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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. 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
Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides either retail or wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS currently accounts for essentially all of our revenues and earnings.
Areas of Business Focus
Operational Performance, Reliability and Recent Developments.
Nuclear. APS operates and is a joint owner of Palo Verde. The March 2011 earthquake and tsunamis in Japan and the resulting accident at Japan’s Fukushima Daiichi nuclear power station had a significant impact on nuclear power operators worldwide. In the aftermath of the accident, the NRC conducted an independent assessment to consider actions to address lessons learned from the Fukushima events. The independent assessment, named the "Near Term Task Force," recommended a number of proposed enhancements to U.S. commercial nuclear power plant equipment and emergency plans. The NRC has directed nuclear power plants to begin implementing some of the Near Term Task Force’s recommendations. To implement these recommendations, Palo Verde expects to spend approximately $0.5 million for capital enhancements to the plant through 2016 in addition to the approximate $125 million that has already been spent on capital enhancements as of December 31, 2015 (APS’s share is 29.1%).
Coal and Related Environmental Matters and Transactions. APS is a joint owner of three coal-fired power plants and acts as operating agent for two of the plants. APS is focused on the impacts on its coal fleet that may result from increased regulation and potential legislation concerning GHG emissions. On June 2, 2014, EPA proposed a rule to limit carbon dioxide emissions from existing power plants (the "Clean Power Plan"), and EPA finalized its proposal on August 3, 2015.
EPA’s nationwide CO2 emissions reduction goal is 32% below 2005 emission levels. As finalized for the state of Arizona and the Navajo Nation, compliance with the Clean Power Plan could involve a shift in generation from coal to natural gas and renewable generation. Until implementation plans for these jurisdictions are finalized, we are unable to determine the actual impacts to APS. APS continually analyzes its long-range capital management plans to assess the potential effects of these changes, understanding that any resulting regulation and legislation could impact the economic viability of certain plants, as well as the willingness or ability of power plant participants to continue participation in such plants.
Cholla
On September 11, 2014, APS announced that it would close its 260 MW Unit 2 at Cholla and cease burning coal at Units 1 and 3 by the mid-2020s if EPA approves a compromise proposal offered by APS to meet required environmental and emissions standards and rules. On April 14, 2015, the ACC approved APS's plan to retire Unit 2, without expressing any view on the future recoverability of APS's remaining investment in the Unit. (See Note 3 for details related to the resulting regulatory asset and Note 10 for details of the proposal.) APS believes that the environmental benefits of this proposal are greater in the long term than the benefits that would have resulted from adding emissions control equipment. APS closed Unit 2 on October 1, 2015.
Four Corners
Asset Purchase Agreement and Coal Supply Matters. On December 30, 2013, APS purchased SCE’s 48% interest in each of Units 4 and 5 of Four Corners. The final purchase price for the interest was approximately $182 million. In connection with APS’s most recent retail rate case with the ACC, the ACC reserved the right to review the prudence of the Four Corners transaction for cost recovery purposes upon the closing of the transaction. On December 23, 2014, the ACC approved rate adjustments related to APS’s acquisition of SCE’s interest in Four Corners resulting in a revenue increase of $57.1 million on an annual basis. On February 23, 2015, the ACC decision approving the rate adjustments was appealed. APS has intervened and is actively participating in the proceeding. The Arizona Court of Appeals has suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed below, which could have an effect on the outcome of this Four Corners proceeding. We cannot predict when or how this matter will be resolved.
Concurrently with the closing of the SCE transaction, BHP Billiton, the parent company of BNCC, the coal supplier and operator of the mine that serves Four Corners, transferred its ownership of BNCC to NTEC, a company formed by the Navajo Nation to own the mine and develop other energy projects. BHP Billiton will be retained by NTEC under contract as the mine manager and operator until July 2016. Also occurring concurrently with the closing, the Four Corners’ co-owners executed the 2016 Coal Supply Agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through 2031. El Paso, a 7% owner in Units 4 and 5 of Four Corners, did not sign the 2016 Coal Supply Agreement. Under the 2016 Coal Supply Agreement, APS has agreed to assume the 7% shortfall obligation. On February 17, 2015, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in each of Units 4 and 5 of Four Corners. The cash purchase price, which will be subject to certain adjustments at closing, is immaterial in amount, and the purchaser will assume El Paso's reclamation and decommissioning obligations associated with the 7% interest. Completion of the purchase is subject to the receipt of certain regulatory approvals and is expected to occur in July 2016.
When APS, or an affiliate of APS, ultimately acquires El Paso's interest in Four Corners, NTEC has the option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC. On December 29, 2015, NTEC notified APS of its intent to exercise the option. APS is negotiating a definitive purchase agreement with NTEC for the purchase of the 7% interest. The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% shortfall obligations in the event NTEC does not purchase the interest.
Lease Extension. APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041. The Navajo Nation approved these amendments in March 2011. The effectiveness of the amendments also required the approval of the DOI, as did a related federal rights-of-way grant. A federal environmental review was undertaken as part of the DOI review process, and culminated in the issuance by DOI of a record
of decision on July 17, 2015. The record of decision provided the authority for the Bureau of Indian Affairs to sign the lease amendments and rights-of-way renewals, which occurred in late July 2015. On December 21, 2015, several environmental groups filed a notice of intent to sue with OSM and other federal agencies under the Endangered Species Act alleging that OSM's reliance on the Biological Opinion and Incidental Take Statement prepared in connection with the environmental review described above were not in accordance with applicable law. We are monitoring this matter and will intervene if a lawsuit is filed. We cannot predict the timing or outcome of this matter.
