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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 2019 results with 2018 results. A comparison of the 2018 results with 2017 results can be found in the Annual Report on Form 10-K for the fiscal year ended December 31, 2018. 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 $18 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.
Strategic Overview
Our strategy is to deliver shareholder value by creating a sustainable energy future for Arizona with a clean, affordable, reliable and customer-focused plan.
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 to achieve clean energy goals. Guided by science, our approach is intended to encourage market-based and innovative solutions to drive towards a low-carbon economy. We believe clean energy can power a robust economy.
APS's new clean energy goals consist of three parts:
- An aspirational 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 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 Aspirational 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 Electricity. APS has an energy mix that is already 50% clean with existing plans to add more renewables and energy storage before 2025. Those plans are intended to allow us to attain an energy mix that is 65% clean by 2030, with 45% of APS's portfolio coming from renewable energy. 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 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 buying coal-generation from 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 28% since 2005. In addition, APS has committed to end the use of coal at its remaining Cholla units by 2025.
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, including energy efficiency resources that enable renewable additions and lead to a cleaner grid.
Palo Verde. Palo Verde is the nation’s largest producer of electricity and the largest source of carbon-free energy. The plant 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, the average residential bill decreased by 7.8% or $11.68, due primarily to savings from lower operating costs in areas such as fuel and purchased power and federal tax reform that have been passed on to customers.
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 eliminating waste. Through the initiative and existing cost management practices, APS identified $20 million in possible cost savings for 2020.
Participation in the EIM continues to be an effective tool for creating savings for our customers from the real-time, voluntary market. Over the past three years, the EIM has delivered approximately $140 million in gross benefits to APS customers. 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. Excluding voluntary outages and proactive fire mitigation efforts, APS finished 2019 with its best score for frequency of customer power outages.
Planned investments will support operating and maintaining the grid, updating technology, accommodating customer growth and enabling more renewable energy resources. Our advanced 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. (See "Liquidity and Capital Resources - Capital Expenditures" below for additional details on capital expenditures.)
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 APS is committed to providing options that make it easier for its customers to do business with them. In 2019, APS launched its redesigned aps.com website and mobile app, giving customers upgraded access to their energy usage data and billing information. APS's Customer Care team is using speech analytics to enrich advisors’ interactions with customers over the telephone, and customers can also communicate with APS through an online chat.
APS expanded financial help for its most vulnerable customers in 2019, allocating $2.75 million in crisis bill assistance and increasing the individual benefit for qualifying customers from $400 to $800 per year. The APS Solar Communities program has allowed more than 600 limited- and moderate-income customers to support clean energy and save money by hosting APS-owned solar systems on their residences in exchange for a monthly bill credit.
APS continues to develop and deploy innovative programs that connect customers with advanced technologies to help them manage their bills and encourage energy use during midday, when solar power is most abundant. Three energy storage programs incorporating smart thermostats, connected water heaters and batteries are helping customers shift energy use to times when they can take advantage of low-cost, abundant energy and reduce peak demand on APS's system.
In 2020, APS is convening an advisory panel of customers to gain a deeper understanding of the customer experience through their individual perspectives. A group of customer service advisors, in conjunction with local human services agencies, will provide in-person customer support in communities APS serves.
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 this agreement is scheduled to begin in 2021. In 2018, APS issued a request for proposal for approximately 106 MW of energy storage to be located at up to five of its AZ Sun sites. Based upon our 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. In February 2019, we contracted for the 141 MW and originally anticipated such facilities could be in service by mid-2020. 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. The results of the investigation will inform the timing of our utilization and implementation of batteries on our system. Due to the April 2019 event, APS is working with the counterparty for the AZ Sun sites to determine appropriate timing and path forward for such facilities. Additionally, in February 2019, APS signed two 20-year power purchase agreements for energy storage totaling 150 MW. Service under these power purchase agreements is also dependent on the results of the McMicken battery incident investigation and requires approval from the ACC to allow for recovery of these agreements through the PSA.
We currently plan to install at least 850 MW of energy storage by 2025, including the 150 MW of energy storage projects under power purchase agreements described above. The additional 700 MW of APS-owned energy storage is expected to be made up of the retrofits associated with our AZ Sun sites as described above, along with current and future RFPs for energy storage and solar plus energy storage projects. Given the April 2019 event, we continue to evaluate the appropriate timing and path forward to support the overall capacity goals for our system and associated energy storage requirements. Currently, APS is pursuing an RFP for battery-ready solar resources up to 150 MW with results expected in the first half of 2020.
