PINNACLE WEST CAPITAL: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL POSITION AND OPERATING RESULTS (Form 10-K)
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, Arizonawith 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'slargest and longest-serving electric company that generates safe, affordable and reliable electricity for approximately 1.3 million retail customers in 11 of Arizona's15 counties. APS is also the operator and co-owner of Palo Verde- a primary source of electricity for the southwest United Statesand 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. 53 -------------------------------------------------------------------------------- Table of Contents 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 millionfor the year ended December 31, 2020due 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, 2020through 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 Arizonaand remained in effect until May 16, 2020, when it was lifted and Arizonabegan reopening. In June 2020, Arizonasaw an increase in the number of COVID-19 cases, hospitalizations, and deaths. Accordingly, on June 29, 2020, the governor of Arizonaclosed bars, indoor gyms and fitness clubs or centers, indoor movie theaters, water parks and tubing operations until July 27, 2020as a partial reversal of the state's reopening and to mitigate the spread of COVID-19. On July 23, 2020, the governor of Arizonaextended 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 Securitypayroll taxes that would have otherwise been owed from March 27, 2020through December 31, 2020. We deferred the cash payment of the employer's portion of Social Securitypayroll taxes for the period July 1, 2020through December 31, 2020that was approximately $18 million. We will pay half of this cash deferral by December 31, 2021and the remainder by December 31, 2022. 54 -------------------------------------------------------------------------------- Table of Contents On June 30, 2020, FERCissued an order granting a waiver request related to the existing AFUDC rate calculation beginning March 1, 2020through 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, 2021and customers were automatically placed on eight-month payment arrangements if they had past due balances at the end of the disconnection period of $75or 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 millionpre-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 millionto $30 millionpre-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 2020rather than April 2020and and also delayed the reset of the PSA to the first billing cycle of April 2021rather 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 millionthat 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 millionto customers. The additional $7 millionover the approved amount of $36 millionwas 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 millionto assist customers and local non-profits and community organizations to help with the impact of the COVID-19 pandemic, with $12.4 millionof these dollars directly committed to bill assistance programs (the " COVID Customer Support Fund"). The COVID Customer Support Fundwas 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 millionin bill credits for limited income customers was ordered by the ACC in December 2020of which 50%, up to a 55 -------------------------------------------------------------------------------- Table of Contents 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 Fundwere programs that assisted customers that had a delinquency of two or more months with a one-time credit of $100, an expanded credit of $300for 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 2020ACC order further assisted delinquent limited income customers with an additional bill credit of up to $250or their delinquent balance, whichever was less. As of December 31, 2020, APS had distributed all funds for all COVID Customer Support Fundprograms combined. Beyond the COVID Customer Support Fund, APS has also provided $2.7 millionto 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 COVID19 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.
Our strategy is to deliver shareholder value by creating a sustainable energy future for
Arizonaby 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 Arizonapresents 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 targets consist of three parts: • A 2050 target to deliver 100% clean and carbon-free electricity; • A 2030 objective of achieving a 65% clean energy resource mix, with 45% of the production portfolio coming from renewable energies; and • A commitment to end the use of coal-fired power generation by APS 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 target: 100% clean and carbon-free electricity. Achieving a completely clean and carbon-free energy mix by 2050 is our aspiration. The 2050 goal will involve new thinking and will depend 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 56
The table of contents serves as a checkpoint for our resource planning, investment strategy and customer accessibility efforts as APS moves towards a 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 Nationto 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 Nationin 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.)
Renewable. APS intends to strengthen its already diversified energy mix by increasing its investments in carbon-free resources. Its short-term actions include competitive solicitations for 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 Verdeis 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 Arizonaand the region, as a reliable, continuous, affordable resource and as a large contributor to the local economy.
We believe it is APS's responsibility to deliver electric services to customers in the most cost-effective manner. Since
January 2018through December 2020, the average residential bill decreased by 7.3%, or $10.95. 57
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 millionin 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.
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.
Customers are at the heart of what APS does every day and its focus remains on its customers and the communities it serves. APS’s goal is to provide an industry-leading customer experience.
In 2020, APS adopted a number of changes to improve the customer experience. It has moved to a 24/7 care center in order to better serve its customers 24/7. APS improved the performance of its call center, answering nearly 75% of its more than 1.5 million phone calls in 30 seconds or less. APS
58 -------------------------------------------------------------------------------- Table of Contents 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.
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 Sunsites. 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 Sunsite. 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 Sunretrofits 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 Sunsites 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. 59 -------------------------------------------------------------------------------- Table of Contents Electric Vehicles APS is making electric vehicle charging more accessible for its customers and helping Arizonabusinesses, 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 2021and submitted to the ACC for review and approval.