Natural Gas. APS has six natural gas power plants located throughout Arizona, including Ocotillo. Ocotillo is a 330 MW 4-unit gas plant located in the metropolitan Phoenix area. In early 2014, APS announced a project to modernize the plant, which involves retiring two older 110 MW steam units, adding five 102 MW combustion turbines and maintaining two existing 55 MW combustion turbines. In total, this increases the capacity of the site by 290 MW, to 620 MW, with completion targeted by summer 2019. APS completed a competitive solicitation process in which the Ocotillo project was evaluated against other alternatives. Consistent with the independent monitor’s report, the Ocotillo project was selected as the best alternative. APS must finalize the permitting process before construction can begin.
Transmission and Delivery. APS is working closely with regulators to identify and plan for transmission needs that continue to support system reliability, access to markets and renewable energy development. The capital expenditures table presented in the "Liquidity and Capital Resources" section below includes new APS transmission projects through 2018, along with other transmission costs for upgrades and replacements. APS is also working to establish and expand advanced grid technologies throughout its service territory to provide long-term benefits both to APS and its customers. APS is strategically deploying a variety of technologies that are intended to allow customers to better monitor their energy use and needs, minimize system outage durations, as well as the number of customers that experience outages, and facilitate greater cost savings to APS through improved reliability and the automation of certain distribution functions, including remote meter reading and remote connects and disconnects.
Renewable Energy. The ACC approved the RES in 2006. The renewable energy requirement is 6% of retail electric sales in 2016 and increases annually until it reaches 15% in 2025. In the 2009 Settlement Agreement, APS agreed to exceed the RES standards, committing to use APS’s best efforts to obtain 1,700 GWh of new renewable resources to be in service by year-end 2015, in addition to its RES renewable resource commitments. APS met its settlement commitment and RES target for 2015. A component of the RES targets development of distributed energy systems.
In 2013, the ACC conducted a hearing to consider APS's proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits. On September 9, 2014, the ACC authorized a rulemaking process to modify the RES rules. The proposed changes would permit the ACC to find that utilities have complied with the distributed energy requirement in light of all available information. The ACC adopted these changes on December 18, 2014. The revised rules went into effect on April 21, 2015.
On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million. On December 31, 2014, the ACC issued a decision approving the 2015 RES implementation plan with minor modifications, including reducing the requested budget to approximately $152 million.
On July 1, 2015, APS filed its 2016 RES implementation plan and proposed a RES budget of approximately $148 million. On January 12, 2016, the ACC approved APS’s plan and requested budget.
APS has developed owned solar resources through the ACC-approved AZ Sun Program. APS has invested approximately $675 million in its AZ Sun Program. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the project to the electric grid.
In accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 MW of APS-owned utility scale solar under the AZ Sun Program. In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 10 MW (approximately 1,500 customers) of APS-owned residential solar that will not be under the AZ Sun Program. On December 19, 2014, the ACC voted that it had no objection to APS implementing its residential rooftop solar program. The first stage of the residential rooftop solar program, called the "Solar Partner Program", is to be 8 MW followed by a 2 MW second stage that will only be deployed if coupled with distributed storage. The program will target specific distribution feeders in an effort to maximize potential system benefits, as well as make systems available to limited-income customers who cannot easily install solar through transactions with third parties. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes shall not be made until the project is fully in service and APS requests cost recovery in a future rate case.
Demand Side Management. In December 2009, Arizona regulators placed an increased focus on energy efficiency and other demand side management programs to encourage customers to conserve energy, while incentivizing utilities to aid in these efforts that ultimately reduce the demand for energy. The ACC initiated an Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard of 22% cumulative annual energy savings by 2020. The 22% figure represents the cumulative reduction in future energy usage through 2020 attributable to energy efficiency initiatives. This standard became effective on January 1, 2011.
On June 1, 2012, APS filed its 2013 DSM Plan. In 2013, the standards required APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.
On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan. The ACC approved a budget of $68.9 million for each of 2013 and 2014. The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency Standards, savings from improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan.
On March 20, 2015, APS filed an application with the ACC requesting a budget of $68.9 million for 2015 and minor modifications to its DSM portfolio going forward, including for the first time three resource savings projects which reflect energy savings on APS's system. The ACC approved APS’s 2015 DSM budget on November 25, 2015. In its decision, the ACC also approved that verified energy savings from APS’s resource savings projects could be counted toward compliance with the Electric Energy Efficiency Standard, however, the ACC ruled that APS was not allowed to count savings from systems savings projects toward determination of its achievement tier level for its performance incentive, nor may APS include savings from conservation voltage reduction in the calculation of its Lost Fixed Cost Recovery mechanism.
On June 1, 2015, APS filed its 2016 DSM Plan requesting a budget of $68.9 million and minor modifications to its DSM portfolio to increase energy savings and cost effectiveness of the programs. The DSM Plan also proposed a reduction in the DSMAC of approximately 12%.
Electric Energy Efficiency. On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Standards should be modified. The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.
On November 4, 2014, the ACC staff issued a request for informal comment on a draft of possible amendments to Arizona’s Electric Utility Energy Efficiency Standards. The draft proposed substantial changes to the rules and energy efficiency standards. The ACC accepted written comments and took public comment regarding the possible amendments on December 19, 2014. A formal rulemaking has not been initiated and there has been no additional action on the draft to date.