Electric Vehicles
APS plans to make electric vehicle charging more accessible for its customers and help Arizona businesses, schools and governments electrify their fleets. In 2019, APS implemented its Take Charge AZ Pilot Program. The program provides charging equipment, installation, and maintenance to business customers, government agencies, and multifamily housing communities. Rates are designed to encourage charging overnight and during daytime off-peak hours when solar energy is abundant.
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 project, planned for 2020 through 2022, will look at how hydrogen from Palo Verde may be used as energy storage for use in reverse-operable electrolysis or peaking gas turbines during times of the day when photovoltaic solar energy sources are
unavailable and energy reserves in the southwest United States are low. It could also be used to support a rapidly increasing hydrogen transportation fuel market.
Experience from the pilot project will offer insights into methods for flexible transitions between electricity and hydrogen generation missions in solar-dominated electricity markets, and demonstrate how hydrogen may be used as energy storage to provide electricity during operating periods when solar is not available.
Carbon Capture
Carbon capture technologies can isolate atmospheric 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. At the same time, these generators are dispatchable: they can supply energy quickly as needed for reliability. Carbon capture technologies offer the potential to keep in operation existing generators that otherwise would need to be retired. There are a number of demonstration projects that show promise but are still being tested in real-world conditions. APS will continue to monitor this emerging technology.
Regulatory Overview
On October 31, 2019, APS filed an application with the ACC for 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 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 are:
| • | 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; |
| • | 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 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. APS cannot predict the outcome of its request.
See Note 4 for information regarding additional regulatory matters.
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 focus is on new growth opportunities that leverage the Company’s core expertise in the electric energy industry. BCE’s first initiative is 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 transmission opportunities within the eleven 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 developed by Tenaska, the 242 MW Clear Creek wind farm in Missouri and the 250 MW Nobles 2 wind farm in Minnesota. The Clear Creek project is expected to achieve commercial operation in 2020 and deliver power under a long-term power purchase agreement. The Nobles 2 project is also expected to achieve commercial operation in 2020 and deliver power under a long-term power purchase agreement. BCE indirectly owns 9.9% of the Clear Creek project and 5.1% of the Nobles 2 project.
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.
Operating Revenues. For the years 2017 through 2019, 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 2.0% for the year ended December 31, 2019 compared with the prior year. For the three years 2017 through 2019, APS’s customer growth averaged 1.8% per year. We currently project annual customer growth to be 1.5 - 2.5% for 2020 and for 2020 through 2022 based on our assessment of steady economic growth in Arizona.
Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 0.6% for the year ended December 31, 2019 compared with the prior year. Steady economic growth and customer growth were offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives. For the three years 2017 through 2019, 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 1.0 - 2.0% for 2020 and increase on average in the range of 1.0 - 2.0% during 2020 through 2022, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations and excluding the impacts of several new large data centers opening operations in Metro Phoenix. The impact of new large data centers could raise the range of expected sales annual growth rate over the 2020 to 2022 period, but demand from these customers remains uncertain at this point. Slower than expected growth of the Arizona economy or acceleration of the expected effects of customer conservation, energy efficiency or distributed renewable generation initiatives could further impact these estimates.
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, impacts of energy efficiency programs and growth in distributed generation, and responses to retail price changes. Based on past experience, a reasonable range of variation in our kWh sales projections attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of up to approximately $15 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 and income tax impacts related to bonus depreciation.
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 10.9% of the assessed value for 2019, 11.0% for 2018 and 11.2% for 2017. 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, 2019.) 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 – 2019 compared with 2018.
Our consolidated net income attributable to common shareholders for the year ended December 31, 2019 was $538 million, compared with $511 million for the prior year. The results reflect an increase of approximately $30 million for the regulated electricity segment primarily due to lower operations and maintenance costs and tax expense due to amortization of excess deferred taxes as a result of the Tax Act,
partially offset by lower revenue due to the refunds provided to customers resulting from the Tax Act, and milder weather and lower pension and other postretirement non-service credits.
