangement “HRA”) for the employees of Pinnacle West and its subsidiaries. These plans provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plan, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions. We retain the right to change or eliminate these benefits.
Pinnacle West uses a December 31 measurement date each year for its pension and other postretirement benefit plans. The market-related value of our plan assets is their fair value at the measurement date. (See Note 13 for further discussion of how fair values are determined.) Due to subjective and complex judgments, which may be required in determining fair values, actual results could differ from the results estimated through the application of these methods.
Under the HRA, included in the other postretirement benefit plan, the Company provides a subsidy to retirees to defray the cost of a Medicare supplemental policy. In prior years, we had been assuming a 4.75% escalation of these benefits; however, actual escalation has been significantly less than this assumption. Accordingly, during 2020 and for future periods, the escalation assumption was reduced to 2.00% (see weighted-average assumption table below). This escalation factor assumption change, among other factors, resulted in an increase in the over-funded status of the other postretirement benefit plan as of December 31, 2020. As a result, on January 4, 2021, we initiated the transfer of approximately $106 million of investment assets from the other postretirement benefit plan into the Active Union Employee Medical Account Trust. The Active Union Employee Medical Account is an existing trust account that holds investments restricted for paying active union employee medical costs (see Note 19). The transfer of other postretirement benefit plan investment assets into the Active Union Employee Medical Account permits access to approximately $106 million of assets for the sole purpose of paying active union employee medical benefits. This transfer of investment assets into the Active Union Employee Medical Account is consistent with the terms of a similar 2018 transaction.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A significant portion of the changes in the actuarial gains and losses of our pension and postretirement plans is attributable to APS and are recoverable in rates. Accordingly, these changes are recorded as a regulatory asset or regulatory liability (see Note 4).
The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction or billed to electric plant participants) (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plans
|
|
Other Benefits Plans
|
|
2020
|
|
2019
|
|
2018
|
|
2020
|
|
2019
|
|
2018
|
Service cost-benefits earned during the period
|
$
|
56,233
|
|
|
$
|
49,902
|
|
|
$
|
56,669
|
|
|
$
|
22,236
|
|
|
$
|
18,369
|
|
|
$
|
21,100
|
|
Interest cost on benefit obligation
|
118,567
|
|
|
136,843
|
|
|
124,689
|
|
|
25,857
|
|
|
29,894
|
|
|
28,147
|
|
Expected return on plan assets
|
(187,443)
|
|
|
(171,884)
|
|
|
(182,853)
|
|
|
(40,077)
|
|
|
(38,412)
|
|
|
(42,082)
|
|
Amortization of:
|
|
|
|
|
|
|
|
|
|
|
|
Prior service credit
|
—
|
|
|
—
|
|
|
—
|
|
|
(37,575)
|
|
|
(37,821)
|
|
|
(37,842)
|
|
Net actuarial loss
|
34,612
|
|
|
42,584
|
|
|
32,082
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net periodic benefit cost/(benefit)
|
$
|
21,969
|
|
|
$
|
57,445
|
|
|
$
|
30,587
|
|
|
$
|
(29,559)
|
|
|
$
|
(27,970)
|
|
|
$
|
(30,677)
|
|
Portion of cost/(benefit) charged to expense
|
$
|
3,386
|
|
|
$
|
30,312
|
|
|
$
|
10,120
|
|
|
$
|
(20,966)
|
|
|
$
|
(19,859)
|
|
|
$
|
(21,426)
|
|
The following table shows the plans’ changes in the benefit obligations and funded status (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plans
|
|
Other Benefits Plans
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Change in Benefit Obligation
|
|
|
|
|
|
|
|
Benefit obligation at January 1
|
$
|
3,613,114
|
|
|
$
|
3,190,626
|
|
|
$
|
746,924
|
|
|
$
|
676,771
|
|
Service cost
|
56,233
|
|
|
49,902
|
|
|
22,236
|
|
|
18,369
|
|
Interest cost
|
118,567
|
|
|
136,843
|
|
|
25,857
|
|
|
29,894
|
|
Benefit payments
|
(191,704)
|
|
|
(177,882)
|
|
|
(31,511)
|
|
|
(32,486)
|
|
Actuarial (gain) loss
|
306,657
|
|
|
413,625
|
|
|
(139,472)
|
|
|
54,376
|
|
|
|
|
|
|
|
|
|
Benefit obligation at December 31
|
3,902,867
|
|
|
3,613,114
|
|
|
624,034
|
|
|
746,924
|
|
Change in Plan Assets
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1
|
3,318,351
|
|
|
2,733,476
|
|
|
837,494
|
|
|
723,677
|
|
Actual return on plan assets
|
642,373
|
|
|
602,030
|
|
|
150,076
|
|
|
144,095
|
|
Employer contributions
|
100,000
|
|
|
150,000
|
|
|
—
|
|
|
—
|
|
Benefit payments
|
(174,180)
|
|
|
(167,155)
|
|
|
(26,405)
|
|
|
(30,278)
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at December 31
|
3,886,544
|
|
|
3,318,351
|
|
|
961,165
|
|
|
837,494
|
|
Funded Status at December 31
|
$
|
(16,323)
|
|
|
$
|
(294,763)
|
|
|
$
|
337,131
|
|
|
$
|
90,570
|
|
The following table shows information for pension plans with an accumulated obligation in excess of plan assets (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
2020
|
|
2019
|
Accumulated benefit obligation
|
171,672
|
|
|
169,091
|
|
Fair value of plan assets
|
—
|
|
|
—
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on an accumulated benefit obligation basis at December 31, 2020 and December 31, 2019, therefore the only pension plan with an accumulated benefit obligation in excess of plan assets in 2020 and 2019 is a non-qualified supplemental excess benefit retirement plan.
The following table shows information for pension plans with a projected benefit obligation in excess of plan assets (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
2020
|
|
2019
|
Projected benefit obligation
|
182,184
|
|
|
3,613,114
|
|
Fair value of plan assets
|
—
|
|
|
3,318,351
|
|
The Pinnacle West Capital Corporation Retirement Plan is more than 100% funded on a projected benefit obligation basis at December 31, 2020, therefore the only pension plan with a projected benefit obligation in excess of plan assets in 2020 is a non-qualified supplemental excess benefit retirement plan.
The following table shows the amounts recognized on the Consolidated Balance Sheets (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plans
|
|
Other Benefits Plans
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Noncurrent asset
|
$
|
165,861
|
|
|
$
|
—
|
|
|
$
|
337,131
|
|
|
$
|
90,570
|
|
Current liability
|
(15,700)
|
|
|
(14,578)
|
|
|
—
|
|
|
—
|
|
Noncurrent liability
|
(166,484)
|
|
|
(280,185)
|
|
|
—
|
|
|
—
|
|
Net amount recognized
|
$
|
(16,323)
|
|
|
$
|
(294,763)
|
|
|
$
|
337,131
|
|
|
$
|
90,570
|
|
The following table shows the details related to accumulated other comprehensive loss as of December 31, 2020 and 2019 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plans
|
|
Other Benefits Plans
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
Net actuarial loss (gain)
|
$
|
552,301
|
|
|
$
|
735,186
|
|
|
$
|
(237,233)
|
|
|
$
|
12,238
|
|
Prior service credit
|
—
|
|
|
—
|
|
|
(152,337)
|
|
|
(189,912)
|
|
APS’s portion recorded as a regulatory (asset) liability
|
(469,953)
|
|
|
(660,223)
|
|
|
387,293
|
|
|
177,209
|
|
Income tax expense (benefit)
|
(20,364)
|
|
|
(18,546)
|
|
|
1,018
|
|
|
570
|
|
Accumulated other comprehensive loss (gain)
|
$
|
61,984
|
|
|
$
|
56,417
|
|
|
$
|
(1,259)
|
|
|
$
|
105
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the weighted-average assumptions used for both the pension and other benefits to determine benefit obligations and net periodic benefit costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit Obligations
As of December 31,
|
|
Benefit Costs
For the Years Ended December 31,
|
|
2020
|
|
2019
|
|
2020
|
|
2019
|
|
2018
|
Discount rate – pension plans
|
2.53
|
%
|
|
3.30
|
%
|
|
3.30
|
%
|
|
4.34
|
%
|
|
3.65
|
%
|
Discount rate – other benefits plans
|
2.63
|
%
|
|
3.42
|
%
|
|
3.42
|
%
|
|
4.39
|
%
|
|
3.71
|
%
|
Rate of compensation increase
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
|
4.00
|
%
|
Expected long-term return on plan assets - pension plans
|
N/A
|
|
N/A
|
|
5.75
|
%
|
|
6.25
|
%
|
|
6.05
|
%
|
Expected long-term return on plan assets - other benefit plans
|
N/A
|
|
N/A
|
|
4.85
|
%
|
|
5.40
|
%
|
|
5.40
|
%
|
Initial healthcare cost trend rate (pre-65 participants)
|
6.50
|
%
|
|
7.00
|
%
|
|
7.00
|
%
|
|
7.00
|
%
|
|
7.00
|
%
|
Ultimate healthcare cost trend rate (pre-65 participants)
|
4.75
|
%
|
|
4.75
|
%
|
|
4.75
|
%
|
|
4.75
|
%
|
|
4.75
|
%
|
Number of years to ultimate trend rate (pre-65 participants)
|
5
|
|
6
|
|
5
|
|
7
|
|
8
|
Initial and ultimate healthcare cost trend rate (post-65 participants) (a)
|
2.00
|
%
|
|
4.75
|
%
|
|
4.75
|
%
|
|
4.75
|
%
|
|
4.75
|
%
|
|
|
|
|
|
|
|
|
|
|
Interest crediting rate – cash balance pension plans
|
4.50
|
%
|
|
4.50
|
%
|
|
4.50
|
%
|
|
4.50
|
%
|
|
4.50
|
%
|
(a)See discussion above relating to this assumptions impact on benefit obligations and the January 2021 asset transfer to the Active Union Employee Medical Account.
In selecting the pretax expected long-term rate of return on plan assets, we consider past performance and economic forecasts for the types of investments held by the plan. For 2021, we are assuming a 5.30% long-term rate of return for pension assets and 5.05% (before tax) for other benefit assets, which we believe is reasonable given our asset allocation in relation to historical and expected performance.
In selecting our healthcare trend rates, we consider past performance and forecasts of healthcare costs.
Plan Assets
The Board of Directors has delegated oversight of the pension and other postretirement benefit plans’ assets to an Investment Management Committee (“Committee”). The Committee has adopted investment policy statements (“IPS”) for the pension and the other postretirement benefit plans’ assets. The investment strategies for these plans include external management of plan assets, and prohibition of investments in Pinnacle West securities.
The overall strategy of the pension plan’s IPS is to achieve an adequate level of trust assets relative to the benefit obligations. To achieve this objective, the plan’s investment policy provides for mixes of investments including long-term fixed income assets and return-generating assets. The target allocation between return-generating and long-term fixed income assets is defined in the IPS and is a function of the plan’s funded status. The plan’s funded status is reviewed on at least a monthly basis.
Changes in the value of long-term fixed income assets, also known as liability-hedging assets, are intended to offset changes in the benefit obligations due to changes in interest rates. Long-term fixed income assets consist primarily of fixed income debt securities issued by the U.S. Treasury and other
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
government agencies, U.S. Treasury Futures Contracts, and fixed income debt securities issued by corporations. Long-term fixed income assets may also include interest rate swaps, and other instruments.
Return-generating assets are intended to provide a reasonable long-term rate of investment return with a prudent level of volatility. Return-generating assets are composed of U.S. equities, international equities, and alternative investments. International equities include investments in both developed and emerging markets. Alternative investments may include investments in real estate, private equity and various other strategies. The plan may also hold investments in return-generating assets by holding securities in partnerships, common and collective trusts and mutual funds.
Based on the IPS, and given the pension plan’s funded status at year-end 2020, the target and actual allocation for the pension plan at December 31, 2020 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plans
|
|
Target Allocation
|
|
Actual Allocation
|
Long-term fixed income assets
|
72
|
%
|
|
68
|
%
|
Return-generating assets
|
28
|
%
|
|
32
|
%
|
Total
|
100
|
%
|
|
100
|
%
|
The permissible range is within +/-3% of the target allocation shown in the above table, and also considers the plan’s funded status. At December 31, 2020, the return-seeking assets were slightly outside the target allocation permissible range and were rebalanced to within the target range during January 2021.
The following table presents the additional target allocations, as a percent of total pension plan assets, for the return-generating assets:
|
|
|
|
|
|
Asset Class
|
Target Allocation
|
Equities in US and other developed markets
|
17
|
%
|
Equities in emerging markets
|
6
|
%
|
Alternative investments
|
5
|
%
|
Total
|
28
|
%
|
The pension plan IPS does not provide for a specific mix of long-term fixed income assets, but does expect the average credit quality of such assets to be investment grade.
As of December 31, 2020, the asset allocation for other postretirement benefit plan assets is governed by the IPS for those plans, which provides for different asset allocation target mixes depending on the characteristics of the liability. Some of these asset allocation target mixes vary with the plan’s funded status. The following table presents the actual allocations of the investment for the other postretirement benefit plan at December 31, 2020:
|
|
|
|
|
|
|
Other Benefits Plans
|
|
Actual Allocation
|
Long-term fixed income assets
|
55
|
%
|
Return-generating assets
|
45
|
%
|
Total
|
100
|
%
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
See Note 13 for a discussion on the fair value hierarchy and how fair value methodologies are applied. The plans invest directly in fixed income, U.S. Treasury Futures Contracts, and equity securities, in addition to investing indirectly in fixed income securities, equity securities and real estate through the use of mutual funds, partnerships and common and collective trusts. Equity securities held directly by the plans are valued using quoted active market prices from the published exchange on which the equity security trades, and are classified as Level 1. U.S. Treasury Futures Contracts are valued using the quoted active market prices from the exchange on which they trade, and are classified as Level 1. Fixed income securities issued by the U.S. Treasury held directly by the plans are valued using quoted active market prices, and are classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies are primarily valued using quoted inactive market prices, or quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield, maturity and credit quality. These instruments are classified as Level 2.