Rate Matters. APS needs timely recovery through rates of its capital and operating expenditures to maintain its financial health. APS’s retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by FERC. On June 1, 2011, APS filed a rate case with the ACC. APS and other parties to the retail rate case subsequently entered into the 2012 Settlement Agreement detailing the terms upon which the parties have agreed to settle the rate case. See Note 3 for details regarding the 2012 Settlement Agreement terms and for information on APS’s FERC rates.
On January 29, 2016, APS filed a NOI informing the ACC that APS intends to submit a rate case application in June 2016 using an adjusted test year ending December 31, 2015. The NOI provides an overview of the key issues APS expects to address in its formal request such as rate design changes (residential, commercial and industrial), a decoupling mechanism, permission to defer for potential future recovery costs associated with the Company’s Ocotillo Modernization Project, permission to defer for potential future recovery costs associated with environmental standards compliance, inclusion of post-test year plant and modifications to certain adjustor mechanisms, among other items. In its rate application, APS will request that its proposed pricing changes take effect in July 2017. APS is still developing the exact amount of the request.
APS has several recovery mechanisms in place that provide more timely recovery to APS of its fuel and transmission costs, and costs associated with the promotion and implementation of its demand side management and renewable energy efforts and customer programs. These mechanisms are described more fully in Note 3.
As part of APS’s acquisition of SCE’s interest in Units 4 and 5 of Four Corners, APS and SCE agreed, via a "Transmission Termination Agreement" that, upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provides transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California. APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third parties, including 300 MW to APS’s marketing and trading group. However, this alternative arrangement was not approved by FERC. On December 22, 2015, APS and SCE agreed to terminate the Transmission Termination Agreement and allow for the Transmission Agreement to expire according to its terms, which includes settling obligations in accordance with the terms of the Transmission Agreement. APS has established a regulatory asset of $12 million at December 31, 2015 in connection with the expiration of the Transmission Agreement, which it expects to recover through its FERC-jurisdictional rates.
Net Metering. On July 12, 2013, APS filed an application with the ACC proposing a solution to address the cost shift brought by the current net metering rules. On December 3, 2013, the ACC issued its order on APS’s net metering proposal. The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electric grid. The fixed charge does not increase APS's revenue because it is credited to the LFCR.
In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electric grid. The ACC acknowledged that the $0.70 per kilowatt charge addresses only a portion of the cost shift.
On October 20, 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of distributed generation to gather information that will inform the ACC on net metering issues and cost of service studies in upcoming utility rate cases. A hearing has been scheduled to commence in April 2016. APS cannot predict the outcome of this proceeding.
In 2015, Arizona jurisdictional utilities UNS Electric, Inc. and Tucson Electric Power Company both filed applications with the ACC requesting rate increases. These applications include rate design changes to mitigate the cost shift caused by net metering. On December 9, 2015, APS filed testimony in the UNS Electric, Inc. rate case in support of the UNS Electric, Inc. proposed rate design changes. APS has also requested intervention in the upcoming Tucson Electric Power Company rate case. The outcomes of these proceedings will not directly impact our financial position.
Appellate Review of Third-Party Regulatory Decision ("System Improvement Benefits" or "SIB"). In a recent appellate challenge to an ACC rate decision involving a water company, the Arizona Court of Appeals considered the question of how the ACC should determine the “fair value” of a utility’s property, as specified in the Arizona Constitution, in connection with authorizing the recovery of costs through rate adjustors outside of a rate case. The Court of Appeals reversed the ACC’s method of finding fair value in that case, and raised questions concerning the relationship between the need for fair value findings and the recovery of capital and certain other utility costs through adjustors. The ACC sought review by the Arizona Supreme Court of this decision and APS filed a brief supporting the ACC’s petition to the Arizona Supreme Court for review of the Court of Appeals’ decision. On February 9, 2016, the Arizona Supreme Court granted review of the decision and oral argument is set for March 22, 2016. If the decision is upheld by the Supreme Court without modification, certain APS rate adjustors may require modification. This could in turn have an impact on APS’s ability to recover certain costs in between rate cases. APS cannot predict the outcome of this matter.
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 will focus 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. TransCanyon
continues to pursue transmission development opportunities in the western United States consistent with its strategy.
El Dorado. The operations of El Dorado are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.
Key Financial Drivers
In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company’s current needs, and to adjust our expectations, financial budgets and forecasts appropriately.
Electric Operating Revenues. For the years 2013 through 2015, retail electric revenues comprised approximately 93% of our total electric 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.
Customer and Sales Growth. Retail customers in APS’s service territory increased 1.2% for the year ended December 31, 2015 compared with the prior year. For the three years 2013 through 2015, APS’s customer growth averaged 1.3% per year. We currently expect annual customer growth to average in the range of 2.0-3.0% for 2016 through 2018 based on our assessment of modestly improving economic conditions in Arizona. Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 0.7% for the year ended December 31, 2015 compared with the prior year, reflecting the effects of improving economic conditions and customer growth, partially offset by customer conservation and energy efficiency and distributed renewable generation initiatives. For the three years 2013 through 2015, APS experienced annual increases in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations. We currently estimate that annual retail electricity sales in kWh will increase on average in the range of 0.5-1.5% during 2016 through 2018, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations. A slower recovery of the Arizona economy 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 $10 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 $20 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 $10 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, outages, renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors. On September 30, 2014, Pinnacle West announced plan design changes to the group life and medical postretirement benefit plan, which reduced net periodic benefit costs. See Note 7.