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
| Year Ended December 31, | |||||||||||
| 2019 | 2018 | Net change | |||||||||
| (dollars in millions) | |||||||||||
| Regulated Electricity Segment: | |||||||||||
| Operating revenues less fuel and purchased power expenses | $ | 2,425 | $ | 2,590 | $ | (165 | ) | ||||
| Operations and maintenance | (939 | ) | (1,025 | ) | 86 | ||||||
| Depreciation and amortization | (591 | ) | (581 | ) | (10 | ) | |||||
| Taxes other than income taxes | (219 | ) | (212 | ) | (7 | ) | |||||
| Pension and other postretirement non-service credits - net | 23 | 50 | (27 | ) | |||||||
| All other income and expenses, net | 61 | 59 | 2 | ||||||||
| Interest charges, net of allowance for borrowed funds used during construction | (217 | ) | (218 | ) | 1 | ||||||
| Income taxes (Note 5) | 16 | (134 | ) | 150 | |||||||
| Less income related to noncontrolling interests (Note 19) | (19 | ) | (19 | ) | — | ||||||
| Regulated electricity segment income | 540 | 510 | 30 | ||||||||
| All other | (2 | ) | 1 | (3 | ) | ||||||
| Net Income Attributable to Common Shareholders | $ | 538 | $ | 511 | $ | 27 |
Operating revenues less fuel and purchased power expenses**.** Regulated electricity segment operating revenues less fuel and purchased power expenses were $165 million lower for the year ended December 31, 2019 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) | |||||||||||
| Refunds due to lower Federal corporate income tax rate (Note 4) | $ | (146 | ) | $ | — | $ | (146 | ) | |||
| Effects of weather | (32 | ) | (8 | ) | (24 | ) | |||||
| Lower renewable energy regulatory surcharges and higher purchased power, offset by operations and maintenance costs | (15 | ) | 2 | (17 | ) | ||||||
| Change in residential rate design (a) | 13 | — | 13 | ||||||||
| Lost fixed cost recovery | 8 | — | 8 | ||||||||
| Higher retail revenue due to higher customer growth, partially offset by the impacts of energy efficiency, distributed generation and changes in customer usage patterns | 10 | 5 | 5 | ||||||||
| Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals | (60 | ) | (61 | ) | 1 | ||||||
| Miscellaneous items, net | 5 | 10 | (5 | ) | |||||||
| Total | $ | (217 | ) | $ | (52 | ) | $ | (165 | ) |
(a) As part of the 2017 Settlement Agreement, rate design changes were implemented that moved some revenue responsibility from summer to non-summer months. The change was made to better align revenue collections with costs of service.
Operations and maintenance. Operations and maintenance expenses decreased $86 million for the year ended December 31, 2019 compared with the prior-year period primarily because of:
| • | A decrease of $42 million related to public outreach costs at the parent company primarily associated with the ballot initiative in 2018; |
| • | A decrease of $28 million in fossil generation costs primarily due to lower planned outages and operating costs, including $4 million of Navajo Plant costs which were offset in depreciation and amortization; |
| • | A decrease of $19 million related to employee benefit costs; |
| • | A decrease of $18 million related to costs for renewable energy and similar regulatory programs, which are offset in operating revenues and purchased power; |
| • | An increase of $12 million for costs related to information technology; |
| • | An increase of $12 million related to consulting costs; and |
| • | A decrease of $3 million for other miscellaneous factors. |
Depreciation and amortization. Depreciation and amortization expenses were $10 million higher for the year ended December 31, 2019 compared with the prior-year period primarily due to increased plant in service of $33 million, partially offset by the regulatory deferrals for the Four Corners SCR and Ocotillo modernization project of $19 million and the deferral of Navajo Plant costs of $4 million which is offset in operations and maintenance.
Taxes other than income taxes. Taxes other than income taxes were $7 million higher for the year ended December 31, 2019 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 $27 million lower for the year ended December 31, 2019 compared to the prior-year period primarily due to lower market returns in 2018.
Income taxes. Income taxes were $150 million lower for the year ended December 31, 2019 compared with the prior-year period primarily due to amortization of excess deferred taxes and lower pretax income in the current year period (see Note 5).