Mutual funds, partnerships, and common and collective trusts are valued utilizing a Net Asset Value (NAV) concept or its equivalent. Mutual funds, which includes exchange traded funds (ETFs), are classified as Level 1 and valued using a NAV that is observable and based on the active market in which the fund trades.
Common and collective trusts are maintained by banks or investment companies and hold certain investments in accordance with a stated set of objectives (such as tracking the performance of the S&P 500 Index). The trust’s shares are offered to a limited group of investors, and are not traded in an active market. Investments in common and collective trusts are valued using NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for trusts investing in exchange traded equities, and fixed income securities is derived from the market prices of the underlying securities held by the trusts. The NAV for trusts investing in real estate is derived from the appraised values of the trust’s underlying real estate assets. As of December 31, 2020, the plans were able to transact in the common and collective trusts at NAV.
Investments in partnerships are also valued using the concept of NAV as a practical expedient and, accordingly, are not classified in the fair value hierarchy. The NAV for these investments is derived from the value of the partnerships’ underlying assets. The plan’s partnerships holdings relate to investments in high-yield fixed income instruments. Certain partnerships also include funding commitments that may require the plan to contribute up to $50 million to these partnerships; as of December 31, 2020, approximately $38 million of these commitments have been funded.
The plans’ trustee provides valuation of our plan assets by using pricing services that utilize methodologies described to determine fair market value. We have internal control procedures to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustee’s internal operating controls and valuation processes.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2020, by asset category, are as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Other (a)
|
|
Total
|
Pension Plan:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
9,911
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,911
|
|
Fixed income securities:
|
|
|
|
|
|
|
|
Corporate
|
—
|
|
|
1,684,782
|
|
|
—
|
|
|
1,684,782
|
|
U.S. Treasury
|
794,571
|
|
|
—
|
|
|
—
|
|
|
794,571
|
|
Other (b)
|
—
|
|
|
112,224
|
|
|
—
|
|
|
112,224
|
|
Common stock equities (c)
|
331,058
|
|
|
—
|
|
|
—
|
|
|
331,058
|
|
Mutual funds (d)
|
262,765
|
|
|
—
|
|
|
—
|
|
|
262,765
|
|
Common and collective trusts:
|
|
|
|
|
|
|
|
Equities
|
—
|
|
|
—
|
|
|
407,522
|
|
|
407,522
|
|
Real estate
|
—
|
|
|
—
|
|
|
191,595
|
|
|
191,595
|
|
|
|
|
|
|
|
|
|
Partnerships
|
—
|
|
|
—
|
|
|
22,420
|
|
|
22,420
|
|
Short-term investments and other (e)
|
—
|
|
|
—
|
|
|
69,696
|
|
|
69,696
|
|
Total
|
$
|
1,398,305
|
|
|
$
|
1,797,006
|
|
|
$
|
691,233
|
|
|
$
|
3,886,544
|
|
Other Benefits:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
1,909
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,909
|
|
Fixed income securities:
|
|
|
|
|
|
|
|
Corporate
|
—
|
|
|
221,488
|
|
|
—
|
|
|
221,488
|
|
U.S. Treasury
|
258,102
|
|
|
—
|
|
|
—
|
|
|
258,102
|
|
Other (b)
|
—
|
|
|
8,316
|
|
|
—
|
|
|
8,316
|
|
Common stock equities (c)
|
175,605
|
|
|
—
|
|
|
—
|
|
|
175,605
|
|
Mutual funds (d)
|
34,310
|
|
|
—
|
|
|
—
|
|
|
34,310
|
|
Common and collective trusts:
|
|
|
|
|
|
|
|
Equities
|
—
|
|
|
—
|
|
|
94,674
|
|
|
94,674
|
|
Real estate
|
—
|
|
|
—
|
|
|
19,778
|
|
|
19,778
|
|
|
|
|
|
|
|
|
|
Short-term investments and other (e)
|
142,995
|
|
|
—
|
|
|
3,988
|
|
|
146,983
|
|
Total
|
$
|
612,921
|
|
|
$
|
229,804
|
|
|
$
|
118,440
|
|
|
$
|
961,165
|
|
(a)These investments primarily represent assets valued using NAV as a practical expedient, and have not been classified in the fair value hierarchy.
(b)This category consists primarily of debt securities issued by municipalities.
(c)This category primarily consists of U.S. common stock equities.
(d)These funds invest in international common stock equities.
(e)This category includes plan receivables and payables.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of Pinnacle West’s pension plan and other postretirement benefit plan assets at December 31, 2019, by asset category, are as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Other (a)
|
|
Total
|
Pension Plan:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
9,370
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,370
|
|
Fixed income securities:
|
|
|
|
|
|
|
|
Corporate
|
—
|
|
|
1,541,729
|
|
|
—
|
|
|
1,541,729
|
|
U.S. Treasury
|
406,112
|
|
|
—
|
|
|
—
|
|
|
406,112
|
|
Other (b)
|
—
|
|
|
92,240
|
|
|
—
|
|
|
92,240
|
|
Common stock equities (c)
|
250,829
|
|
|
—
|
|
|
—
|
|
|
250,829
|
|
Mutual funds (d)
|
185,928
|
|
|
—
|
|
|
—
|
|
|
185,928
|
|
Common and collective trusts:
|
|
|
|
|
|
|
|
Equities
|
—
|
|
|
—
|
|
|
392,403
|
|
|
392,403
|
|
Real estate
|
—
|
|
|
—
|
|
|
171,645
|
|
|
171,645
|
|
Fixed Income
|
—
|
|
|
—
|
|
|
98,065
|
|
|
98,065
|
|
Partnerships
|
—
|
|
|
—
|
|
|
103,796
|
|
|
103,796
|
|
Short-term investments and other (e)
|
—
|
|
|
—
|
|
|
66,234
|
|
|
66,234
|
|
Total
|
$
|
852,239
|
|
|
$
|
1,633,969
|
|
|
$
|
832,143
|
|
|
$
|
3,318,351
|
|
Other Benefits:
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
$
|
2,184
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,184
|
|
Fixed income securities:
|
|
|
|
|
|
|
|
Corporate
|
—
|
|
|
202,640
|
|
|
—
|
|
|
202,640
|
|
U.S. Treasury
|
353,650
|
|
|
—
|
|
|
—
|
|
|
353,650
|
|
Other (b)
|
—
|
|
|
7,999
|
|
|
—
|
|
|
7,999
|
|
Common stock equities (c)
|
146,316
|
|
|
—
|
|
|
—
|
|
|
146,316
|
|
Mutual funds (d)
|
14,351
|
|
|
—
|
|
|
—
|
|
|
14,351
|
|
Common and collective trusts:
|
|
|
|
|
|
|
|
Equities
|
—
|
|
|
—
|
|
|
83,648
|
|
|
83,648
|
|
Real estate
|
—
|
|
|
—
|
|
|
19,806
|
|
|
19,806
|
|
|
|
|
|
|
|
|
|
Short-term investments and other (e)
|
2,881
|
|
|
—
|
|
|
4,019
|
|
|
6,900
|
|
Total
|
$
|
519,382
|
|
|
$
|
210,639
|
|
|
$
|
107,473
|
|
|
$
|
837,494
|
|
(a)These investments primarily represent assets valued using NAV as a practical expedient, and have not been classified in the fair value hierarchy.
(b)This category consists primarily of debt securities issued by municipalities.
(c)This category primarily consists of U.S. common stock equities.
(d)These funds invest in U.S. and international common stock equities.
(e)This category includes plan receivables and payables.
Contributions
Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $100 million in 2020, $150 million in 2019, and $50 million in 2018. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to $100 million in 2021 and zero thereafter. With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2020 and 2019. We do not expect to make any contributions over the next three years to
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
our other postretirement benefit plans. The Company was reimbursed $26 million in 2020, $30 million in 2019, and $72 million in 2018 for prior years retiree medical claims from the other postretirement benefit plan trust assets.
Estimated Future Benefit Payments
Benefit payments, which reflect estimated future employee service, for the next five years and the succeeding five years thereafter, are estimated to be as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
|
|
Pension Plans
|
|
Other Benefits Plans
|
2021
|
|
$
|
210,119
|
|
|
$
|
31,204
|
|
2022
|
|
209,593
|
|
|
31,731
|
|
2023
|
|
215,527
|
|
|
32,196
|
|
2024
|
|
220,241
|
|
|
31,914
|
|
2025
|
|
220,787
|
|
|
31,484
|
|
Years 2026-2030
|
|
1,116,848
|
|
|
153,536
|
|
Electric plant participants contribute to the above amounts in accordance with their respective participation agreements.
Employee Savings Plan Benefits
Pinnacle West sponsors a defined contribution savings plan for eligible employees of Pinnacle West and its subsidiaries. In 2020, costs related to APS’s employees represented 99% of the total cost of this plan. In a defined contribution savings plan, the benefits a participant receives result from regular contributions participants make to their own individual account, the Company’s matching contributions and earnings or losses on their investments. Under this plan, the Company matches a percentage of the participants’ contributions in cash which is then invested in the same investment mix as participants elect to invest their own future contributions. Pinnacle West recorded expenses for this plan of approximately $11 million for 2020, $11 million for 2019, and $11 million for 2018.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. Leases
We lease certain land, buildings, vehicles, equipment and other property through operating rental agreements with varying terms, provisions, and expiration dates. APS also has certain purchased power agreements that qualify as lease arrangements. Our leases have remaining terms that expire in 2021 through 2050. Substantially all of our leasing activities relate to APS.
In 1986, APS entered into agreements with three separate lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. These lessor trust entities have been deemed VIEs for which APS is the primary beneficiary. As the primary beneficiary, APS consolidated these lessor trust entities. The impacts of these sale leaseback transactions are excluded from our lease disclosures as lease accounting is eliminated upon consolidation. (See Note 18 for a discussion of VIEs.)
On June 1, 2020 APS had two separate purchased power lease contracts that commenced. The lease terms end on September 30, 2025 and September 30, 2026, respectively. Both of these leases allow APS the right to the generation capacity from certain natural-gas fueled generators during the months of June through September over the contract term. APS does not operate or maintain these leased assets. APS controls the dispatch of the leased assets during the months of June through September and is required to pay a fixed monthly capacity payment during these periods of use. For these types of leased assets APS has elected to combine both the lease and non-lease payment components and accounts for the entire fixed payment as a lease obligation. These purchased power lease contracts are accounted for as operating leases. The contracts do not contain purchase options or term extension options. In addition to the fixed monthly capacity payment, APS must also pay variable charges based on the actual production volume of the asset. The variable consideration is not included in the measurement of our lease obligation.
The following table provides information related to our lease costs (dollars in thousands):
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|
|
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|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2020
|
|
Year Ended
December 31, 2019
|
|
|
Purchased Power Lease Contracts
|
|
Land, Property & Equipment Leases
|
|
Total
|
|
Purchased Power Lease Contracts
|
|
Land, Property & Equipment Leases
|
|
Total
|
Operating lease cost
|
|
$
|
68,883
|
|
|
$
|
18,493
|
|
|
$
|
87,376
|
|
|
$
|
42,190
|
|
|
$
|
18,038
|
|
|
$
|
60,228
|
|
Variable lease cost
|
|
121,359
|
|
|
972
|
|
|
122,331
|
|
|
113,233
|
|
|
782
|
|
|
114,015
|
|
Short-term lease cost
|
|
—
|
|
|
3,804
|
|
|
3,804
|
|
|
—
|
|
|
4,385
|
|
|
4,385
|
|
Total lease cost
|
|
$
|
190,242
|
|
|
$
|
23,269
|
|
|
$
|
213,511
|
|
|
$
|
155,423
|
|
|
$
|
23,205
|
|
|
$
|
178,628
|
|
Lease costs are primarily included as a component of operating expenses on our Consolidated Statements of Income. Lease costs relating to purchased power lease contracts are recorded in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4). The tables above reflect the lease cost amounts before the effect of regulatory deferral under the PSA and RES. Variable lease costs are recognized in the period the costs are incurred, and primarily relate to renewable purchased power lease contracts. Payments under most renewable purchased power lease contracts are dependent upon environmental factors, and due to the inherent uncertainty associated with the reliability of the fuel source, the payments are considered variable and are excluded from the measurement of lease liabilities and right-of-use lease assets. Certain of our lease agreements
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
have lease terms with non-consecutive periods of use. For these agreements we recognize lease costs during the periods of use. Leases with initial terms of 12 months or less are considered short-term leases and are not recorded on the balance sheet.
Lease expense recognized in the Consolidated Statements of Income was $18 million in 2018, this amount does not include purchased power lease contracts. Operating lease cost for purchased power lease contracts was $47 million in 2018. In addition, contingent rents for purchased power lease contracts was $109 million in 2018. These purchased power lease costs are recorded in fuel and purchased power on the Consolidated Statements of Income, and are subject to recovery under the PSA or RES (see Note 4).