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 "Capital Expenditures" below for information regarding the planned additions to our facilities. See Note 3 regarding deferral of certain costs pursuant to an ACC order.
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 11.0% of the assessed value for 2015, 10.7% for 2014 and 10.5% for 2013. We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units, transmission and distribution facilities. (See Note 3 for property tax deferrals contained in the 2012 Settlement Agreement.)
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.
Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 6). 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 electric service to Native Load customers) and related activities and includes electricity generation, transmission and distribution.
Operating Results – 2015 compared with 2014.
Our consolidated net income attributable to common shareholders for the year ended December 31, 2015 was $437 million, compared with $398 million for the prior year. The results reflect an increase of approximately $34 million for the regulated electricity segment primarily due to the Four Corners-related rate change, lower operations and maintenance expenses, and higher retail sales due to customer growth and changes in customer usage patterns and related pricing, partially offset by higher depreciation and amortization. The all other segment's income was higher by $5 million primarily related to El Dorado's investment losses in 2014.
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
| Year Ended December 31, | |||||||||||
| 2015 | 2014 | Net change | |||||||||
| (dollars in millions) | |||||||||||
| Regulated Electricity Segment: | |||||||||||
| Operating revenues less fuel and purchased power expenses | $ | 2,391 | $ | 2,309 | $ | 82 | |||||
| Operations and maintenance | (868 | ) | (908 | ) | 40 | ||||||
| Depreciation and amortization | (494 | ) | (417 | ) | (77 | ) | |||||
| Taxes other than income taxes | (172 | ) | (172 | ) | — | ||||||
| All other income and expenses, net | 19 | 28 | (9 | ) | |||||||
| Interest charges, net of allowance for borrowed funds used during construction | (179 | ) | (185 | ) | 6 | ||||||
| Income taxes | (239 | ) | (224 | ) | (15 | ) | |||||
| Less income related to noncontrolling interests (Note 18) | (19 | ) | (26 | ) | 7 | ||||||
| Regulated electricity segment income | 439 | 405 | 34 | ||||||||
| All other | (2 | ) | (7 | ) | 5 | ||||||
| Net Income Attributable to Common Shareholders | $ | 437 | $ | 398 | $ | 39 |
Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $82 million higher for the year ended December 31, 2015 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) | |||||||||||
| Four Corners-related rate change | $ | 56 | $ | — | $ | 56 | |||||
| Higher retail sales due to customer growth and changes in customer usage patterns and related pricing | 25 | 6 | 19 | ||||||||
| Lost fixed cost recovery | 12 | — | 12 | ||||||||
| Effects of weather | 16 | 6 | 10 | ||||||||
| Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals | (69 | ) | (68 | ) | (1 | ) | |||||
| Changes in long-term wholesale contracted sales | (40 | ) | (25 | ) | (15 | ) | |||||
| Miscellaneous items, net | 3 | 2 | 1 | ||||||||
| Total | $ | 3 | $ | (79 | ) | $ | 82 |
Operations and maintenance. Operations and maintenance expenses decreased $40 million for the year ended December 31, 2015 compared with the prior year primarily because of:
| • | A decrease of $21 million for employee benefit costs; |
| • | A decrease of $14 million in fossil generation costs primarily related to lower planned outage costs; |
| • | A decrease of $13 million for costs related to corporate support; |
| • | A decrease of $8 million related to costs for demand-side management, renewable energy and similar regulatory programs, which is partially offset in operating revenues and purchased power; |
| • | An increase of $9 million related to higher nuclear generation costs; |
| • | An increase of $6 million in customer service costs including costs related to a new customer information system; and |
| • | An increase of $1 million related to other miscellaneous factors. |
Depreciation and amortization. Depreciation and amortization expenses were $77 million higher for the year ended December 31, 2015 compared with the prior year primarily related to:
| • | An increase of $34 million related to the absence of 2014 Four Corners cost deferrals and the related 2015 amortization; |
| • | An increase of $16 million related to the Four Corners acquisition adjustment; |
| • | An increase of $20 million due to increased plant in service; |
| • | An increase of $10 million related to the regulatory treatment of the Palo Verde sale leaseback, which is offset in noncontrolling interests; and |
| • | A decrease of $3 million due to other miscellaneous factors. |
All other income and expenses, net. All other income and expenses, net, were $9 million lower for the year ended December 31, 2015 compared with the prior year primarily due to the return on the Four Corners acquisition in 2014.
Interest charges, net of allowance for borrowed funds used during construction. Interest charges, net of allowance for borrowed funds used during construction, decreased $6 million for the year ended December 31, 2015 compared with the prior year, primarily because of lower interest rates on our debt in the current year.
Income taxes. Income taxes were $15 million higher for the year ended December 31, 2015 compared with the prior year primarily due to the effects of higher pretax income in the current year.
Operating Results – 2014 compared with 2013.
Our consolidated net income attributable to common shareholders for the year ended December 31, 2014 was $398 million, compared with $406 million for the prior year. The results reflect a decrease of approximately $4 million for the regulated electricity segment primarily due to higher fossil generation costs, lower retail sales due to the effects of weather, higher property taxes, and lower retail transmission revenues. These
negative factors were partially offset by lower operations and maintenance expenses related to lower employee benefit costs, higher other income, and increased revenues for lost fixed cost recovery. All other segment's income was lower by $4 million primarily related to El Dorado's investment losses.