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, 2019, APS’s common equity ratio, as defined, was 52%. Its total shareholder equity was approximately $5.9 billion, and total capitalization was approximately $11.2 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $4.5 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, 2019 and 2018 (dollars in millions):
Pinnacle West Consolidated
| 2019 | 2018 | ||||||
| Net cash flow provided by operating activities | $ | 957 | $ | 1,277 | |||
| Net cash flow used for investing activities | (1,131 | ) | (1,193 | ) | |||
| Net cash flow provided by (used for) financing activities | 179 | (92 | ) | ||||
| Net increase (decrease) in cash and cash equivalents | $ | 5 | $ | (8 | ) |
Arizona Public Service Company
| 2019 | 2018 | ||||||
| Net cash flow provided by operating activities | $ | 1,007 | $ | 1,255 | |||
| Net cash flow used for investing activities | (1,136 | ) | (1,187 | ) | |||
| Net cash flow provided by (used for) financing activities | 133 | (76 | ) | ||||
| Net increase (decrease) in cash and cash equivalents | $ | 4 | $ | (8 | ) |
Operating Cash Flows
2019 Compared with 2018. Pinnacle West’s consolidated net cash provided by operating activities was $957 million in 2019 compared to $1,277 million in 2018. The decrease of $320 million in net cash provided is primarily due to lower cash receipts from electric revenues, higher payments for operations and maintenance, fuel and purchased power costs, property taxes, interest and higher pension contributions. The difference between APS and Pinnacle West's net cash provided by operating activities primarily relates to Pinnacle West's income tax cash payments to APS, offset by lower operations and maintenance expense at the parent.
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 117% funded as of January 1, 2020 and 112% as of January 1, 2019. Under GAAP, the qualified pension plan was 97% funded as of January 1, 2020 and 90% funded as of January 1, 2019. 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 $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 per year during the 2020-2022 period. With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2019 and 2018. We do not expect to make any contributions over the next three years to our other postretirement benefit plans. The Company was reimbursed $30 million in 2019 and $72 million in 2018 for prior years' retiree medical claims from the other postretirement benefit plan trust assets.
Investing Cash Flows
2019 Compared with 2018. Pinnacle West’s consolidated net cash used for investing activities was $1,131 million in 2019 compared to $1,193 million in 2018. The decrease of $62 million in net cash used primarily related to decreased capital expenditures and active union employee medical claim reimbursements (see Note 20). The difference between APS and Pinnacle West's net cash used for investing activities primarily relates to Pinnacle West's investing cash activity related to 4CA.
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, | |||||||||||
| 2020 | 2021 | 2022 | |||||||||
| APS | |||||||||||
| Generation: | |||||||||||
| Clean: | |||||||||||
| Nuclear Generation | $ | 131 | $ | 123 | $ | 123 | |||||
| Renewables and Energy Storage Systems ("ESS") (a) | 121 | 490 | 671 | ||||||||
| Environmental | 44 | 53 | 44 | ||||||||
| Other Generation | 139 | 154 | 121 | ||||||||
| Distribution | 554 | 444 | 446 | ||||||||
| Transmission | 182 | 203 | 208 | ||||||||
| Other (b) | 160 | 183 | 112 | ||||||||
| Total APS | $ | 1,331 | $ | 1,650 | $ | 1,725 |
| (a) | APS Solar Communities program, energy storage, renewable projects and other clean energy projects |
| (b) | 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
2019 Compared with 2018. Pinnacle West’s consolidated net cash provided by financing activities was $179 million in 2019 compared to $92 million of net cash used in 2018, an increase of $271 million in net cash provided. The increase in net cash provided by financing activities includes $647 million in higher issuances of long-term debt partially offset by higher long-term debt repayments of $418 million, a net increase in short term borrowings of $57 million and higher dividend payments of $21 million.
APS’s consolidated net cash provided by financing activities was $133 million in 2019 compared to $76 million of net cash used in 2018, an increase of $209 million in net cash provided. The increase in net cash provided by financing activities includes $797 million in higher issuances of long-term debt partially offset by higher long-term debt repayments of $418 million, lower equity infusion of $150 million and higher dividend payments of $20 million.
Significant Financing Activities. On December 18, 2019, the Pinnacle West Board of Directors declared a dividend of $0.7825 per share of common stock, payable on March 2, 2020 to shareholders of record on February 3, 2020. During 2019, Pinnacle West increased its indicated annual dividend from $2.95 per share to $3.13 per share. For the year ended December 31, 2019, Pinnacle West's total dividends paid per share of common stock were $3.00 per share, which resulted in dividend payments of $329 million.
On February 26, 2019, APS entered into a $200 million term loan agreement that matures August 26, 2020. APS used the proceeds to repay existing indebtedness. Borrowings under the agreement bear interest at London Inter-bank Offered Rate ("LIBOR") plus 0.50% per annum.