The following table provides information related to the maturity of our operating lease liabilities (dollars in thousands):
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|
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|
|
|
|
|
|
December 31, 2020
|
Year
|
|
Purchased Power Lease Contracts
|
|
Land, Property & Equipment Leases
|
|
Total
|
2021
|
|
$
|
66,658
|
|
|
$
|
14,455
|
|
|
$
|
81,113
|
|
2022
|
|
68,325
|
|
|
10,849
|
|
|
79,174
|
|
2023
|
|
70,033
|
|
|
8,503
|
|
|
78,536
|
|
2024
|
|
71,784
|
|
|
6,104
|
|
|
77,888
|
|
2025
|
|
73,578
|
|
|
4,400
|
|
|
77,978
|
|
Thereafter
|
|
36,760
|
|
|
37,314
|
|
|
74,074
|
|
Total lease commitments
|
|
387,138
|
|
|
81,625
|
|
|
468,763
|
|
Less imputed interest
|
|
14,375
|
|
|
18,267
|
|
|
32,642
|
|
Total lease liabilities
|
|
$
|
372,763
|
|
|
$
|
63,358
|
|
|
$
|
436,121
|
|
We recognize lease assets and liabilities upon lease commencement. At December 31, 2020, we have certain purchased power lease contracts, that have been executed but have not yet commenced. In January 2021, we also executed additional purchased power lease contracts relating to energy storage. These arrangements have commencement dates beginning in May 2021 with terms ending through December 2042. We expect the total fixed consideration paid for these arrangements, which includes both lease and nonlease payments, will approximate $650 million over the term of the arrangements.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following tables provide other additional information related to operating lease liabilities (dollars in thousands):
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|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31, 2020
|
|
Year Ended December 31, 2019
|
Cash paid for amounts included in the measurement of lease liabilities — operating cash flows:
|
$
|
75,097
|
|
|
$
|
69,075
|
|
Right-of-use operating lease assets obtained in exchange for operating lease liabilities
|
441,653
|
|
|
11,262
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
Weighted average remaining lease term
|
6 years
|
|
13 years
|
Weighted average discount rate (a)
|
1.69
|
%
|
|
3.71
|
%
|
(a)Most of our lease agreements do not contain an implicit rate that is readily determinable. For these agreements we use our incremental borrowing rate to measure the present value of lease liabilities. We determine our incremental borrowing rate at lease commencement based on the rate of interest that we would have to pay to borrow, on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. We use the implicit rate when it is readily determinable.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. Jointly-Owned Facilities
APS shares ownership of some of its generating and transmission facilities with other companies. We are responsible for our share of operating costs which are included in the corresponding operating expenses on our Consolidated Statements of Income. We are also responsible for providing our own financing. Our share of operating expenses and utility plant costs related to these facilities is accounted for using proportional consolidation. The following table shows APS’s interests in those jointly-owned facilities recorded on the Consolidated Balance Sheets at December 31, 2020 (dollars in thousands):
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|
Percent
Owned
|
|
|
|
Plant in
Service
|
|
Accumulated
Depreciation
|
|
Construction
Work in
Progress
|
Generating facilities:
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|
|
|
|
|
|
|
|
|
|
Palo Verde Units 1 and 3
|
|
29.1
|
%
|
|
|
|
$
|
1,911,339
|
|
|
$
|
1,108,883
|
|
|
$
|
26,623
|
|
Palo Verde Unit 2 (a)
|
|
16.8
|
%
|
|
|
|
649,035
|
|
|
379,305
|
|
|
7,268
|
|
Palo Verde Common
|
|
28.0
|
%
|
|
(b)
|
|
774,054
|
|
|
320,107
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|
|
41,607
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|
Palo Verde Sale Leaseback
|
|
|
|
(a)
|
|
351,050
|
|
|
253,014
|
|
|
—
|
|
Four Corners Generating Station
|
|
63.0
|
%
|
|
|
|
1,621,418
|
|
|
581,436
|
|
|
35,028
|
|
Cholla common facilities (c)
|
|
50.5
|
%
|
|
|
|
193,807
|
|
|
109,447
|
|
|
1,206
|
|
Transmission facilities:
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|
|
|
|
|
|
|
|
|
|
ANPP 500kV System
|
|
33.5
|
%
|
|
(b)
|
|
131,991
|
|
|
52,626
|
|
|
3,859
|
|
Navajo Southern System
|
|
26.0
|
%
|
|
(b)
|
|
89,113
|
|
|
33,536
|
|
|
1,215
|
|
Palo Verde — Yuma 500kV System
|
|
25.3
|
%
|
|
(b)
|
|
23,247
|
|
|
6,681
|
|
|
433
|
|
Four Corners Switchyards
|
|
61.8
|
%
|
|
(b)
|
|
69,441
|
|
|
17,009
|
|
|
3,145
|
|
Phoenix — Mead System
|
|
17.1
|
%
|
|
(b)
|
|
39,437
|
|
|
19,072
|
|
|
73
|
|
Palo Verde — Rudd 500kV System
|
|
50.0
|
%
|
|
|
|
93,123
|
|
|
28,206
|
|
|
1,921
|
|
Morgan — Pinnacle Peak System
|
|
64.6
|
%
|
|
(b)
|
|
117,497
|
|
|
20,754
|
|
|
912
|
|
Round Valley System
|
|
50.0
|
%
|
|
|
|
531
|
|
|
174
|
|
|
13
|
|
Palo Verde — Morgan System
|
|
88.9
|
%
|
|
(b)
|
|
257,220
|
|
|
20,943
|
|
|
530
|
|
Hassayampa — North Gila System
|
|
80.0
|
%
|
|
|
|
148,067
|
|
|
16,080
|
|
|
—
|
|
Cholla 500kV Switchyard
|
|
85.7
|
%
|
|
|
|
7,896
|
|
|
1,850
|
|
|
940
|
|
Saguaro 500kV Switchyard
|
|
60.0
|
%
|
|
|
|
21,669
|
|
|
13,229
|
|
|
2
|
|
Kyrene — Knox System
|
|
50.0
|
%
|
|
|
|
578
|
|
|
323
|
|
|
—
|
|
(a)See Note 18.
(b)Weighted-average of interests.
(c)PacifiCorp owns Cholla Unit 4 (see Note 4 for additional information) and APS operates the unit for PacifiCorp. The common facilities at Cholla are jointly-owned. Cholla Unit 4 was retired on December 24, 2020.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. Commitments and Contingencies
Palo Verde Generating Station
Spent Nuclear Fuel and Waste Disposal
On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the United States Department of Energy (“DOE”) in the United States Court of Federal Claims (“Court of Federal Claims”). The lawsuit sought to recover damages incurred due to DOE’s breach of the Contract for Disposal of Spent Nuclear Fuel and/or High Level Radioactive Waste (“Standard Contract”) for failing to accept Palo Verde’s spent nuclear fuel and high level waste from January 1, 2007 through June 30, 2011, as it was required to do pursuant to the terms of the Standard Contract and the Nuclear Waste Policy Act. On August 18, 2014, APS and DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment by DOE to the Palo Verde owners for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. In addition, the settlement agreement, as amended, provides APS with a method for submitting claims and getting recovery for costs incurred through December 31, 2019. On September 1, 2020, APS and DOE entered into an addendum to the settlement agreement allowing for the recovery of costs incurred through December 31, 2022.
APS has submitted six claims pursuant to the terms of the August 18, 2014 settlement agreement, for six separate time periods during July 1, 2011 through June 30, 2019. The DOE has approved and paid $99.7 million for these claims (APS’s share is $29.0 million). The amounts recovered were primarily recorded as adjustments to a regulatory liability and had no impact on reported net income. In accordance with the 2017 Rate Case Decision, this regulatory liability is being refunded to customers (see Note 4). On November 2, 2020, APS filed its seventh claim pursuant to the terms of the August 18, 2014 settlement agreement in the amount of $12.2 million (APS’s share is $3.6 million).
Nuclear Insurance
Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity Act (“Price-Anderson Act”), which limits the liability of nuclear reactor owners to the amount of insurance available from both commercial sources and an industry-wide retrospective payment plan. In accordance with the Price-Anderson Act, the Palo Verde participants are insured against public liability for a nuclear incident of up to approximately $13.8 billion per occurrence. Palo Verde maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers (“ANI”). The remaining balance of approximately $13.3 billion of liability coverage is provided through a mandatory industry-wide retrospective premium program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be responsible for retrospective premiums. The maximum retrospective premium per reactor under the program for each nuclear liability incident is approximately $137.6 million, subject to a maximum annual premium of approximately $20.5 million per incident. Based on APS’s ownership interest in the three Palo Verde units, APS’s maximum retrospective premium per incident for all three units is approximately $120.1 million, with a maximum annual retrospective premium of approximately $17.9 million.
The Palo Verde participants maintain insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion. APS has also secured accidental outage insurance for a sudden and unforeseen accidental outage of any of the three units. The property damage,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
decontamination, and accidental outage insurance are provided by Nuclear Electric Insurance Limited (“NEIL”). APS is subject to retrospective premium adjustments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount APS could incur under the current NEIL policies totals approximately $25.8 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. In addition, NEIL policies contain rating triggers that would result in APS providing approximately $75.1 million of collateral assurance within 20 business days of a rating downgrade to non-investment grade. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions, sublimits and exclusions.
Fuel and Purchased Power Commitments and Purchase Obligations
APS is party to various fuel and purchased power contracts and purchase obligations with terms expiring between 2021 and 2043 that include required purchase provisions. APS estimates the contract requirements to be approximately $772 million in 2021; $671 million in 2022; $632 million in 2023; $592 million in 2024; $564 million in 2025; and $5.4 billion thereafter. However, these amounts may vary significantly pursuant to certain provisions in such contracts that permit us to decrease required purchases under certain circumstances. These amounts include estimated commitments relating to purchased power lease contracts (see Note 9).
Of the various fuel and purchased power contracts mentioned above, some of those contracts for coal supply include take-or-pay provisions. The current coal contracts with take-or-pay provisions have terms expiring through 2031.
The following table summarizes our estimated coal take-or-pay commitments (dollars in thousands):
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31,
|
|
2021
|
|
2022
|
|
2023
|
|
2024
|
|
2025
|
|
Thereafter
|
Coal take-or-pay commitments (a)
|
$
|
182,569
|
|
|
$
|
183,604
|
|
|
$
|
184,540
|
|
|
$
|
186,804
|
|
|
$
|
177,114
|
|
|
$
|
1,024,854
|
|
(a)Total take-or-pay commitments are approximately $1.9 billion. The total net present value of these commitments is approximately $1.5 billion.
APS may spend more to meet its actual fuel requirements than the minimum purchase obligations in our coal take-or-pay contracts. The following table summarizes actual amounts purchased under the coal contracts which include take-or-pay provisions for each of the last three years (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
Total purchases
|
$
|
189,817
|
|
|
$
|
204,888
|
|
|
$
|
206,093
|
|
Renewable Energy Credits
APS has entered into contracts to purchase renewable energy credits to comply with the RES. APS estimates the contract requirements to be approximately $35 million in 2021; $31 million in 2022; $30 million in 2023; $28 million in 2024; $25 million in 2025; and $105 million thereafter. These amounts do not include purchases of renewable energy credits that are bundled with energy.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Coal Mine Reclamation Obligations
APS must reimburse certain coal providers for amounts incurred for final and contemporaneous coal mine reclamation. We account for contemporaneous reclamation costs as part of the cost of the delivered coal. We utilize site-specific studies of costs expected to be incurred in the future to estimate our final reclamation obligation. These studies utilize various assumptions to estimate the future costs. Based on the most recent reclamation studies, APS recorded an obligation for the coal mine final reclamation of approximately $170 million at December 31, 2020 and $166 million at December 31, 2019. Under our current coal supply agreements, APS expects to make payments for the final mine reclamation as follows: $16 million in 2021; $17 million in 2022; $18 million in 2023; $19 million in 2024; $20 million in 2025; and $69 million thereafter. Any amendments to current coal supply agreements may change the timing of the contribution. Portions of these funds will be held in an escrow account and distributed to certain coal providers under the terms of the applicable coal supply agreements.
Superfund-Related Matters
The Comprehensive Environmental Response Compensation and Liability Act (“Superfund” or “CERCLA”) establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who released, generated, transported to or disposed of hazardous substances at a contaminated site are among the parties who are potentially responsible (“PRPs”). PRPs may be strictly, and often are jointly and severally, liable for clean-up. On September 3, 2003, EPA advised APS that EPA considers APS to be a PRP in the Motorola 52nd Street Superfund Site, Operable Unit 3 (“OU3”) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with EPA to perform certain investigative activities of the APS facilities within OU3. In addition, on September 23, 2009, APS agreed with EPA and one other PRP to voluntarily assist with the funding and management of the site-wide groundwater remedial investigation and feasibility study (“RI/FS”). Based upon discussions between the OU3 working group parties and EPA, along with the results of recent technical analyses prepared by the OU3 working group to supplement the RI/FS for OU3, APS anticipates finalizing the RI/FS during the first or second quarter of 2021. We estimate that our costs related to this investigation and study will be approximately $3 million. We anticipate incurring additional expenditures in the future, but because the overall investigation is not complete and ultimate remediation requirements are not yet finalized, at the present time expenditures related to this matter cannot be reasonably estimated.