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
| Year Ended December 31, | |||||||||||
| 2014 | 2013 | Net change | |||||||||
| (dollars in millions) | |||||||||||
| Regulated Electricity Segment: | |||||||||||
| Operating revenues less fuel and purchased power expenses | $ | 2,309 | $ | 2,356 | $ | (47 | ) | ||||
| Operations and maintenance | (908 | ) | (925 | ) | 17 | ||||||
| Depreciation and amortization | (417 | ) | (416 | ) | (1 | ) | |||||
| Taxes other than income taxes | (172 | ) | (164 | ) | (8 | ) | |||||
| All other income and expenses, net | 28 | 11 | 17 | ||||||||
| Interest charges, net of allowance for borrowed funds used during construction | (185 | ) | (187 | ) | 2 | ||||||
| Income taxes | (224 | ) | (232 | ) | 8 | ||||||
| Less income related to noncontrolling interests (Note 18) | (26 | ) | (34 | ) | 8 | ||||||
| Regulated electricity segment income | 405 | 409 | (4 | ) | |||||||
| All other | (7 | ) | (3 | ) | (4 | ) | |||||
| Net Income Attributable to Common Shareholders | $ | 398 | $ | 406 | $ | (8 | ) |
Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $47 million lower for the year ended December 31, 2014 compared with the prior year. The following table summarizes the major components of this change:
| Increase (Decrease) | |||||||||||
| Operating revenues | Fuel and purchased power expenses | Net change | |||||||||
| (dollars in millions) | |||||||||||
| Effects of weather | $ | (45 | ) | $ | (16 | ) | $ | (29 | ) | ||
| Lower demand side management regulatory surcharges, offset by renewable energy regulatory surcharges and purchased power | — | 20 | (20 | ) | |||||||
| Lower retail transmission revenues | (7 | ) | — | (7 | ) | ||||||
| Lower retail sales due to changes in customer usage patterns and related pricing, partially offset by customer growth | (4 | ) | — | (4 | ) | ||||||
| Higher net fuel and purchased power costs, including related deferrals and higher off-system sales margins | 78 | 79 | (1 | ) | |||||||
| Lost fixed cost recovery | 12 | — | 12 | ||||||||
| Miscellaneous items, net | 3 | 1 | 2 | ||||||||
| Total | $ | 37 | $ | 84 | $ | (47 | ) |
Operations and maintenance. Operations and maintenance expenses decreased $17 million for the year ended December 31, 2014 compared with the prior year primarily because of:
| • | A decrease of $33 million related to costs for demand-side management, renewable energy and similar regulatory programs, which were partially offset in operating revenues and purchased power; |
- A decrease of $20 million related to lower employee benefit costs;
| • | An increase of $33 million in generation costs, primarily related to an increased ownership share in Four Corners, a portion of which is deferred in depreciation and amortization, and higher fossil maintenance costs; and |
| • | An increase of $3 million related to miscellaneous other factors. |
Depreciation and amortization. Depreciation and amortization expenses were $1 million higher for the year ended December 31, 2014 compared with the prior year primarily related to higher plant balances of approximately $23 million, partially offset by higher Four Corners cost deferrals in the current year of approximately $22 million.
Taxes other than income taxes. Taxes other than income taxes were $8 million higher for the year ended December 31, 2014 compared with the prior year primarily due to higher property tax rates and higher plant balances.
All other income and expenses, net. All other income and expenses, net, were $17 million higher for the year ended December 31, 2014 compared with the prior year due to the debt return on the Four Corners acquisition, an increase in the allowance for equity funds used during construction due to higher balances, and other non-operating income.
Income taxes. Income taxes were $8 million lower for the year ended December 31, 2014 compared with the prior year primarily due to the effects of lower pretax income in the current year.
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, 2015, APS’s common equity ratio, as defined, was 55%. Its total shareholder equity was approximately $4.7 billion, and total capitalization was approximately $8.6 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.4 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 financing and equity infusions from Pinnacle West.
Many of APS’s current capital expenditure projects qualify for bonus depreciation. On December 18, 2015, President Obama signed into law the Consolidated Appropriations Act, 2016 (H.R. 2029) which combined the tax and government funding bills (The Protecting Americans from Tax Hikes Act and Omnibus Bill) containing an extension of bonus depreciation through 2019. Enactment of this legislation is expected to generate approximately $375-$425 million of cash tax benefits over the next three years, which is expected to be fully realized by APS and Pinnacle West Consolidated during this time frame. The cash generated by the extension of bonus depreciation is an acceleration of the tax benefits that APS would have otherwise received over 20 years. At Pinnacle West Consolidated, the extension of bonus depreciation will, in turn, delay until 2019 full cash realization of approximately $82 million of currently unrealized Investment Tax Credits, which are recorded as a deferred tax asset on the Consolidated Balance Sheet as of December 31, 2015.
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, 2015, 2014 and 2013 (dollars in millions):
Pinnacle West Consolidated
| 2015 | 2014 | 2013 | |||||||||
| Net cash flow provided by operating activities | $ | 1,094 | $ | 1,100 | $ | 1,153 | |||||
| Net cash flow used for investing activities | (1,066 | ) | (923 | ) | (1,009 | ) | |||||
| Net cash flow provided by (used for) financing activities | 4 | (179 | ) | (161 | ) | ||||||
| Net increase (decrease) in cash and cash equivalents | $ | 32 | $ | (2 | ) | $ | (17 | ) |
Arizona Public Service Company
| 2015 | 2014 | 2013 | |||||||||
| Net cash flow provided by operating activities | $ | 1,100 | $ | 1,124 | $ | 1,194 | |||||
| Net cash flow used for investing activities | (1,060 | ) | (922 | ) | (1,009 | ) | |||||
| Net cash flow used for financing activities | (22 | ) | (201 | ) | (185 | ) | |||||
| Net increase in cash and cash equivalents | $ | 18 | $ | 1 | $ | — |
Operating Cash Flows
2015 Compared with 2014. Pinnacle West’s consolidated net cash provided by operating activities was $1,094 million in 2015 compared to $1,100 million in 2014, a decrease of $6 million in net cash provided. The decrease is primarily related to a $135 million income tax refund received in the first quarter of 2014, which is partially offset by a $48 million change in cash collateral posted, and other changes in working capital including increased cash receipts for the Four Corners-related rate change of $56 million.