On February 28, 2019, APS issued $300 million of 4.25% unsecured senior notes that mature on March 1, 2049. The net proceeds from the sale, together with funds made available from the term loan described above, were used to repay existing indebtedness.
On March 1, 2019, APS repaid at maturity $500 million aggregate principal amount of its 8.75% senior notes.
On August 19, 2019, APS issued $300 million of 2.6% unsecured senior notes that mature on August 15, 2029. The net proceeds from the sale were used to repay short-term indebtedness, consisting of commercial paper borrowings, and to replenish cash used to fund capital expenditures.
On November 20, 2019, APS issued $300 million of 3.5% unsecured senior notes that mature on December 1, 2049. The net proceeds from the sale were used to repay short-term indebtedness, consisting of commercial paper borrowings, to replenish cash used to fund capital expenditures, and to redeem, on December 30, 2019, $100 million of the $250 million aggregate principal amount of our 2.2% Notes due January 15, 2020.
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 mentioned above.
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 9, 2019, Pinnacle West entered into a $50 million term loan agreement that matures May 7, 2020. Pinnacle West used the proceeds to refinance indebtedness under and terminate a prior $150 million revolving credit facility. Borrowings under the agreement bear interest at LIBOR plus 0.55% per annum. At December 31, 2019, Pinnacle West had $38 million in outstanding borrowings under the agreement.
At December 31, 2019, 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, 2019, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $77 million of commercial paper borrowings.
At December 31, 2019, 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, 2019, APS had no commercial paper outstanding and no outstanding borrowings or letters of credit under its revolving credit facilities. See "Financial Assurances" in Note 11 for a discussion of APS's other outstanding letters of credit.
Other Financing Matters. See Note 17 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, 2019, the ratio was approximately 52% for Pinnacle West and 47% 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 14, 2020 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 19 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, 2019 (dollars in millions):
| 2020 | 2021- 2022 | 2023- 2024 | Thereafter | Total | |||||||||||||||
| Long-term debt payments, including interest: (a) | |||||||||||||||||||
| APS | $ | 554 | $ | 398 | $ | 757 | $ | 7,405 | $ | 9,114 | |||||||||
| Pinnacle West | 460 | — | — | — | 460 | ||||||||||||||
| Total long-term debt payments, including interest | 1,014 | 398 | 757 | 7,405 | 9,574 | ||||||||||||||
| Short-term debt payments, including interest (b) | 115 | — | — | — | 115 | ||||||||||||||
| Fuel and purchased power commitments (c) | 569 | 1,217 | 1,176 | 5,318 | 8,280 | ||||||||||||||
| Renewable energy credits (d) | 36 | 66 | 58 | 133 | 293 | ||||||||||||||
| Purchase obligations (e) | 21 | 20 | 21 | 196 | 258 | ||||||||||||||
| Coal reclamation | 17 | 33 | 37 | 88 | 175 | ||||||||||||||
| Nuclear decommissioning funding requirements | 2 | 4 | 4 | 50 | 60 | ||||||||||||||
| Noncontrolling interests (f) | 23 | 46 | 39 | 143 | 251 | ||||||||||||||
| Operating lease payments (g) | 15 | 20 | 10 | 39 | 84 | ||||||||||||||
| Total contractual commitments | $ | 1,812 | $ | 1,804 | $ | 2,102 | $ | 13,372 | $ | 19,090 |
| (a) | The long-term debt matures at various dates through 2049 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2019 (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 19). |
| (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 $43 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. Estimated minimum required pension contributions are zero for 2020, 2021 and 2022 (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 $1,507 million of regulatory assets and $2,503 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2019.
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 liability 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, 2019 reported pension liability on the Consolidated Balance Sheets and our 2019 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):
| Increase (Decrease) | ||||||||
| Actuarial Assumption (a) | Impact on Pension Liability | Impact on Pension Expense | ||||||
| Discount rate: | ||||||||
| Increase 1% | $ | (388 | ) | $ | (11 | ) | ||
| Decrease 1% | 471 | 14 | ||||||
| Expected long-term rate of return on plan assets: | ||||||||
| Increase 1% | — | (22 | ) | |||||
| Decrease 1% | — | 22 |
| (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, 2019 other postretirement benefit obligation and our 2019 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):
| Increase (Decrease) | ||||||||
| Actuarial Assumption (a) | Impact on Other Postretirement Benefit Obligation | Impact on Other Postretirement Benefit Expense | ||||||
| Discount rate: | ||||||||
| Increase 1% | $ | (104 | ) | $ | (1 | ) | ||
| Decrease 1% | 134 | 5 | ||||||
| Healthcare cost trend rate (b): | ||||||||
| Increase 1% | 124 | 9 | ||||||
| Decrease 1% | (98 | ) | (4 | ) | ||||
| Expected long-term rate of return on plan assets – pretax: | ||||||||
| Increase 1% | — | (4 | ) | |||||
| Decrease 1% | — | 4 |
| (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 trust 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 14 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, 2019 are described further in Note 12.