On August 6, 2013, the Roosevelt Irrigation District (“RID”) filed a lawsuit in Arizona District Court against APS and 24 other defendants, alleging that RID’s groundwater wells were contaminated by the release of hazardous substances from facilities owned or operated by the defendants. The lawsuit also alleges that, under Superfund laws, the defendants are jointly and severally liable to RID. The allegations against APS arise out of APS’s current and former ownership of facilities in and around OU3. As part of a state governmental investigation into groundwater contamination in this area, on January 25, 2015, ADEQ sent a letter to APS seeking information concerning the degree to which, if any, APS’s current and former ownership of these facilities may have contributed to groundwater contamination in this area. APS responded to ADEQ on May 4, 2015. On December 16, 2016, two RID environmental and engineering contractors filed an ancillary lawsuit for recovery of costs against APS and the other defendants in the RID litigation. That same day, another RID service provider filed an additional ancillary CERCLA lawsuit against certain of the defendants in the main RID litigation, but excluded APS and certain other parties as named defendants. Because the ancillary lawsuits concern past costs allegedly incurred by these RID
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
vendors, which were ruled unrecoverable directly by RID in November of 2016, the additional lawsuits do not increase APS’s exposure or risk related to these matters.
On April 5, 2018, RID and the defendants in that particular litigation executed a settlement agreement, fully resolving RID’s CERCLA claims concerning both past and future cost recovery. APS’s share of this settlement was immaterial. In addition, the two environmental and engineering vendors voluntarily dismissed their lawsuit against APS and the other named defendants without prejudice. An order to this effect was entered on April 17, 2018. With this disposition of the case, the vendors may file their lawsuit again in the future. On August 16, 2019, Maricopa County, one of the three direct defendants in the service provider lawsuit, filed a third-party complaint seeking contribution for its liability, if any, from APS and 28 other third-party defendants. We are unable to predict the outcome of these matters; however, we do not expect the outcome to have a material impact on our financial position, results of operations or cash flows.
Arizona Attorney General Matter
APS received civil investigative demands from the Attorney General seeking information pertaining to the rate plan comparison tool offered to APS customers and other related issues including implementation of rates from the 2017 Settlement Agreement and its Customer Education and Outreach Plan associated with the 2017 Settlement Agreement. APS fully cooperated with the Attorney General’s Office in this matter. On February 22, 2021 APS entered into a consent agreement with the Attorney General as a way to settle the matter. The settlement results in APS paying $24.75 million, $24 million of which is being returned to customers as restitution.
Environmental Matters
APS is subject to numerous environmental laws and regulations affecting many aspects of its present and future operations, including air emissions of both conventional pollutants and greenhouse gases, water quality, wastewater discharges, solid waste, hazardous waste, and CCRs. These laws and regulations can change from time to time, imposing new obligations on APS resulting in increased capital, operating, and other costs. Associated capital expenditures or operating costs could be material. APS intends to seek recovery of any such environmental compliance costs through our rates, but cannot predict whether it will obtain such recovery. The following proposed and final rules involve material compliance costs to APS.
Regional Haze Rules. APS has received the final rulemaking imposing pollution control requirements on Four Corners. EPA required the plant to install pollution control equipment that constitutes BART to lessen the impacts of emissions on visibility surrounding the plant. In addition, EPA issued a final rule for Regional Haze compliance at Cholla that does not involve the installation of new pollution controls and that will replace an earlier BART determination for this facility. See below for details of the Cholla BART approval.
Four Corners. Based on EPA’s final standards, APS’s 63% share of the cost of required controls for Four Corners Units 4 and 5 was approximately $400 million, which has been incurred. In addition, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in Four Corners Units 4 and 5. 4CA purchased the El Paso interest on July 6, 2016. NTEC purchased the interest from 4CA on July 3, 2018. See “Four Corners — 4CA Matter” below for a discussion of the NTEC purchase. The cost of the pollution controls related to
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the 7% interest is approximately $45 million, which was assumed by NTEC through its purchase of the 7% interest.
Cholla. In early 2017, EPA approved a final rule containing a revision to Arizona’s State Implementation Plan (“SIP”) for Cholla that implemented BART requirements for this facility, which did not require the installation of any new pollution control capital improvements. In conjunction with the closure of Cholla Unit 2 in 2015, APS has committed to ceasing coal combustion within Units 1 and 3 by April 2025. PacifiCorp retired Cholla Unit 4 at the end of 2020. (See “Cholla” in Note 4 for information regarding future plans for Cholla and details related to the resulting regulatory asset).
Coal Combustion Waste. On December 19, 2014, EPA issued its final regulations governing the handling and disposal of CCR, such as fly ash and bottom ash. The rule regulates CCR as a non-hazardous waste under Subtitle D of the Resource Conservation and Recovery Act (“RCRA”) and establishes national minimum criteria for existing and new CCR landfills and surface impoundments and all lateral expansions. These criteria include standards governing location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements. The rule generally requires any existing unlined CCR surface impoundment to stop receiving CCR and either retrofit or close, and further requires the closure of any CCR landfill or surface impoundment that cannot meet the applicable performance criteria for location restrictions or structural integrity. Such closure requirements are deemed “forced closure” or “closure for cause” of unlined surface impoundments, and are the subject of recent regulatory and judicial activities described below.
Since these regulations were finalized, EPA has taken steps to substantially modify the federal rules governing CCR disposal. While certain changes have been prompted by utility industry petitions, others have resulted from judicial review, court-approved settlements with environmental groups, and statutory changes to RCRA. The following lists the pending regulatory changes that, if finalized, could have a material impact as to how APS manages CCR at its coal-fired power plants:
•Following the passage of the Water Infrastructure Improvements for the Nation Act in 2016, EPA possesses authority to, either, authorize states to develop their own permit programs for CCR management or issue federal permits governing CCR disposal both in states without their own permit programs and on tribal lands. Although ADEQ has taken steps to develop a CCR permitting program, it is not clear when that program will be put into effect. On December 19, 2019, EPA proposed its own set of regulations governing the issuance of CCR management permits.
•On March 1, 2018, as a result of a settlement with certain environmental groups, EPA proposed adding boron to the list of constituents that trigger corrective action requirements to remediate groundwater impacted by CCR disposal activities. Apart from a subsequent proposal issued on August 14, 2019 to add a specific, health-based groundwater protection standard for boron, EPA has yet to take action on this proposal.
•Based on an August 21, 2018 D.C. Circuit decision, which vacated and remanded those provisions of the EPA CCR regulations that allow for the operation of unlined CCR surface impoundments, EPA recently proposed corresponding changes to federal CCR regulations. On July 29, 2020, EPA took final action on new regulations establishing revised deadlines for initiating the closure of unlined CCR surface impoundments; such disposal units must close as soon as technically feasible, but no later than April 22, 2021.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•On November 4, 2019, EPA also proposed to change the manner by which facilities that have committed to cease burning coal in the near-term may qualify for alternative closure. Such qualification would allow CCR disposal units at these plants to continue operating, even though they would otherwise be subject to forced closure under the federal CCR regulations. EPA’s July 29, 2020 final regulation adopted this proposal and now requires explicit EPA approval for facilities to utilize an alternative closure deadline. With respect to the Cholla facility, APS’s application for alternative closure (which would allow the continued disposal of CCR within the facility’s existing unlined CCR surface impoundments until the required date for ceasing coal-fired boiler operations in April 2025) was submitted to EPA on November 30, 2020 and is currently pending. This application will be subject to public comment and, potentially, judicial review.
We cannot at this time predict the outcome of these regulatory proceedings or when the EPA will take final action on those matters that are still pending. Depending on the eventual outcome, the costs associated with APS’s management of CCR could materially increase, which could affect APS’s financial position, results of operations, or cash flows.
APS currently disposes of CCR in ash ponds and dry storage areas at Cholla and Four Corners. APS estimates that its share of incremental costs to comply with the CCR rule for Four Corners is approximately $27 million and its share of incremental costs to comply with the CCR rule for Cholla is approximately $16 million. The Navajo Plant disposed of CCR only in a dry landfill storage area. To comply with the CCR rule for the Navajo Plant, APS’s share of incremental costs was approximately $1 million, which has been incurred. Additionally, the CCR rule requires ongoing, phased groundwater monitoring.
As of October 2018, APS has completed the statistical analyses for its CCR disposal units that triggered assessment monitoring. APS determined that several of its CCR disposal units at Cholla and Four Corners will need to undergo corrective action. In addition, under the current regulations, all such disposal units must have ceased operating and initiated closure by October 31, 2020. APS initiated an assessment of corrective measures on January 14, 2019 and expects such assessment will continue through mid- to late-2021. As part of this assessment, APS continues to gather additional groundwater data and perform remedial evaluations as to the CCR disposal units at Cholla and Four Corners undergoing corrective action. In addition, APS will solicit input from the public, host public hearings, and select remedies as part of this process. Based on the work performed to date, APS currently estimates that its share of corrective action and monitoring costs at Four Corners will likely range from $10 million to $15 million, which would be incurred over 30 years. The analysis needed to perform a similar cost estimate for Cholla remains ongoing at this time. As APS continues to implement the CCR rule’s corrective action assessment process, the current cost estimates may change. Given uncertainties that may exist until we have fully completed the corrective action assessment process, we cannot predict any ultimate impacts to the Company; however, at this time we do not believe the cost estimates for Cholla and any potential change to the cost estimate for Four Corners would have a material impact on our financial position, results of operations or cash flows.
Clean Power Plan/Affordable Clean Energy Regulations. On June 19, 2019, EPA took final action on its proposals to repeal EPA's 2015 Clean Power Plan (“CPP”) and replace those regulations with a new rule, the Affordable Clean Energy (“ACE”) regulations. EPA originally finalized the CPP on August 3, 2015, and such rules would have had far broader impact on the electric power sector than the ACE regulations. The ACE regulations had been stayed pending judicial review and on January 19, 2021, the U.S. Court of Appeals for the D.C. Circuit vacated the ACE regulations and remanded them back to
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EPA to develop new existing power plant carbon regulations consistent with the court’s ruling. That ruling endorsed an expansive view of the federal Clean Air Act consistent with EPA’s 2015 CPP. While the Biden administration has expressed an intent to regulate carbon emissions in this sector more aggressively under the Clean Air Act, we cannot at this time predict the outcome of pending EPA rulemaking proceedings in response to the court’s recent ACE decision.
Other environmental rules that could involve material compliance costs include those related to effluent limitations, the ozone national ambient air quality standard and other rules or matters involving the Clean Air Act, Clean Water Act, Endangered Species Act, RCRA, Superfund, the Navajo Nation, and water supplies for our power plants. The financial impact of complying with current and future environmental rules could jeopardize the economic viability of our coal plants or the willingness or ability of power plant participants to fund any required equipment upgrades or continue their participation in these plants. The economics of continuing to own certain resources, particularly our coal plants, may deteriorate, warranting early retirement of those plants, which may result in asset impairments. APS would seek recovery in rates for the book value of any remaining investments in the plants as well as other costs related to early retirement, but cannot predict whether it would obtain such recovery.
Four Corners National Pollutant Discharge Elimination System (“NPDES”) Permit
On July 16, 2018, several environmental groups filed a petition for review before the EPA Environmental Appeals Board (“EAB”) concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018. The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised effluent limitation guidelines for steam-electric EGUs, 2014 existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018. Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis. The EAB thereafter dismissed the environmental group appeal on February 12, 2019. EPA then issued a revised final NPDES permit for Four Corners on September 30, 2019. Based upon a November 1, 2019 filing by several environmental groups, the EAB again took up review of the Four Corners NPDES Permit. Oral argument on this appeal was held on September 3, 2020 and the EAB denied the environmental group petition on September 30, 2020. On January 22, 2021, the environmental groups filed a petition for review of the EAB’s decision with the U.S. Court of Appeals for the Ninth Circuit. We cannot predict the outcome of these appeal proceedings and, if such appeal is successful, whether that outcome will have a material impact on our financial position, results of operations, or cash flows.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Four Corners
4CA Matter
On July 6, 2016, 4CA purchased El Paso’s 7% interest in Four Corners. NTEC purchased this 7% interest on July 3, 2018 from 4CA. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million, and is paying 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. The note is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement. As of December 31, 2020, the note has a remaining balance of $27 million. NTEC continues to make payments in accordance with the terms of the note. Due to its short-remaining term, among other factors, there are no expected credit losses associated with the note.
In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC’s 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West’s guarantee is secured by a portion of APS’s payments to be owed to NTEC under the 2016 Coal Supply Agreement.
The 2016 Coal Supply Agreement contained alternate pricing terms for the 7% interest in the event NTEC did not purchase the interest. Until the time that NTEC purchased the 7% interest, the alternate pricing provisions were applicable to 4CA as the holder of the 7% interest. These terms included a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. The amount under this formula for calendar year 2018 (up to the date that NTEC purchased the 7% interest) was approximately $10 million, which was due to 4CA on December 31, 2019. Such payment was satisfied in January 2020 by NTEC directing to 4CA a prepayment from APS of future coal payment obligations of which the prepayment has been fully utilized as of June 2020.
Financial Assurances
In the normal course of business, we obtain standby letters of credit and surety bonds from financial institutions and other third parties. These instruments guarantee our own future performance and provide third parties with financial and performance assurance in the event we do not perform. These instruments support commodity contract collateral obligations and other transactions. As of December 31, 2020, standby letters of credit totaled $5.2 million and will expire in 2021. As of December 31, 2020, surety bonds expiring through 2022 totaled $16 million. The underlying liabilities insured by these instruments are reflected on our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds themselves.