2014 Compared with 2013. Pinnacle West’s consolidated net cash provided by operating activities was $1,100 million in 2014 compared to $1,153 million in 2013, a decrease of $53 million in net cash provided. The decrease is primarily related to $99 million in higher fuel and purchased power costs, a $39 million increase in cash collateral posted, $34 million of higher pension contributions in 2014, and other changes in working capital. The decrease is partially offset by a $121 million increase in income tax refunds net of payments (primarily related to a $135 million income tax refund received in the first quarter of 2014). APS's
operating cash flows included income tax refunds of approximately $86 million in 2014 compared with payments of $8 million in 2013.
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 116% funded as of January 1, 2015 and is estimated to be approximately 116% funded as of January 1, 2016. Under GAAP, the qualified pension plan was 89% funded as of January 1, 2015 and is estimated to be approximately 88% funded as of January 1, 2016. See Note 7 for additional details. The assets in the plan are comprised of fixed-income, equity, real estate, and short-term investments. Future year contribution amounts are dependent on plan asset performance and plan actuarial assumptions. We made contributions to our pension plan totaling $100 million in 2015, $175 million in 2014, and $141 million in 2013. The minimum required contributions for the pension plan are zero for the next three years. We expect to make voluntary contributions up to a total of $300 million during the 2016-2018 period. With regard to our contributions to our other postretirement benefit plans, we made a contribution of approximately $1 million in 2015, $1 million in 2014, and $14 million in 2013. We expect to make contributions of approximately $1 million in each of the next three years to our other postretirement benefit plans.
Investing Cash Flows
2015 Compared with 2014. Pinnacle West’s consolidated net cash used for investing activities was $1,066 million in 2015, compared to $923 million in 2014, an increase of $143 million in net cash used primarily related to increased capital expenditures.
2014 Compared with 2013. Pinnacle West’s consolidated net cash used for investing activities was $923 million in 2014, compared to $1,009 million in 2013, a decrease of $86 million in net cash used. The decrease in net cash used for investing activities is primarily related to APS's purchase of SCE’s interest in Units 4 and 5 of Four Corners of approximately $209 million in 2013, partially offset by an increase of approximately $123 million in other capital expenditures.
Capital Expenditures. The following table summarizes the estimated capital expenditures for the next three years:
Capital Expenditures
(dollars in millions)
| Estimated for the Year Ended December 31, | |||||||||||
| 2016 | 2017 | 2018 | |||||||||
| APS | |||||||||||
| Generation: | |||||||||||
| Nuclear Fuel | $ | 81 | $ | 78 | $ | 81 | |||||
| Renewables | 110 | 1 | 1 | ||||||||
| Environmental | 235 | 199 | 130 | ||||||||
| New Gas Generation | 77 | 237 | 112 | ||||||||
| Other Generation | 134 | 133 | 222 | ||||||||
| Distribution | 357 | 345 | 376 | ||||||||
| Transmission | 123 | 210 | 120 | ||||||||
| Other (a) | 88 | 82 | 82 | ||||||||
| Total APS | $ | 1,205 | $ | 1,285 | $ | 1,124 |
(a) Primarily information systems and facilities projects.
Generation capital expenditures are comprised of various improvements to APS’s existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment, such as turbines, boilers and environmental equipment. The estimated renewables capital expenditures include a planned utility-scale solar facility, which is subject to regulatory approval. We have not included estimated costs for Cholla’s compliance with MATS or EPA’s regional haze rule since we have challenged the regional haze rule judicially and we have proposed a compromise strategy to EPA, which, if approved, would allow us to avoid expenditures related to environmental control equipment. The portion of estimated costs for 2016 through 2018 for installation of pollution control equipment needed to ensure Four Corners’ compliance with EPA’s regional haze rules have been included in the table above. Costs related to the Navajo Plant's compliance with the regional haze rules are not included in the table above, as they are expected to be incurred post-2018. The portion of estimated costs for 2016 through 2018 for incremental costs to comply with the CCR rule for Four Corners and Cholla have also been included in the table above.
On February 17, 2015, APS and El Paso entered into an asset purchase agreement providing for the purchase by APS, or an affiliate of APS, of El Paso’s 7% interest in each of Units 4 and 5 of Four Corners. On December 29, 2015, NTEC notified APS of its intent to exercise its option to purchase the 7% interest. The table above does not include capital expenditures related to El Paso's 7% interest in Four Corners Units 4 and 5 of $27 million in 2016 and $20 million in 2017. We are monitoring the status of other 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
2015 Compared with 2014. Pinnacle West’s consolidated net cash provided by financing activities was $4 million in 2015, compared to $179 million net cash used in 2014, an increase of $183 million in net cash provided. The increase in net cash provided by financing activities is primarily due to $237 million lower repayments of long-term debt and $111 million higher issuances of long-term debt (see below), partially offset by a $142 million net change in short-term borrowings.