Palo Verde, in partnership with Idaho National Laboratoryand two other utilities, has been chosen by the DOE's Office of Nuclear Energyto 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 Laboratorywill perform a technical and economic assessment of using electricity generated at Palo Verdeto produce hydrogen. Experience from Palo Verde'sutility 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 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 millionprimarily due to the prospective inclusion of rate refunds currently provided through the TEAM. The proposed total annual 60 -------------------------------------------------------------------------------- Table of Contents 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 % 4.1 % 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 Arizonalaw; •a Base Fuel Rate of $0.030168per kWh; •authorization to defer until APS's next general rate case the increase or decrease in its Arizonaproperty 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 millionin 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 called for the increase to become effective
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 millionrevenue 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 millionrevenue 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. 61 -------------------------------------------------------------------------------- Table of Contents 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 millionrevenue 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 millionwould 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 millionthat will be paid over 10 years to the Navajo Nationfor a sustainable transition to a post-coal economy, which would be funded by customers, (ii) $1.25 millionthat will be paid over five years to the Navajo Nationto fund an economic development organization, which would be funds not recoverable through rates, (iii) $10 millionto facilitate electrification projects within the Navajo Nation, which would be funded equally by funds not recoverable through rates and by customers, (iv) $2.5 millionper year in transmission revenue sharing to be paid to the Navajo Nationbeginning after the closure of the Four Corners PowerPlant through 2038, which would be funds not recoverable through rates, (v) $12 millionthat 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 millionthat will be paid over five years to the Hopi Triberelated 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 more information on additional regulatory matters.
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 Officein this matter. On February 22, 2021APS 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 millionof 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 significant borrowing capacity under their respective credit facilities and can easily access these facilities, ensuring adequate liquidity for each business. Capital city
Expenses will be funded by internally generated cash and external funding, which may include long-term debt and common stock issues of Pinnacle West.
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 Creekwind farm in Missouri(" Clear Creek") and the 250 MW Nobles 2 wind farm in Minnesota("Nobles 2"). Clear Creekachieved commercial operation in May 2020and 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 Creekand 5.1% of Nobles 2. El Dorado. El Doradois a wholly-owned subsidiary of Pinnacle West. El Doradoowns debt investments and minority interests in several energy-related investments and Arizonacommunity-based ventures. El Doradocommitted to a $25 millioninvestment in the Energy Impact Partnersfund, which is an organization that focuses on fostering innovation and supporting the transformation of the utility industry. The investment will be made by El Doradoas investments are selected by the Energy Impact Partnersfund.
Main 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, 2020compared 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. 63 -------------------------------------------------------------------------------- Table of Contents Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 1.4% for the year ended December 31, 2020compared 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, 2020through 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 Arizonaeconomy, 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, 2020reflects 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. 64 -------------------------------------------------------------------------------- Table of Contents 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 Arizonafor 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.) 65 -------------------------------------------------------------------------------- Table of Contents 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 vs. 2019
Our consolidated net income attributable to common shareholders for the year ended
December 31, 2020was $551 million, compared with $538 millionfor the prior year. The results reflect an increase of approximately $13 millionfor 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 the net income attributable to ordinary shareholders by business segment compared to the previous 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 $ 164Operations and maintenance (953) (939) (14) Depreciation and amortization (614) (591) (23) Taxes other than income taxes (225) (219) (6)
Pension and other credits unrelated to post-retirement service – net 56
23 33 All other income and expenses, net 26 61 (35)
Interest expense, net of allowance for borrowed funds used during construction
(229) (217) (12) Income taxes (Note 5) (78) 16 (94)
Less income related to non-controlling interests (note 18) (19)
(19) - Regulated electricity segment income 553 540 13 All other (2) (2) - Net Income Attributable to Common Shareholders
$ 551 $ 538 $ 1366
-------------------------------------------------------------------------------- Table of Contents Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were
$164 millionhigher for the year ended December 31, 2020compared with the prior year. The following table summarizes the major components of this change: Increase (Decrease) Fuel and Operating purchased revenues 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 costs of fuel and purchased electricity, including off-grid sales margins and related deferrals
(78) (85) 7 Lost fixed cost recovery 7 - 7
Reduction of regulatory surcharges relating to renewable energies, offset by operating and maintenance costs
(9) - (9)
Decline in retail revenues 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) $ 164Operations and maintenance. Operations and maintenance expenses increased $14 millionfor the year ended December 31, 2020compared with the prior-year period primarily because of: •An increase of $25 millionprimarily 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 millionrelated to employee benefits; •An increase of $12 millionrelated to customer bad debt expenses for the Summer Disconnection Moratorium and COVID-19 disconnect suspensions (see Note 4); •An increase of $11 millionfor costs related to information technology; •A decrease of $21 millionin nuclear generation costs primarily related to an increased recovery from contributions of administrative and general costs from Palo Verdeowners; •A decrease of $14 millionrelated to consulting costs; •A decrease of $13 millionprimarily related to costs for renewable energy and similar regulatory programs, which are partially offset in operating revenues and purchased power; •A decrease of $6 millionfor customer outreach costs; and •A decrease of $2 millionfor corporate resources and other miscellaneous factors. 67 -------------------------------------------------------------------------------- Table of Contents Depreciation and amortization. Depreciation and amortization expenses were $23 millionhigher for the year ended December 31, 2020compared 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 millionhigher for the year ended December 31, 2020compared 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 millionhigher for the year ended December 31, 2020compared 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 millionlower for the year ended December 31, 2020compared to the prior-year period primarily due to the current year CCT and APS Foundationcontributions. Interest charges, net of allowance for borrowed funds used during construction. Interest charges, net of allowance for borrowed funds used during construction were $12 millionhigher for the year ended December 31, 2020compared to the prior-year period primarily due to higher debt balances in the current period. Income taxes. Income taxes were $94 millionhigher for the year ended December 31, 2020compared 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. 68
Summary of cash flow
The following tables present the net cash provided by (used for) operating, investing and financing activities for the years ended.