We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements. Most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Pinnacle West has issued parental guarantees and has provided indemnification under certain surety bonds for APS which were not material at December 31, 2020. In connection with the sale of 4CA’s 7% interest to NTEC, Pinnacle West is guaranteeing certain obligations that NTEC will have to the other owners of Four Corners. (See “Four Corners — 4CA Matter” above for information related to this guarantee.) Pinnacle West has not needed to perform under this guarantee. A maximum obligation is not explicitly stated in the guarantee and, therefore, the overall maximum amount of the obligation under such guarantee cannot be reasonably estimated; however, we consider the fair value of this guarantee, including expected credit losses, to be immaterial.
In connection with BCE’s acquisition of minority ownership positions in the Clear Creek and Nobles 2 wind farms, Pinnacle West has issued parental guarantees to guarantee the obligations of BCE subsidiaries to make required equity contributions to fund project construction (the “Equity Contribution Guarantees”) and to make production tax credit funding payments to borrowers of the projects (the “PTC Guarantees”). The amounts guaranteed by Pinnacle West are reduced as payments are made under the respective guarantee agreements. The Equity Contribution Guarantees remaining as of December 31, 2020 are immaterial in amount (approximately $3 million) and the PTC Guarantees (approximately $39 million as of December 31, 2020) are currently expected to be terminated ten years following the commercial operation date of the applicable project.
12. Asset Retirement Obligations
In 2020, APS revised its cost estimates for existing AROs at Cholla relating to updated estimates for the closure of ponds and facilities, and at Four Corners and the Navajo Plant relating to corrective action and water monitoring costs, which resulted in an increase to the ARO of $6 million. Also in 2020, an updated Four Corners decommissioning study was finalized for the updated closure date of 2031, which resulted in an increase to the ARO of $13 million.
In 2019, APS received updated decommissioning estimates for the Navajo Plant closure in December 2019, which resulted in a decrease to the ARO in the amount of $8 million (see Note 4 for additional information). In addition, APS received a new decommissioning study for Palo Verde. This resulted in a decrease to the ARO in the amount of $89 million, a decrease in plant in service of $80 million and a reduction in the regulatory liability of $9 million.
The following table shows the change in our asset retirement obligations for 2020 and 2019 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
Asset retirement obligations at the beginning of year
|
$
|
657,218
|
|
|
$
|
726,545
|
|
Changes attributable to:
|
|
|
|
Accretion expense
|
38,652
|
|
|
39,726
|
|
Settlements
|
(9,710)
|
|
|
(12,591)
|
|
|
|
|
|
Estimated cash flow revisions
|
18,923
|
|
|
(96,462)
|
|
Asset retirement obligations at the end of year
|
$
|
705,083
|
|
|
$
|
657,218
|
|
In accordance with regulatory accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal. See detail of regulatory liabilities in Note 4.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
13. Fair Value Measurements
We classify our assets and liabilities that are carried at fair value within the fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:
Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date.
Level 2 — Other significant observable inputs, including quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active, and model-derived valuations whose inputs are observable (such as yield curves).
Level 3 — Valuation models with significant unobservable inputs that are supported by little or no market activity. Instruments in this category may include long-dated derivative transactions where valuations are unobservable due to the length of the transaction, options, and transactions in locations where observable market data does not exist. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Thus, a valuation may be classified in Level 3 even though the valuation may include significant inputs that are readily observable. We maximize the use of observable inputs and minimize the use of unobservable inputs. We rely primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities. If market data is not readily available, inputs may reflect our own assumptions about the inputs market participants would use. Our assessment of the inputs and the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities as well as their placement within the fair value hierarchy levels. We assess whether a market is active by obtaining observable broker quotes, reviewing actual market activity, and assessing the volume of transactions. We consider broker quotes observable inputs when the quote is binding on the broker, we can validate the quote with market activity, or we can determine that the inputs the broker used to arrive at the quoted price are observable.
Certain instruments have been valued using the concept of NAV, as a practical expedient. These instruments are typically structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. These instruments are similar to mutual funds; however, their NAV is generally not published and publicly available, nor are these instruments traded on an exchange. Instruments valued using NAV, as a practical expedient are included in our fair value disclosures however, in accordance with GAAP are not classified within the fair value hierarchy levels.
Recurring Fair Value Measurements
We apply recurring fair value measurements to cash equivalents, derivative instruments, and investments held in the nuclear decommissioning trusts and other special use funds. On an annual basis we apply fair value measurements to plan assets held in our retirement and other benefit plans. (See Note 8 for fair value discussion of plan assets held in our retirement and other benefit plans.)
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash Equivalents
Cash equivalents represent certain investments in money market funds that are valued using quoted prices in active markets.
Risk Management Activities — Derivative Instruments
Exchange traded commodity contracts are valued using unadjusted quoted prices. For non-exchange traded commodity contracts, we calculate fair value based on the average of the bid and offer price, discounted to reflect net present value. We maintain certain valuation adjustments for a number of risks associated with the valuation of future commitments. These include valuation adjustments for liquidity and credit risks. The liquidity valuation adjustment represents the cost that would be incurred if all unmatched positions were closed out or hedged. The credit valuation adjustment represents estimated credit losses on our net exposure to counterparties, taking into account netting agreements, expected default experience for the credit rating of the counterparties and the overall diversification of the portfolio. We maintain credit policies that management believes minimize overall credit risk.
Certain non-exchange traded commodity contracts are valued based on unobservable inputs due to the long-term nature of contracts, characteristics of the product, or the unique location of the transactions. Our long-dated energy transactions consist of observable valuations for the near-term portion and unobservable valuations for the long-term portions of the transaction. We rely primarily on broker quotes to value these instruments. When our valuations utilize broker quotes, we perform various control procedures to ensure the quote has been developed consistent with fair value accounting guidance. These controls include assessing the quote for reasonableness by comparison against other broker quotes, reviewing historical price relationships, and assessing market activity. When broker quotes are not available, the primary valuation technique used to calculate the fair value is the extrapolation of forward pricing curves using observable market data for more liquid delivery points in the same region and actual transactions at more illiquid delivery points.
When the unobservable portion is significant to the overall valuation of the transaction, the entire transaction is classified as Level 3.
Investments Held in Nuclear Decommissioning Trusts and Other Special Use Funds
The nuclear decommissioning trusts and other special use funds invest in fixed income and equity securities. Other special use funds include the coal reclamation escrow account and the active union employee medical account. (See Note 19 for additional discussion about our investment accounts.)
We value investments in fixed income and equity securities using information provided by our trustees and escrow agent. Our trustees and escrow agent use pricing services that utilize the valuation methodologies described below to determine fair market value. We have internal control procedures designed to ensure this information is consistent with fair value accounting guidance. These procedures include assessing valuations using an independent pricing source, verifying that pricing can be supported by actual recent market transactions, assessing hierarchy classifications, comparing investment returns with benchmarks, and obtaining and reviewing independent audit reports on the trustees’ and escrow agent’s internal operating controls and valuation processes.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fixed Income Securities
Fixed income securities issued by the U.S. Treasury are valued using quoted active market prices and are typically classified as Level 1. Fixed income securities issued by corporations, municipalities, and other agencies, including mortgage-backed instruments, are valued using quoted inactive market prices, quoted active market prices for similar securities, or by utilizing calculations which incorporate observable inputs such as yield curves and spreads relative to such yield curves. These fixed income instruments are classified as Level 2. Whenever possible, multiple market quotes are obtained which enables a cross-check validation. A primary price source is identified based on asset type, class, or issue of securities.
Fixed income securities may also include short-term investments in certificates of deposit, variable rate notes, time deposit accounts, U.S. Treasury and Agency obligations, U.S. Treasury repurchase agreements, commercial paper, and other short term instruments. These instruments are valued using active market prices or utilizing observable inputs described above.
Equity Securities
The Nuclear Decommissioning Trust’s equity security investments are held indirectly through commingled funds. The commingled funds are valued using the funds’ NAV as a practical expedient. The funds’ NAV is primarily derived from the quoted active market prices of the underlying equity securities held by the funds. We may transact in these commingled funds on a semi-monthly basis at the NAV. The commingled funds are maintained by a bank and hold investments in accordance with the stated objective of tracking the performance of the S&P 500 Index. Because the commingled funds’ shares are offered to a limited group of investors, they are not considered to be traded in an active market. As these instruments are valued using NAV, as a practical expedient, they have not been classified within the fair value hierarchy.
The Nuclear Decommissioning Trusts and other special use funds may also hold equity securities that include exchange traded mutual funds and money market accounts for short-term liquidity purposes. These short-term, highly-liquid, investments are valued using active market prices.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair Value Tables
The following table presents the fair value at December 31, 2020 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Other
|
|
|
|
Total
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk management activities — derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
$
|
—
|
|
|
$
|
9,016
|
|
|
$
|
4
|
|
|
$
|
(4,271)
|
|
|
(a)
|
|
$
|
4,749
|
|
Nuclear decommissioning trust:
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities
|
29,796
|
|
|
—
|
|
|
—
|
|
|
(17,828)
|
|
|
(b)
|
|
11,968
|
|
U.S. commingled equity funds
|
—
|
|
|
—
|
|
|
—
|
|
|
610,055
|
|
|
(c)
|
|
610,055
|
|
U.S. Treasury debt
|
164,514
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
164,514
|
|
Corporate debt
|
—
|
|
|
149,509
|
|
|
—
|
|
|
—
|
|
|
|
|
149,509
|
|
Mortgage-backed securities
|
—
|
|
|
99,623
|
|
|
—
|
|
|
—
|
|
|
|
|
99,623
|
|
Municipal bonds
|
—
|
|
|
89,705
|
|
|
—
|
|
|
—
|
|
|
|
|
89,705
|
|
Other fixed income
|
—
|
|
|
13,061
|
|
|
—
|
|
|
—
|
|
|
|
|
13,061
|
|
Subtotal nuclear decommissioning trust
|
194,310
|
|
|
351,898
|
|
|
—
|
|
|
592,227
|
|
|
|
|
1,138,435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other special use funds:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities
|
37,337
|
|
|
—
|
|
|
—
|
|
|
504
|
|
|
(b)
|
|
37,841
|
|
U.S. Treasury debt
|
203,220
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
203,220
|
|
Municipal bonds
|
—
|
|
|
13,448
|
|
|
—
|
|
|
—
|
|
|
|
|
13,448
|
|
Subtotal other special use funds
|
240,557
|
|
|
13,448
|
|
|
—
|
|
|
504
|
|
|
|
|
254,509
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
$
|
434,867
|
|
|
$
|
374,362
|
|
|
$
|
4
|
|
|
$
|
588,460
|
|
|
|
|
$
|
1,397,693
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Risk management activities — derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
$
|
—
|
|
|
$
|
(20,498)
|
|
|
$
|
(1,107)
|
|
|
$
|
2,986
|
|
|
(a)
|
|
$
|
(18,619)
|
|
(a)Represents counterparty netting, margin, and collateral (see Note 16).
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table presents the fair value at December 31, 2019 of our assets and liabilities that are measured at fair value on a recurring basis (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Other
|
|
|
|
Total
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk management activities — derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
$
|
—
|
|
|
$
|
551
|
|
|
$
|
33
|
|
|
$
|
(69)
|
|
|
(a)
|
|
$
|
515
|
|
Nuclear decommissioning trust:
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities
|
10,872
|
|
|
—
|
|
|
—
|
|
|
2,401
|
|
|
(b)
|
|
13,273
|
|
U.S. commingled equity funds
|
—
|
|
|
—
|
|
|
—
|
|
|
518,844
|
|
|
(c)
|
|
518,844
|
|
U.S. Treasury debt
|
160,607
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
160,607
|
|
Corporate debt
|
—
|
|
|
115,869
|
|
|
—
|
|
|
—
|
|
|
|
|
115,869
|
|
Mortgage-backed securities
|
—
|
|
|
118,795
|
|
|
—
|
|
|
—
|
|
|
|
|
118,795
|
|
Municipal bonds
|
—
|
|
|
73,040
|
|
|
—
|
|
|
—
|
|
|
|
|
73,040
|
|
Other fixed income
|
—
|
|
|
10,347
|
|
|
—
|
|
|
—
|
|
|
|
|
10,347
|
|
Subtotal nuclear decommissioning trust
|
171,479
|
|
|
318,051
|
|
|
—
|
|
|
521,245
|
|
|
|
|
1,010,775
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other special use funds:
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities
|
7,142
|
|
|
—
|
|
|
—
|
|
|
474
|
|
|
(b)
|
|
7,616
|
|
U.S. Treasury debt
|
232,848
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
|
232,848
|
|
Municipal bonds
|
—
|
|
|
4,631
|
|
|
—
|
|
|
—
|
|
|
|
|
4,631
|
|
Subtotal other special use funds
|
239,990
|
|
|
4,631
|
|
|
—
|
|
|
474
|
|
|
|
|
245,095
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
$
|
411,469
|
|
|
$
|
323,233
|
|
|
$
|
33
|
|
|
$
|
521,650
|
|
|
|
|
$
|
1,256,385
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
Risk management activities — derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
$
|
—
|
|
|
$
|
(67,992)
|
|
|
$
|
(3,429)
|
|
|
$
|
(711)
|
|
|
(a)
|
|
$
|
(72,132)
|
|
(a)Represents counterparty netting, margin, and collateral (see Note 16).
(b)Represents net pending securities sales and purchases.
(c)Valued using NAV as a practical expedient and, therefore, are not classified in the fair value hierarchy.