2014 Compared with 2013. Pinnacle West’s consolidated net cash used for financing activities was $179 million in 2014, compared to $161 million in 2013, an increase of $18 million in net cash used. The increase in net cash used for financing activities is primarily due to $530 million in higher repayments of long-term debt, a $67 million net reduction in funds received through short-term borrowings, and $11 million in higher dividend payments, partially offset by $595 million in higher issuances of long-term debt (see below).
Significant Financing Activities. On December 16, 2015, the Pinnacle West Board of Directors declared a quarterly dividend of $0.625 per share of common stock, payable on March 1, 2016, to shareholders of record on February 1, 2015. During 2015, Pinnacle West increased its indicated annual dividend from $2.38 per share to $2.50 per share. For the year ended December 31, 2015, Pinnacle West’s total dividends paid per share of common stock were $2.41 per share, which resulted in dividend payments of $260 million.
On January 12, 2015, APS issued $250 million of 2.20% unsecured senior notes that mature on January 15, 2020. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures.
On May 19, 2015, APS issued $300 million of 3.15% unsecured senior notes that mature on May 15, 2025. The net proceeds from the sale were used to repay short-term indebtedness consisting of commercial paper borrowings and drawings under our revolving credit facilities, incurred in connection with the payment at maturity of our $300 million aggregate principal amount of 4.65% notes due May 15, 2015.
On May 28, 2015, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029 in connection with the mandatory tender provisions for this indebtedness. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2014.
On June 26, 2015, APS entered into a $50 million term loan facility that matures June 26, 2018. Interest rates are based on APS’s senior unsecured debt credit ratings. APS used the proceeds to repay and refinance existing short-term indebtedness.
On November 6, 2015, APS issued $250 million of 4.35% unsecured senior notes that mature on November 15, 2045. The net proceeds from the sale were used to refinance via redemption and cancellation at par our indebtedness related to the principal amounts of the Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A and 2009 Series C both due June 1, 2034, and repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures.
On November 17, 2015, APS redeemed at par and canceled all $38 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla
Project), 2009 Series A. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2014.
On November 17, 2015, APS canceled all $32 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series B, purchased in connection with the mandatory tender provision on May 30, 2014.
On December 8, 2015, APS redeemed at par and canceled all $32 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series C.
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 programs.
At December 31, 2015, Pinnacle West had a $200 million revolving credit facility that matures in May 2019. 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. At December 31, 2015, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.
On September 2, 2015, APS replaced its $500 million revolving credit facility that would have matured in April 2018, with a new $500 million facility that matures in September 2020.
At December 31, 2015, APS had two credit facilities totaling $1 billion, including the $500 million credit facility that matures in September 2020 and a $500 million credit facility that matures in May 2019. APS may increase the amount of each facility up to a maximum of $700 million each, 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 $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2015, APS had no outstanding borrowings or letters of credit under its revolving credit facilities.
See “Financial Assurances” in Note 10 for a discussion of APS’s separate outstanding letters of credit.
Other Financing Matters. See Note 3 for information regarding the PSA approved by the ACC.
See Note 16 for information related to the change in our margin and collateral accounts.
Debt Provisions
Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with this covenant. For both Pinnacle West and APS, this covenant requires that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At December 31, 2015, the ratio was approximately 47% for Pinnacle West and 46% 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 and term loan facilities 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 6 for further discussions of liquidity matters.
Credit Ratings
The ratings of securities of Pinnacle West and APS as of February 12, 2016 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- | ||
| Commercial paper | P-2 | A-2 | F2 | ||
| Outlook | Stable | Stable | Stable | ||
| APS | |||||
| Corporate credit rating | A2 | A- | A- | ||
| Senior unsecured | A2 | A- | A | ||
| Commercial paper | P-1 | A-2 | F2 | ||
| Outlook | Stable | Stable | Stable |
Off-Balance Sheet Arrangements
See Note 18 for a discussion of the impacts on our financial statements of consolidating certain VIEs.
Contractual Obligations
The following table summarizes Pinnacle West’s consolidated contractual requirements as of December 31, 2015 (dollars in millions):
| 2016 | 2017- 2018 | 2019- 2020 | Thereafter | Total | |||||||||||||||
| Long-term debt payments, including interest: (a) | |||||||||||||||||||
| APS | $ | 542 | $ | 414 | $ | 1,011 | $ | 4,422 | $ | 6,389 | |||||||||
| Pinnacle West | 2 | 127 | — | — | 129 | ||||||||||||||
| Total long-term debt payments, including interest | 544 | 541 | 1,011 | 4,422 | 6,518 | ||||||||||||||
| Fuel and purchased power commitments (b) | 643 | 1,174 | 1,064 | 7,559 | 10,440 | ||||||||||||||
| Renewable energy credits (c) | 42 | 80 | 80 | 432 | 634 | ||||||||||||||
| Purchase obligations (d) | 233 | 512 | 37 | 213 | 995 | ||||||||||||||
| Coal reclamation | 15 | 34 | 39 | 262 | 350 | ||||||||||||||
| Nuclear decommissioning funding requirements | 2 | 4 | 4 | 62 | 72 | ||||||||||||||
| Noncontrolling interests (e) | 23 | 46 | 46 | 226 | 341 | ||||||||||||||
| Operating lease payments | 9 | 16 | 11 | 61 | 97 | ||||||||||||||
| Total contractual commitments | $ | 1,511 | $ | 2,407 | $ | 2,292 | $ | 13,237 | $ | 19,447 |
| (a) | The long-term debt matures at various dates through 2045 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2015 (see Note 6). |
| (b) | Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation (see Notes 3 and 10). These amounts include commitments incurred assuming an additional 7% in the 2016 Coal Supply Agreement. |
| (c) | Contracts to purchase renewable energy credits in compliance with the RES (see Note 3). |
| (d) | These contractual obligations include commitments for capital expenditures and other obligations. |
| (e) | Payments to the noncontrolling interests relate to the Palo Verde Sale Leaseback (see Note 18). |
This table excludes $34 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. Estimated minimum required pension contributions are zero for 2016, 2017 and 2018 (see Note 7).