Pinnacle West Consolidated 2020 2019
Net cash flow generated by operating activities
Net cash flow from investing activities (1,278) (1,131) Net cash flow generated by financing activities 361
Net increase in cash and cash equivalents
Net cash flow generated by operating activities
Net cash flow from investing activities (1,286) (1,136) Net cash flow from financing activities 404,133 Net increase in cash and cash equivalents
Operating cash flow
2020 Compared with 2019. Pinnacle West's consolidated net cash provided by operating activities was
$967 millionin 2020 compared to $957 millionin 2019. The increase of $10 millionin 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, 2021and 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, 2021and 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 millionin 2020, $150 millionin 2019, and $50 millionin 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 millionin 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 69 -------------------------------------------------------------------------------- Table of Contents any contributions over the next three years to our other postretirement benefit plans. The Company was reimbursed $26 millionin 2020, $30 millionin 2019, and $72 millionin 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 Securitypayroll taxes that would have otherwise been owed from March 27, 2020through December 31, 2020. We deferred the cash payment of the employer's portion of Social Securitypayroll taxes for the period July 1, 2020through December 31, 2020that was approximately $18 million. We will pay half of this cash deferral by December 31, 2021and the remainder by December 31, 2022.
Investing cash flow
2020 Compared to 2019. Pinnacle West’s consolidated net cash used for investing activities was
Capital expenditure. The following table summarizes the estimated capital expenditures for the next three years:
Capital Expenditures (dollars in millions)
Estimate for the year ended
December 31, 2021 2022 2023 APS Generation: Clean: Nuclear Generation
$ 114 $ 116 $ 125Renewables 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 70 -------------------------------------------------------------------------------- Table of Contents 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 by internally generated cash and external funding, which may include long-term debt and common share issuances of Pinnacle West.
Funding of cash flow and liquidity
2020 Compared with 2019. Pinnacle West's consolidated net cash provided by financing activities was
$361 millionin 2020 compared to $179 millionof net cash provided in 2019, an increase of $182 millionin net cash provided. The increase in net cash provided by financing activities includes $504 millionin 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 millionand higher dividend payments of $21 million. APS's consolidated net cash provided by financing activities was $404 millionin 2020 compared to $133 millionof net cash provided in 2019, an increase of $271 millionin net cash provided. The increase in net cash provided by financing activities includes lower long-term debt repayments of $135 millionand $8 millionin higher issuances of long-term debt, higher equity infusion of $150 millionand higher dividend payments of $21 million. Significant Financing Activities. On December 16, 2020, the Pinnacle West Board of Directors declared a dividend of $0.83per share of common stock, payable on March 1, 2021to shareholders of record on February 1, 2021. During 2020, Pinnacle West increased its indicated annual dividend from $3.13per share to $3.32per share. For the year ended December 31, 2020, Pinnacle West's total dividends paid per share of common stock were $3.18per share, which resulted in dividend payments of $351 million.
May 22, 2020, APS issued $600 millionof 3.35% unsecured senior notes that mature May 15, 2050. The net proceeds from the sale were used to repay early its $200 millionterm 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 millionof 1.3% unsecured senior notes that mature June 15, 2025. The net proceeds from the sale were used to repay early its $150 millionterm 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. 71 -------------------------------------------------------------------------------- Table of Contents On September 11, 2020, APS issued $400 millionof 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 millionof 2.6% unsecured senior notes. The aggregate balance of $405 millionwill 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 millionoutstanding principal amount of 4.7% City of Farmington, New MexicoPollution Control Revenue Refunding Bonds ( Arizona Public Service Company Four Corners Project), 1994 Series A, and (ii) the $65.75 millionoutstanding principal amount of 4.7% City of Farmington, New MexicoPollution Control Revenue Refunding Bonds ( Arizona Public Service Company Four Corners Project), 1994 Series B. On December 23, 2020, Pinnacle West entered into a $150 millionterm loan facility that matures June 2022. The proceeds were received on January 4, 2021and 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 millioninto 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 millionterm loan agreement that would have matured on May 7, 2020with a new 364-day $31 millionterm 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 millionin outstanding borrowings under the agreement. At December 31, 2020, Pinnacle West had a $200 millionrevolving 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 millionupon 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 millioncommercial 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 millionof commercial paper borrowings. At December 31, 2020, APS had two revolving credit facilities totaling $1 billion, including a $500 millioncredit facility that matures in June 2022and a $500 millionfacility 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 millioncommercial 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 funding issues. See note 16 for information relating to the change in our margin and guarantee accounts.