Fair Value Measurements Classified as Level 3
The significant unobservable inputs used in the fair value measurement of our energy derivative contracts include broker quotes that cannot be validated as an observable input primarily due to the long-term nature of the quote, or other characteristics of the product. Significant changes in these inputs in isolation would result in significantly higher or lower fair value measurements. Changes in our derivative contract fair values, including changes relating to unobservable inputs, typically will not impact net income due to regulatory accounting treatment (see Note 4).
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Because our forward commodity contracts classified as Level 3 are currently in a net purchase position, we would expect price increases of the underlying commodity to result in increases in the net fair value of the related contracts. Conversely, if the price of the underlying commodity decreases, the net fair value of the related contracts would likely decrease.
Other unobservable valuation inputs include credit and liquidity reserves which do not have a material impact on our valuations; however, significant changes in these inputs could also result in higher or lower fair value measurements.
Financial Instruments Not Carried at Fair Value
The carrying value of our short-term borrowings approximate fair value and are classified within Level 2 of the fair value hierarchy. (See Note 7 for our long-term debt fair values.) The NTEC note receivable related to the sale of 4CA’s interest in Four Corners bears interest at 3.9% per annum and has a book value of $27.1 million as of December 31, 2020, as presented on the Consolidated Balance Sheets. The carrying amount is not materially different from the fair value of the note receivable and is classified within Level 3 of the fair value hierarchy. (See Note 11 for more information on 4CA matters.)
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
14. Earnings Per Share
The following table presents the calculation of Pinnacle West’s basic and diluted earnings per share (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
Net income attributable to common shareholders
|
$
|
550,559
|
|
|
$
|
538,320
|
|
|
$
|
511,047
|
|
Weighted average common shares outstanding — basic
|
112,666
|
|
|
112,443
|
|
|
112,129
|
|
Net effect of dilutive securities:
|
|
|
|
|
|
Contingently issuable performance shares and restricted stock units
|
276
|
|
|
315
|
|
|
421
|
|
Weighted average common shares outstanding — diluted
|
112,942
|
|
|
112,758
|
|
|
112,550
|
|
Earnings per weighted-average common share outstanding
|
|
|
|
|
|
Net income attributable to common shareholders — basic
|
$
|
4.89
|
|
|
$
|
4.79
|
|
|
$
|
4.56
|
|
Net income attributable to common shareholders — diluted
|
$
|
4.87
|
|
|
$
|
4.77
|
|
|
$
|
4.54
|
|
15. Stock-Based Compensation
Pinnacle West has incentive compensation plans under which stock-based compensation is granted to officers, key-employees, and non-officer members of the Board of Directors. Awards granted under the 2012 Long-Term Incentive Plan (“2012 Plan”) may be in the form of stock grants, restricted stock units, stock units, performance shares, restricted stock, dividend equivalents, performance share units, performance cash, incentive and non-qualified stock options, and stock appreciation rights. The 2012 Plan authorizes up to 4.6 million common shares to be available for grant. As of December 31, 2020, 1.5 million common shares were available for issuance under the 2012 Plan. During 2020, 2019, and 2018, the Company granted awards in the form of restricted stock units, stock units, stock grants, and performance shares. Awards granted from 2007 to 2011 were issued under the 2007 Long-Term Incentive Plan (“2007 Plan”), and no new awards may be granted under the 2007 Plan.
Stock-Based Compensation Expense and Activity
Compensation cost included in net income for stock-based compensation plans was $18 million in 2020, $18 million in 2019, and $20 million in 2018. The compensation cost capitalized is immaterial for all years. Income tax benefits related to stock-based compensation arrangements were $4 million in 2020, $7 million in 2019, and $7 million in 2018.
As of December 31, 2020, there were approximately $9 million of unrecognized compensation costs related to nonvested stock-based compensation arrangements. We expect to recognize these costs over a weighted-average period of 2 years.
The total fair value of shares vested was $22 million in 2020, $21 million in 2019 and $24 million in 2018.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table is a summary of awards granted and the weighted-average grant date fair value for the three years ended 2020, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Stock Units, Stock Grants, and Stock Units (a)
|
|
Performance Shares (b)
|
|
2020
|
|
2019
|
|
2018
|
|
2020
|
|
2019
|
|
2018
|
Units granted
|
118,403
|
|
|
109,106
|
|
|
132,997
|
|
|
122,830
|
|
|
142,874
|
|
|
171,708
|
|
Weighted-average grant date fair value
|
$
|
71.70
|
|
|
$
|
89.15
|
|
|
$
|
77.51
|
|
|
$
|
104.74
|
|
|
$
|
92.16
|
|
|
$
|
76.56
|
|
(a)Units granted includes awards that will be cash settled of 45,646 in 2020, 48,972 in 2019, and 66,252 in 2018.
(b)Reflects the target payout level.
The following table is a summary of the status of non-vested awards as of December 31, 2020 and changes during the year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Stock Units, Stock Grants, and Stock Units
|
|
Performance Shares
|
|
Shares
|
|
Weighted-Average
Grant Date
Fair Value
|
|
Shares (b)
|
|
Weighted-Average
Grant Date
Fair Value
|
Nonvested at January 1, 2020
|
242,612
|
|
|
$
|
81.38
|
|
|
306,970
|
|
|
$
|
83.65
|
|
Granted
|
118,403
|
|
|
71.70
|
|
|
122,830
|
|
|
104.74
|
|
Vested
|
(136,893)
|
|
|
73.80
|
|
|
(161,906)
|
|
|
76.53
|
|
Forfeited (c)
|
(3,565)
|
|
|
82.61
|
|
|
(7,890)
|
|
|
85.06
|
|
Nonvested at December 31, 2020
|
220,557
|
|
(a)
|
77.93
|
|
|
260,004
|
|
|
98.28
|
|
Vested Awards Outstanding at December 31, 2020
|
82,921
|
|
|
|
|
161,906
|
|
|
|
(a)Includes 126,996 of awards that will be cash settled.
(b)The nonvested performance shares are reflected at target payout level.
(c)We account for forfeitures as they occur.
Share-based liabilities paid relating to restricted stock units were $6 million, $5 million and $4 million in 2020, 2019 and 2018, respectively. This includes cash used to settle restricted stock units of $4 million, $5 million and $5 million in 2020, 2019 and 2018, respectively. Restricted stock units that are cash settled are classified as liability awards. All performance shares are classified as equity awards.
Restricted Stock Units, Stock Grants, and Stock Units
Restricted stock units are granted to officers and key employees. Restricted stock units typically vest and settle in equal annual installments over a 4-year period after the grant date. Vesting is typically dependent upon continuous service during the vesting period; however, awards granted to retirement-eligible employees will vest upon the employee’s retirement. Awardees elect to receive payment in either 100% stock, 100% cash, or 50% in cash and 50% in stock. Restricted stock unit awards typically include a
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
dividend equivalent feature. This feature allows each award to accrue dividend rights equal to the dividends they would have received had they directly owned the stock. Interest on dividend rights compounds quarterly. If the award is forfeited the employee is not entitled to the dividends on those shares.
Compensation cost for restricted stock unit awards is based on the fair value of the award, with the fair value being the market price of our stock on the measurement date. Restricted stock unit awards that will be settled in cash are accounted for as liability awards, with compensation cost initially calculated on the date of grant using the Company’s closing stock price, and remeasured at each balance sheet date. Restricted stock unit awards that will be settled in shares are accounted for as equity awards, with compensation cost calculated using the Company’s closing stock price on the date of grant. Compensation cost is recognized over the requisite service period based on the fair value of the award.
Stock grants are issued to non-officer members of the Board of Directors. They may elect to receive the stock grant, or to defer receipt until a later date and receive stock units in lieu of the stock grant. The members of the Board of Directors who elect to defer may elect to receive payment in either 100% stock, 100% cash, or 50% in cash and 50% in stock. Each stock unit is convertible to one share of stock. The stock units accrue dividend rights, equal to the amount of dividends the Directors would have received had they directly owned stock equal to the number of vested restricted stock units or stock units from the date of grant to the date of payment, plus interest compounded quarterly. The dividends and interest are paid, based on the Director’s election, in either stock, cash, or 50% in cash and 50% in stock.
Performance Share Awards
Performance share awards are granted to officers and key employees. The awards contain two separate performance criteria that affect the number of shares that may be received if after the end of a 3-year performance period the performance criteria are met. For the first criteria, the number of shares that will vest is based on non-financial performance metrics (i.e., the metric component). The other criteria is based upon Pinnacle West’s total shareholder return (“TSR”) in relation to the TSR of other companies in a specified utility index (i.e., the TSR component). The exact number of shares issued will vary from 0% to 200% of the target award. Shares received include dividend rights paid in stock equal to the amount of dividends that recipients would have received had they directly owned stock, equal to the number of vested performance shares from the date of grant to the date of payment plus interest compounded quarterly. If the award is forfeited or if the performance criteria are not achieved, the employee is not entitled to the dividends on those shares.
Performance share awards are accounted for as equity awards, with compensation cost based on the fair value of the award on the grant date. Compensation cost relating to the metric component of the award is based on the Company’s closing stock price on the date of grant, with compensation cost recognized over the requisite service period based on the number of shares expected to vest. Management evaluates the probability of meeting the metric component at each balance sheet date. If the metric component criteria are not ultimately achieved, no compensation cost is recognized relating to the metric component, and any previously recognized compensation cost is reversed. Compensation cost relating to the TSR component of the award is determined using a Monte Carlo simulation valuation model, with compensation cost recognized ratably over the requisite service period, regardless of the number of shares that actually vest.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
16. Derivative Accounting
Derivative financial instruments are used to manage exposure to commodity price and transportation costs of electricity, natural gas, coal, emissions allowances and interest rates. Risks associated with market volatility are managed by utilizing various physical and financial derivative instruments, including futures, forwards, options and swaps. As part of our overall risk management program, we may use derivative instruments to hedge purchases and sales of electricity and natural gas. Derivative instruments that meet certain hedge accounting criteria may be designated as cash flow hedges and are used to limit our exposure to cash flow variability on forecasted transactions. The changes in market value of such instruments have a high correlation to price changes in the hedged transactions. Derivative instruments are also entered into for economic hedging purposes. While economic hedges may mitigate exposure to fluctuations in commodity prices, these instruments have not been designated as accounting hedges. Contracts that have the same terms (quantities, delivery points and delivery periods) and for which power does not flow are netted, which reduces both revenues and fuel and purchased power costs in our Consolidated Statements of Income, but does not impact our financial condition, net income or cash flows.
Our derivative instruments, excluding those qualifying for a scope exception, are recorded on the balance sheet as an asset or liability and are measured at fair value. (See Note 13 for a discussion of fair value measurements.) Derivative instruments may qualify for the normal purchases and normal sales scope exception if they require physical delivery and the quantities represent those transacted in the normal course of business. Derivative instruments qualifying for the normal purchases and sales scope exception are accounted for under the accrual method of accounting and excluded from our derivative instrument discussion and disclosures below.
For its regulated operations, APS defers for future rate treatment 100% of the unrealized gains and losses on derivatives pursuant to the PSA mechanism that would otherwise be recognized in income. Realized gains and losses on derivatives are deferred in accordance with the PSA to the extent the amounts are above or below the Base Fuel Rate (see Note 4). Gains and losses from derivatives in the following tables represent the amounts reflected in income before the effect of PSA deferrals.
The following table shows the outstanding gross notional volume of derivatives, which represent both purchases and sales (does not reflect net position):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantity
|
Commodity
|
|
Unit of Measure
|
December 31, 2020
|
|
December 31, 2019
|
Power
|
|
GWh
|
368
|
|
|
193
|
|
Gas
|
|
Billion cubic feet
|
205
|
|
|
257
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Gains and Losses from Derivative Instruments
The following table provides information about APS’s gains and losses from derivative instruments in designated cash flow accounting hedging relationships (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Statement
|
|
Year Ended
December 31,
|
Commodity Contracts
|
|
Location
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
|
|
|
Loss Reclassified from Accumulated OCI into Income (Effective Portion Realized) (a)
|
|
Fuel and purchased power (b)
|
|
(763)
|
|
|
(1,512)
|
|
|
(2,000)
|
|
|
|
|
|
|
|
|
|
|
(a)During the years ended December 31, 2020, 2019, and 2018, we had no gains or losses reclassified from accumulated OCI to earnings related to discontinued cash flow hedges.
(b)Amounts are before the effect of PSA deferrals.
During the next twelve months, we estimate that no amounts will be reclassified from accumulated OCI into income. For APS, the delivery period for all derivative instruments in designated cash flow accounting hedging relationships have lapsed.
The following table provides information about gains and losses from derivative instruments not designated as accounting hedging instruments (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Statement
|
|
Year Ended
December 31,
|
Commodity Contracts
|
|
Location
|
|
2020
|
|
2019
|
|
2018
|
Net Loss Recognized in Income
|
|
Operating revenues
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2,557)
|
|
Net Loss Recognized in Income
|
|
Fuel and purchased power (a)
|
|
(3,178)
|
|
|
(84,953)
|
|
|
(12,951)
|
|
Total
|
|
|
|
$
|
(3,178)
|
|
|
$
|
(84,953)
|
|
|
$
|
(15,508)
|
|
(a)Amounts are before the effect of PSA deferrals.
Derivative Instruments in the Consolidated Balance Sheets
Our derivative transactions are typically executed under standardized or customized agreements, which include collateral requirements and, in the event of a default, would allow for the netting of positive and negative exposures associated with a single counterparty. Agreements that allow for the offsetting of positive and negative exposures associated with a single counterparty are considered master netting arrangements. Transactions with counterparties that have master netting arrangements are offset and reported net on the Consolidated Balance Sheets. Transactions that do not allow for offsetting of positive and negative positions are reported gross on the Consolidated Balance Sheets.