OTHER ACCOUNTING MATTERS
On January 1, 2019, we adopted new lease accounting guidance, ASU 2016-02, and related amendments. On July 1, 2019, we early adopted ASU 2018-15, relating to accounting for cloud computing implementation costs. On January 1, 2020, we adopted ASU 2016-13 and related amendments, relating to the measurement of credit losses on financial instruments. 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 14 and Note 20), 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, 2019 and 2018. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2019 and 2018 (dollars in millions):
Pinnacle West – Consolidated
| 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 |
| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||||||||
| Interest | Interest | Interest | |||||||||||||||||||
| 2018 | Rates | Amount | Rates | Amount | Rates | Amount | |||||||||||||||
| 2019 | 2.99 | % | $ | 76 | — | $ | — | 8.75 | % | $ | 500 | ||||||||||
| 2020 | — | — | 3.02 | % | 150 | 2.23 | % | 550 | |||||||||||||
| 2021 | — | — | — | — | — | — | |||||||||||||||
| 2022 | — | — | — | — | — | — | |||||||||||||||
| 2023 | — | — | — | — | — | — | |||||||||||||||
| Years thereafter | — | — | 1.76 | % | 36 | 4.25 | % | 3,940 | |||||||||||||
| Total | $ | 76 | $ | 186 | $ | 4,990 | |||||||||||||||
| Fair value | $ | 76 | $ | 186 | $ | 5,048 |
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, 2019 and 2018. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2019 and 2018 (dollars in millions):
APS — Consolidated
| 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 |
| Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||
| Interest | Interest | |||||||||||||
| 2018 | Rates | Amount | Rates | Amount | ||||||||||
| 2019 | — | $ | — | 8.75 | % | $ | 500 | |||||||
| 2020 | — | — | 2.20 | % | 250 | |||||||||
| 2021 | — | — | — | — | ||||||||||
| 2022 | — | — | — | — | ||||||||||
| 2023 | — | — | — | — | ||||||||||
| Years thereafter | 1.76 | % | 36 | 4.25 | % | 3,940 | ||||||||
| Total | $ | 36 | $ | 4,690 | ||||||||||
| Fair value | $ | 36 | $ | 4,754 |
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 fuels. 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 in 2019 and 2018 (dollars in millions):
| 2019 | 2018 | ||||||
| Mark-to-market of net positions at beginning of year | $ | (58 | ) | $ | (91 | ) | |
| Decrease (Increase) in regulatory asset | (15 | ) | 31 | ||||
| Recognized in OCI: | |||||||
| Mark-to-market losses realized during the period | 2 | 2 | |||||
| Change in valuation techniques | — | — | |||||
| Mark-to-market of net positions at end of year | $ | (71 | ) | $ | (58 | ) |
The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2019 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 | 2020 | 2021 | 2022 | 2023 | 2024 | Total fair value | ||||||||||||||||||
| Observable prices provided by other external sources | $ | (36 | ) | $ | (17 | ) | $ | (10 | ) | $ | (4 | ) | $ | — | $ | (67 | ) | |||||||
| Prices based on unobservable inputs | (2 | ) | — | — | — | (2 | ) | (4 | ) | |||||||||||||||
| Total by maturity | $ | (38 | ) | $ | (17 | ) | $ | (10 | ) | $ | (4 | ) | $ | (2 | ) | $ | (71 | ) |
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 at December 31, 2019 and 2018 (dollars in millions):
| December 31, 2019 Gain (Loss) | December 31, 2018 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 | $ | — | $ | — | $ | 1 | $ | (1 | ) | ||||||
| Natural gas | 55 | (55 | ) | 44 | (44 | ) | |||||||||
| Total | $ | 55 | $ | (55 | ) | $ | 45 | $ | (45 | ) |
| (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 17 for a discussion of our credit valuation adjustment policy.
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