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 nor APS’s funding agreements contain “rating triggers” that would accelerate the interest and principal payments required in the event of a rating downgrade. However, our bank credit agreements contain a pricing schedule in which the interest rates we pay for borrowings under them 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 more details on liquidity issues.
73 -------------------------------------------------------------------------------- Table of Contents Credit Ratings The ratings of securities of Pinnacle West and APS as of
February 23, 2021are 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 provisions
See note 18 for a discussion of the impacts on our financial statements of the consolidation of certain VIEs.
74 -------------------------------------------------------------------------------- Table of Contents Contractual Obligations
The following table summarizes Pinnacle West’s consolidated contractual requirements for
2021 2023 2025 Thereafter Total Long-term debt payments, including interest: (a) APS
$ 227 $ 452 $ 985 $ 8,796 $ 10,460Pinnacle 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
(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 Verdesale 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 millionin unrecognized tax benefits because the timing of the future cash outflows is uncertain. In January 2021, approximately $391 millionof 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 75 -------------------------------------------------------------------------------- Table of Contents 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 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 Arizonaand 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 millionof regulatory assets and $2,679 millionof regulatory liabilities on the Consolidated Balance Sheets at December 31, 2020.
See Notes 1 and 4 for more information.
Accounting for pensions and other post-retirement benefits
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, 2020reported 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): 76
Table of Contents Increase (Decrease) Impact on Impact on Pension Pension Actuarial Assumption (a) Plans 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 in the calculation are held constant while the rates are changed by one percentage point.
The following graph reflects the sensitivities that a change in certain actuarial assumptions would have had on the
Increase (Decrease) Impact on Other Postretirement Impact on Other Benefit Postretirement Actuarial Assumption (a) Plans 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 more details on our pension plans and other post-retirement benefits.
77 -------------------------------------------------------------------------------- Table of Contents 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.
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
Our activities include managing market risks associated with changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust, other special purpose funds and employee benefit plan assets. .
78 -------------------------------------------------------------------------------- Table of Contents 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, 2020and 2019. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2020and 2019 (dollars in millions):
Pinnacle West – Consolidated
Short-Term Variable-Rate Fixed-Rate Debt Long-Term Debt 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 $ 6,330Fair value $ 169 $ 36 $ 7,577Short-Term Variable-Rate Fixed-Rate Debt Long-Term Debt Long-Term Debt Interest Interest Interest 2019 Rates Amount Rates Amount Rates Amount 2020 2.06 % $ 1152.16 % $ 3502.23 % $ 4502021 - - - - - - 2022 - - - - - - 2023 - - - - - - 2024 - - - - 3.78 % 365 Years thereafter - - 1.54 % 36 4.12 % 4,475 Total $ 115 $ 386 $ 5,290Fair value $ 115 $ 386 $ 5,80879
-------------------------------------------------------------------------------- Table of Contents 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, 2020and 2019. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2020and 2019 (dollars in millions): APS - Consolidated Variable-Rate Fixed-Rate Long-Term Debt 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 $ 5,830Fair value $ 36 $ 7,068Variable-Rate Fixed-Rate Long-Term Debt Long-Term Debt Interest Interest 2019 Rates Amount Rates Amount 2020 2.12 % $ 200 2.20 % $ 1502021 - - - - 2022 - - - - 2023 - - - - 2024 - - 3.78 % 365 Years thereafter 1.54 % 36 4.12 % 4,475 Total $ 236 $ 4,990Fair value $ 236 $ 5,508Commodity 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. 80
Table of contents The following table shows the net changes before tax in the market value of our derivative positions (in millions of dollars):
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, 2020by 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.) Total fair Source of Fair Value 2021 2022 2023 2024 2025 value Observable prices provided by other external sources $ (2) $ (3)
Prices based on unobservable data
(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 December 31, 2019 Gain (Loss) 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. 81 -------------------------------------------------------------------------------- Table of Contents Credit Risk
We are exposed to losses in the event of non-performance or non-payment of 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 section 7 above for a discussion of quantitative and qualitative information on market risks.
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