We do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our master netting arrangements would allow current and non-current positions to be offset in the event of a default. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, trade receivables and trade payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented below.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following tables provide information about the fair value of our risk management activities reported on a gross basis and the impacts of offsetting. These amounts relate to commodity contracts and are located in the assets and liabilities from risk management activities lines of our Consolidated Balance Sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2020:
(dollars in thousands)
|
|
Gross
Recognized
Derivatives
(a)
|
|
Amounts
Offset
(b)
|
|
Net
Recognized
Derivatives
|
|
Other
(c)
|
|
Amount
Reported on
Balance Sheet
|
Current assets
|
|
$
|
5,870
|
|
|
$
|
(2,939)
|
|
|
$
|
2,931
|
|
|
$
|
—
|
|
|
$
|
2,931
|
|
Investments and other assets
|
|
3,150
|
|
|
(1,332)
|
|
|
1,818
|
|
|
—
|
|
|
1,818
|
|
Total assets
|
|
9,020
|
|
|
(4,271)
|
|
|
4,749
|
|
|
—
|
|
|
4,749
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
(9,211)
|
|
|
2,939
|
|
|
(6,272)
|
|
|
(1,285)
|
|
|
(7,557)
|
|
Deferred credits and other
|
|
(12,394)
|
|
|
1,332
|
|
|
(11,062)
|
|
|
—
|
|
|
(11,062)
|
|
Total liabilities
|
|
(21,605)
|
|
|
4,271
|
|
|
(17,334)
|
|
|
(1,285)
|
|
|
(18,619)
|
|
Total
|
|
$
|
(12,585)
|
|
|
$
|
—
|
|
|
$
|
(12,585)
|
|
|
$
|
(1,285)
|
|
|
$
|
(13,870)
|
|
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,285.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2019:
(dollars in thousands)
|
|
Gross
Recognized
Derivatives
(a)
|
|
Amounts
Offset
(b)
|
|
Net
Recognized
Derivatives
|
|
Other
(c)
|
|
Amount
Reported on
Balance Sheet
|
Current assets
|
|
$
|
584
|
|
|
$
|
(474)
|
|
|
$
|
110
|
|
|
$
|
405
|
|
|
$
|
515
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
(38,235)
|
|
|
474
|
|
|
(37,761)
|
|
|
(1,185)
|
|
|
(38,946)
|
|
Deferred credits and other
|
|
(33,186)
|
|
|
—
|
|
|
(33,186)
|
|
|
—
|
|
|
(33,186)
|
|
Total liabilities
|
|
(71,421)
|
|
|
474
|
|
|
(70,947)
|
|
|
(1,185)
|
|
|
(72,132)
|
|
Total
|
|
$
|
(70,837)
|
|
|
$
|
—
|
|
|
$
|
(70,837)
|
|
|
$
|
(780)
|
|
|
$
|
(71,617)
|
|
(a)All of our gross recognized derivative instruments were subject to master netting arrangements.
(b)No cash collateral has been provided to counterparties, or received from counterparties, that is subject to offsetting.
(c)Represents cash collateral and cash margin that is not subject to offsetting. Amounts relate to non-derivative instruments, derivatives qualifying for scope exceptions, or collateral and margin posted in excess of the recognized derivative instrument. Includes cash collateral received from counterparties of $1,185 and cash margin provided to counterparties of $405.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Credit Risk and Credit Related Contingent Features
We are exposed to losses in the event of nonperformance or nonpayment by counterparties and have risk management contracts with many counterparties. As of December 31, 2020, we have four counterparties for which our exposure represents approximately 62% of Pinnacle West’s $5 million of risk management assets. This exposure relates to master agreements with counterparties and all four are rated as investment grade. Our risk management process assesses and monitors the financial exposure of all counterparties. Despite the fact that the great majority of our trading counterparties' debt is rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these counterparties could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
Certain of our derivative instrument contracts contain credit-risk-related contingent features including, among other things, investment grade credit rating provisions, credit-related cross-default provisions, and adequate assurance provisions. Adequate assurance provisions allow a counterparty with reasonable grounds for uncertainty to demand additional collateral based on subjective events and/or conditions. For those derivative instruments in a net liability position, with investment grade credit contingencies, the counterparties could demand additional collateral if our debt credit rating were to fall below investment grade (below BBB- for Standard & Poor’s or Fitch or Baa3 for Moody’s).
The following table provides information about our derivative instruments that have credit-risk-related contingent features (dollars in thousands):
|
|
|
|
|
|
|
December 31, 2020
|
Aggregate fair value of derivative instruments in a net liability position
|
$
|
21,605
|
|
Cash collateral posted
|
—
|
|
Additional cash collateral in the event credit-risk related contingent features were fully triggered (a)
|
19,510
|
|
(a)This amount is after counterparty netting and includes those contracts which qualify for scope exceptions, which are excluded from the derivative details above.
We also have energy related non-derivative instrument contracts with investment grade credit-related contingent features, which could also require us to post additional collateral of approximately $90 million if our debt credit ratings were to fall below investment grade.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
17. Other Income and Other Expense
The following table provides detail of Pinnacle West’s Consolidated other income and other expense for 2020, 2019 and 2018 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
Other income:
|
|
|
|
|
|
Interest income
|
$
|
12,210
|
|
|
$
|
10,377
|
|
|
$
|
8,647
|
|
Investment gains (losses) — net
|
2,358
|
|
|
—
|
|
|
—
|
|
Debt return on Four Corners SCR deferral (Note 4)
|
26,121
|
|
|
19,541
|
|
|
16,153
|
|
Debt return on Ocotillo modernization project (Note 4)
|
15,865
|
|
|
20,282
|
|
|
—
|
|
Miscellaneous
|
149
|
|
|
63
|
|
|
96
|
|
Total other income
|
$
|
56,703
|
|
|
$
|
50,263
|
|
|
$
|
24,896
|
|
Other expense:
|
|
|
|
|
|
Non-operating costs
|
$
|
(12,400)
|
|
|
$
|
(10,663)
|
|
|
$
|
(10,076)
|
|
Investment gains (losses) — net
|
—
|
|
|
(1,835)
|
|
|
(417)
|
|
Miscellaneous
|
(45,376)
|
|
(a)
|
(5,382)
|
|
|
(7,473)
|
|
Total other expense
|
$
|
(57,776)
|
|
|
$
|
(17,880)
|
|
|
$
|
(17,966)
|
|
(a)Miscellaneous includes donation of approximately $10 million to the APS Foundation and approximately $25.2 million related to the CCT plan (see Note 4).
Other Income and Other Expense - APS
The following table provides detail of APS’s other income and other expense for 2020, 2019 and 2018 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
2019
|
|
2018
|
Other income:
|
|
|
|
|
|
Interest income
|
$
|
9,621
|
|
|
$
|
6,998
|
|
|
$
|
6,496
|
|
Debt return on Four Corners SCR deferral (Note 4)
|
26,121
|
|
|
19,541
|
|
|
16,153
|
|
Debt return on Ocotillo modernization project (Note 4)
|
15,865
|
|
|
20,282
|
|
|
—
|
|
Miscellaneous
|
148
|
|
|
63
|
|
|
97
|
|
Total other income
|
$
|
51,755
|
|
|
$
|
46,884
|
|
|
$
|
22,746
|
|
Other expense:
|
|
|
|
|
|
Non-operating costs
|
$
|
(10,659)
|
|
|
$
|
(9,612)
|
|
|
$
|
(9,462)
|
|
|
|
|
|
|
|
Miscellaneous
|
(43,035)
|
|
(a)
|
(3,378)
|
|
|
(5,830)
|
|
Total other expense
|
$
|
(53,694)
|
|
|
$
|
(12,990)
|
|
|
$
|
(15,292)
|
|
(a)Miscellaneous includes donations of approximately $10 million to the APS Foundation and approximately $25.2 million related to the CCT plan (see Note 4).
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
18. Palo Verde Sale Leaseback Variable Interest Entities
In 1986, APS entered into agreements with three separate VIE lessor trust entities in order to sell and lease back interests in Palo Verde Unit 2 and related common facilities. APS will retain the assets through 2023 under one lease and 2033 under the other two leases. APS will be required to make payments relating to these leases of approximately $23 million annually for the period 2021 through 2023, and about $16 million annually for the period 2024 through 2033. At the end of the lease period, APS will have the option to purchase the leased assets at their fair market value, extend the leases for up to two years, or return the assets to the lessors.
The leases’ terms give APS the ability to utilize the assets for a significant portion of the assets’ economic life, and therefore provide APS with the power to direct activities of the VIEs that most significantly impact the VIEs’ economic performance. Predominantly due to the lease terms, APS has been deemed the primary beneficiary of these VIEs and therefore consolidates the VIEs.
As a result of consolidation, we eliminate lease accounting and instead recognize depreciation expense, resulting in an increase in net income of $19 million for 2020, 2019 and 2018. The increase in net income is entirely attributable to the noncontrolling interests. Income attributable to Pinnacle West shareholders is not impacted by the consolidation.
Our Consolidated Balance Sheets include the following amounts relating to the VIEs (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
December 31, 2019
|
Palo Verde sale leaseback property, plant and equipment, net of accumulated depreciation
|
$
|
98,036
|
|
|
$
|
101,906
|
|
Equity-Noncontrolling interests
|
119,290
|
|
|
122,540
|
|
Assets of the VIEs are restricted and may only be used for payment to the noncontrolling interest holders. These assets are reported on our consolidated financial statements.
APS is exposed to losses relating to these VIEs upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to make specified payments to the VIEs’ noncontrolling equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event were to occur during the lease periods, APS may be required to pay the noncontrolling equity participants approximately $306 million beginning in 2021, and up to $456 million over the lease extension terms.
For regulatory ratemaking purposes, the agreements continue to be treated as operating leases and, as a result, we have recorded a regulatory asset relating to the arrangements.
19. Investments in Nuclear Decommissioning Trusts and Other Special Use Funds
We have investments in debt and equity securities held in Nuclear Decommissioning Trusts, Coal Reclamation Escrow Accounts, and an Active Union Employee Medical Account. Investments in debt securities are classified as available-for-sale securities. We record both debt and equity security
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
investments at their fair value on our Consolidated Balance Sheets. (See Note 13 for a discussion of how fair value is determined and the classification of the investments within the fair value hierarchy.) The investments in each trust or account are restricted for use and are intended to fund specified costs and activities as further described for each fund below.
Nuclear Decommissioning Trusts — APS established external decommissioning trusts in accordance with NRC regulations to fund the future costs APS expects to incur to decommission Palo Verde. Third-party investment managers are authorized to buy and sell securities per stated investment guidelines. The trust funds are invested in fixed income securities and equity securities. Earnings and proceeds from sales and maturities of securities are reinvested in the trusts. Because of the ability of APS to recover decommissioning costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities.
Coal Reclamation Escrow Account — APS has investments restricted for the future coal mine reclamation funding related to Four Corners. This escrow account is primarily invested in fixed income securities. Earnings and proceeds from sales of securities are reinvested in the escrow account. Because of the ability of APS to recover coal reclamation costs in rates, and in accordance with the regulatory treatment, APS has deferred realized and unrealized gains and losses (including credit losses) in other regulatory liabilities. Activities relating to APS coal reclamation escrow account investments are included within the other special use funds in the table below.
Active Union Employee Medical Account — APS has investments restricted for paying active union employee medical costs. These investments may be used to pay active union employee medical costs incurred in the current and future periods. In 2020 and 2019, APS was reimbursed $14 million and $15 million, respectively, for prior year active union employee medical claims from the active union employee medical account. The account is invested primarily in fixed income securities. In accordance with the ratemaking treatment, APS has deferred the unrealized gains and losses (including credit losses) in other regulatory liabilities. Activities relating to active union employee medical account investments are included within the other special use funds in the tables below. On January 4, 2021, an additional $106 million of investments were transferred from APS other postretirement benefit trust assets into the active union employee medical account (see Note 8).
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
APS
The following tables present the unrealized gains and losses based on the original cost of the investment and summarizes the fair value of APS’s nuclear decommissioning trust and other special use fund assets at December 31, 2020 and December 31, 2019 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
|
Fair Value
|
|
Total
Unrealized
Gains
|
|
Total
Unrealized
Losses
|
Investment Type:
|
Nuclear Decommissioning Trusts
|
|
Other Special Use Funds
|
|
Total
|
|
|
Equity Securities
|
$
|
639,851
|
|
|
$
|
37,337
|
|
|
$
|
677,188
|
|
|
$
|
421,666
|
|
|
$
|
—
|
|
Available for Sale-Fixed Income Securities
|
516,412
|
|
|
216,668
|
|
|
733,080
|
|
(a)
|
46,581
|
|
|
(398)
|
|
Other
|
(17,828)
|
|
|
504
|
|
|
(17,324)
|
|
(b)
|
—
|
|
|
—
|
|
Total
|
$
|
1,138,435
|
|
|
$
|
254,509
|
|
|
$
|
1,392,944
|
|
|
$
|
468,247
|
|
|
$
|
(398)
|
|
(a)As of December 31, 2020, the amortized cost basis of these available-for-sale investments is $687 million.
(b)Represents net pending securities sales and purchases.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
Fair Value
|
|
Total
Unrealized
Gains
|
|
Total
Unrealized
Losses
|
Investment Type:
|
Nuclear Decommissioning Trusts
|
|
Other Special Use Funds
|
|
Total
|
|
|
Equity Securities
|
$
|
529,716
|
|
|
$
|
7,142
|
|
|
$
|
536,858
|
|
|
$
|
337,681
|
|
|
$
|
—
|
|
Available for Sale-Fixed Income Securities
|
478,658
|
|
|
237,479
|
|
|
716,137
|
|
(a)
|
25,795
|
|
|
(669)
|
|
Other
|
2,401
|
|
|
474
|
|
|
2,875
|
|
(b)
|
—
|
|
|
—
|
|
Total
|
$
|
1,010,775
|
|
|
$
|
245,095
|
|
|
$
|
1,255,870
|
|
|
$
|
363,476
|
|
|
$
|
(669)
|
|
(a)As of December 31, 2019, the amortized cost basis of these available-for-sale investments is $691 million.
(b)Represents net pending securities sales and purchases.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth APS’s realized gains and losses relating to the sale and maturity of available-for-sale debt securities and equity securities, and the proceeds from the sale and maturity of these investment securities for the years ended December 31, 2020, 2019 and 2018 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Nuclear Decommissioning Trusts
|
|
Other Special Use Funds
|
|
Total
|
2020
|
|
|
|
|
|
Realized gains
|
$
|
12,194
|
|
|
$
|
176
|
|
|
$
|
12,370
|
|
Realized losses
|
(5,553)
|
|
|
(15)
|
|
|
(5,568)
|
|
Proceeds from the sale of securities (a)
|
675,035
|
|
|
144,484
|
|
|
819,519
|
|
2019
|
|
|
|
|
|
Realized gains
|
11,024
|
|
|
108
|
|
|
11,132
|
|
Realized losses
|
(6,972)
|
|
|
—
|
|
|
(6,972)
|
|
Proceeds from the sale of securities (a)
|
473,806
|
|
|
245,228
|
|
|
719,034
|
|
2018
|
|
|
|
|
|
Realized gains
|
6,679
|
|
|
1
|
|
|
6,680
|
|
Realized losses
|
(13,552)
|
|
|
—
|
|
|
(13,552)
|
|
Proceeds from the sale of securities (a)
|
554,385
|
|
|
98,648
|
|
|
653,033
|
|
(a)Proceeds are reinvested in the nuclear decommissioning trusts or other special use funds, excluding amounts reimbursed to the Company for active union employee medical claims from the active union trust.
Fixed Income Securities Contractual Maturities
The fair value of fixed income securities, summarized by contractual maturities, at December 31, 2020 is as follows (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear Decommissioning Trusts
|
|
Coal Reclamation Escrow Account
|
|
Active Union Medical Trust
|
|
Total
|
Less than one year
|
$
|
19,563
|
|
|
$
|
33,079
|
|
|
$
|
—
|
|
|
$
|
52,642
|
|
1 year – 5 years
|
151,537
|
|
|
29,722
|
|
|
142,311
|
|
|
323,570
|
|
5 years – 10 years
|
133,307
|
|
|
2,738
|
|
|
—
|
|
|
136,045
|
|
Greater than 10 years
|
212,005
|
|
|
8,818
|
|
|
—
|
|
|
220,823
|
|
Total
|
$
|
516,412
|
|
|
$
|
74,357
|
|
|
$
|
142,311
|
|
|
$
|
733,080
|
|
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
20. Changes in Accumulated Other Comprehensive Loss
The following table shows the changes in Pinnacle West’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2020 and 2019 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and Other Postretirement Benefits
|
|
|
|
Derivative Instruments
|
|
|
|
Total
|
Balance at December 31, 2018
|
$
|
(45,997)
|
|
|
|
|
$
|
(1,711)
|
|
|
|
|
$
|
(47,708)
|
|
OCI (loss) before reclassifications
|
(14,041)
|
|
|
|
|
—
|
|
|
|
|
(14,041)
|
|
Amounts reclassified from accumulated other comprehensive loss
|
3,516
|
|
|
(a)
|
|
1,137
|
|
|
(b)
|
|
4,653
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2019
|
(56,522)
|
|
|
|
|
(574)
|
|
|
|
|
(57,096)
|
|
OCI (loss) before reclassifications
|
(8,370)
|
|
|
|
|
(2,089)
|
|
|
|
|
(10,459)
|
|
Amounts reclassified from accumulated other comprehensive loss
|
4,167
|
|
|
(a)
|
|
592
|
|
|
(b)
|
|
4,759
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2020
|
$
|
(60,725)
|
|
|
|
|
$
|
(2,071)
|
|
|
|
|
$
|
(62,796)
|
|
(a)These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost (see Note 8).
(b)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA (see Note 16).
Changes in Accumulated Other Comprehensive Loss — APS
The following table shows the changes in APS’s consolidated accumulated other comprehensive loss, including reclassification adjustments, net of tax, by component for the years ended December 31, 2020 and 2019 (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and Other Postretirement Benefits
|
|
|
|
Derivative Instruments
|
|
|
|
Total
|
Balance at December 31, 2018
|
$
|
(25,396)
|
|
|
|
|
$
|
(1,711)
|
|
|
|
|
$
|
(27,107)
|
|
OCI (loss) before reclassifications
|
(12,572)
|
|
|
|
|
—
|
|
|
|
|
(12,572)
|
|
Amounts reclassified from accumulated other comprehensive loss
|
3,020
|
|
|
(a)
|
|
1,137
|
|
|
(b)
|
|
4,157
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2019
|
(34,948)
|
|
|
|
|
(574)
|
|
|
|
|
(35,522)
|
|
OCI (loss) before reclassifications
|
(9,568)
|
|
|
|
|
(18)
|
|
|
|
|
(9,586)
|
|
Amounts reclassified from accumulated other comprehensive loss
|
3,598
|
|
|
(a)
|
|
592
|
|
|
(b)
|
|
4,190
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2020
|
$
|
(40,918)
|
|
|
|
|
$
|
—
|
|
|
|
|
$
|
(40,918)
|
|
(a)These amounts primarily represent amortization of actuarial loss, and are included in the computation of net periodic pension cost (see Note 8).
(b)These amounts represent realized gains and losses and are included in the computation of fuel and purchased power costs and are subject to the PSA (see Note 16).
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
|
|
|
|
|
|
Operating expenses
|
$
|
7,901
|
|
|
$
|
12,451
|
|
|
$
|
53,844
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
Equity in earnings of subsidiaries
|
566,147
|
|
|
562,946
|
|
|
569,249
|
|
Other expense
|
(4,586)
|
|
|
(3,957)
|
|
|
(3,202)
|
|
Total
|
561,561
|
|
|
558,989
|
|
|
566,047
|
|
Interest expense
|
14,021
|
|
|
15,069
|
|
|
12,074
|
|
Income before income taxes
|
539,639
|
|
|
531,469
|
|
|
500,129
|
|
Income tax benefit
|
(10,920)
|
|
|
(6,851)
|
|
|
(10,918)
|
|
Net income attributable to common shareholders
|
550,559
|
|
|
538,320
|
|
|
511,047
|
|
Other comprehensive income (loss) — attributable to common shareholders
|
(5,700)
|
|
|
(9,388)
|
|
|
5,846
|
|
Total comprehensive income — attributable to common shareholders
|
$
|
544,859
|
|
|
$
|
528,932
|
|
|
$
|
516,893
|
|
See Combined Notes to Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2020
|
|
2019
|
ASSETS
|
|
|
|
Current assets
|
|
|
|
Cash and cash equivalents
|
$
|
19
|
|
|
$
|
19
|
|
Accounts receivable
|
123,980
|
|
|
104,640
|
|
|
|
|
|
Income tax receivable
|
14,719
|
|
|
15,905
|
|
Other current assets
|
298
|
|
|
401
|
|
Total current assets
|
139,016
|
|
|
120,965
|
|
Investments and other assets
|
|
|
|
Investments in subsidiaries
|
6,400,339
|
|
|
6,067,957
|
|
Deferred income taxes
|
7,589
|
|
|
40,757
|
|
Other assets
|
52,595
|
|
|
50,139
|
|
Total investments and other assets
|
6,460,523
|
|
|
6,158,853
|
|
Total Assets
|
$
|
6,599,539
|
|
|
$
|
6,279,818
|
|
LIABILITIES AND EQUITY
|
|
|
|
Current liabilities
|
|
|
|
Accounts payable
|
$
|
5,669
|
|
|
$
|
7,634
|
|
Accrued taxes
|
16,998
|
|
|
8,573
|
|
Common dividends payable
|
93,531
|
|
|
87,982
|
|
Short-term borrowings
|
169,000
|
|
|
114,675
|
|
Current maturities of long-term debt
|
—
|
|
|
450,000
|
|
Operating lease liabilities
|
90
|
|
|
81
|
|
Other current liabilities
|
15,306
|
|
|
15,126
|
|
Total current liabilities
|
300,594
|
|
|
684,071
|
|
|
|
|
|
Long-term debt less current maturities (Note 7)
|
496,321
|
|
|
(575)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension liabilities
|
17,541
|
|
|
17,942
|
|
Operating lease liabilities
|
1,683
|
|
|
1,780
|
|
Other
|
30,607
|
|
|
23,412
|
|
Total deferred credits and other
|
49,831
|
|
|
43,134
|
|
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
|
|
|
|
Common stock equity
|
|
|
|
Common stock
|
2,671,193
|
|
|
2,650,134
|
|
Accumulated other comprehensive loss
|
(62,796)
|
|
|
(57,096)
|
|
Retained earnings
|
3,025,106
|
|
|
2,837,610
|
|
Total Pinnacle West Shareholders’ equity
|
5,633,503
|
|
|
5,430,648
|
|
Noncontrolling interests
|
119,290
|
|
|
122,540
|
|
Total Equity
|
5,752,793
|
|
|
5,553,188
|
|
Total Liabilities and Equity
|
$
|
6,599,539
|
|
|
$
|
6,279,818
|
|
See Combined Notes to Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(dollars in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2020
|
|
2019
|
|
2018
|
Cash flows from operating activities
|
|
|
|
|
|
Net income
|
$
|
550,559
|
|
|
$
|
538,320
|
|
|
$
|
511,047
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
Equity in earnings of subsidiaries — net
|
(566,147)
|
|
|
(562,946)
|
|
|
(569,249)
|
|
Depreciation and amortization
|
76
|
|
|
76
|
|
|
76
|
|
Deferred income taxes
|
33,007
|
|
|
(35,831)
|
|
|
49,535
|
|
Accounts receivable
|
(7,903)
|
|
|
182
|
|
|
(7,881)
|
|
Accounts payable
|
(1,964)
|
|
|
(2,129)
|
|
|
1,967
|
|
Accrued taxes and income tax receivables — net
|
9,610
|
|
|
16,400
|
|
|
(13,535)
|
|
Dividends received from subsidiaries
|
357,500
|
|
|
336,300
|
|
|
316,000
|
|
Other
|
20,163
|
|
|
(1,300)
|
|
|
31,807
|
|
Net cash flow provided by operating activities
|
394,901
|
|
|
289,072
|
|
|
319,767
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
Investments in subsidiaries
|
(137,881)
|
|
|
1,557
|
|
|
(142,796)
|
|
Repayments of loans from subsidiaries
|
932
|
|
|
4,190
|
|
|
6,477
|
|
Advances of loans to subsidiaries
|
(7,261)
|
|
|
(4,165)
|
|
|
(500)
|
|
Net cash flow provided by (used for) investing activities
|
(144,210)
|
|
|
1,582
|
|
|
(136,819)
|
|
Cash flows from financing activities
|
|
|
|
|
|
Issuance of long-term debt
|
496,950
|
|
|
—
|
|
|
150,000
|
|
Short-term debt borrowings under revolving credit facility
|
211,690
|
|
|
49,000
|
|
|
20,000
|
|
Short-term debt repayments under revolving credit facility
|
(230,690)
|
|
|
(65,000)
|
|
|
(32,000)
|
|
Commercial paper — net
|
73,325
|
|
|
54,275
|
|
|
(7,000)
|
|
Dividends paid on common stock
|
(350,577)
|
|
|
(329,643)
|
|
|
(308,892)
|
|
Repayment of long-term debt
|
(450,000)
|
|
|
—
|
|
|
—
|
|
Common stock equity issuance — net of purchases
|
(1,389)
|
|
|
692
|
|
|
(5,055)
|
|
Other
|
—
|
|
|
—
|
|
|
(1)
|
|
Net cash flow used for financing activities
|
(250,691)
|
|
|
(290,676)
|
|
|
(182,948)
|
|
Net decrease in cash and cash equivalents
|
—
|
|
|
(22)
|
|
|
—
|
|
Cash and cash equivalents at beginning of year
|
19
|
|
|
41
|
|
|
41
|
|
Cash and cash equivalents at end of year
|
$
|
19
|
|
|
$
|
19
|
|
|
$
|
41
|
|
See Combined Notes to Consolidated Financial Statements.
PINNACLE WEST CAPITAL CORPORATION HOLDING COMPANY
NOTES TO FINANCIAL STATEMENTS OF HOLDING COMPANY
The Combined Notes to Consolidated Financial Statements in Part II, Item 8 should be read in conjunction with the Pinnacle West Capital Corporation Holding Company Financial Statements.
The Pinnacle West Capital Corporation Holding Company Financial Statements have been prepared to present the financial position, results of operations and cash flows of Pinnacle West Capital Corporation on a stand-alone basis as a holding company. Investments in subsidiaries are accounted for using the equity method.