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with accounting principles generally accepted in the United States of America (“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 expected future costs that have already been collected from customers. Management continually assesses whether our regulatory assets are probable of future recovery 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. We had $1,364 million of regulatory assets and $1,140 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2015.
Included in the balance of regulatory assets at December 31, 2015 is a regulatory asset of $619 million for pension benefits. This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.
See Notes 1 and 3 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, 2015 reported pension liability on the Consolidated Balance Sheets and our 2015 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% | $ | (329 | ) | $ | (11 | ) | ||
| Decrease 1% | 399 | 16 | ||||||
| Expected long-term rate of return on plan assets: | ||||||||
| Increase 1% | — | (13 | ) | |||||
| Decrease 1% | — | 13 |
| (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, 2015 other postretirement benefit obligation and our 2015 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% | $ | (84 | ) | $ | (3 | ) | ||
| Decrease 1% | 107 | 6 | ||||||
| Healthcare cost trend rate (b): | ||||||||
| Increase 1% | 100 | 9 | ||||||
| Decrease 1% | (80 | ) | (6 | ) | ||||
| 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 7 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, 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 on accounting policies and Note 13 for fair value measurement disclosures.
OTHER ACCOUNTING MATTERS
During the fourth quarter of 2015, we early adopted two new accounting standards related to balance sheet presentation of debt issuance costs, and balance sheet presentation of deferred income taxes. The adoption of these standards did not impact our results of operations or cash flows.
During the first quarter of 2016, we will be adopting new consolidation accounting guidance. We do not expect the adoption of this guidance to have a material impact on our financial statements.
We are currently evaluating the impacts of adopting new revenue recognition guidance and financial instrument recognition and measurement guidance. These two new accounting standards will be effective for us on January 1, 2018.
See Note 2 for additional information related to accounting matters.
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 fund 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 fund (see Note 13 and Note 19) and benefit plan assets. The nuclear decommissioning trust fund 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, 2015 and 2014. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2015 and 2014 (dollars in millions):
Pinnacle West – Consolidated
| Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||
| Interest | Interest | |||||||||||||
| 2015 | Rates | Amount | Rates | Amount | ||||||||||
| 2016 | 0.01 | % | $ | 44 | 6.15 | % | $ | 314 | ||||||
| 2017 | 1.17 | % | 125 | — | — | |||||||||
| 2018 | 1.02 | % | 50 | 1.75 | % | 32 | ||||||||
| 2019 | — | — | 8.75 | % | 500 | |||||||||
| 2020 | — | — | 2.20 | % | 250 | |||||||||
| Years thereafter | 0.23 | % | 49 | 4.64 | % | 2,490 | ||||||||
| Total | $ | 268 | $ | 3,586 | ||||||||||
| Fair value | $ | 268 | $ | 3,839 |
| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||||||||
| Interest | Interest | Interest | |||||||||||||||||||
| 2014 | Rates | Amount | Rates | Amount | Rates | Amount | |||||||||||||||
| 2015 | 0.40 | % | $ | 147 | 0.03 | % | $ | 32 | 4.32 | % | $ | 352 | |||||||||
| 2016 | — | — | 0.04 | % | 44 | 6.15 | % | 314 | |||||||||||||
| 2017 | — | — | 0.82 | % | 157 | — | — | ||||||||||||||
| 2018 | — | — | — | — | 1.75 | % | 32 | ||||||||||||||
| 2019 | — | — | — | — | 8.75 | % | 500 | ||||||||||||||
| Years thereafter | — | — | 0.27 | % | 49 | 4.90 | % | 1,940 | |||||||||||||
| Total | $ | 147 | $ | 282 | $ | 3,138 | |||||||||||||||
| Fair value | $ | 147 | $ | 282 | $ | 3,558 |
The tables below present contractual balances of APS’s long-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2015 and 2014. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2015 and 2014 (dollars in millions):
APS — Consolidated
| Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||
| Interest | Interest | |||||||||||||
| 2015 | Rates | Amount | Rates | Amount | ||||||||||
| 2016 | 0.01 | % | $ | 44 | 6.15 | % | $ | 314 | ||||||
| 2017 | — | — | — | — | ||||||||||
| 2018 | 1.02 | % | 50 | 1.75 | % | 32 | ||||||||
| 2019 | — | — | 8.75 | % | 500 | |||||||||
| 2020 | — | — | 2.20 | % | 250 | |||||||||
| Years thereafter | 0.23 | % | 49 | 4.64 | % | 2,490 | ||||||||
| Total | $ | 143 | $ | 3,586 | ||||||||||
| Fair value | $ | 143 | $ | 3,839 |
| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||||||||
| Interest | Interest | Interest | |||||||||||||||||||
| 2014 | Rates | Amount | Rates | Amount | Rates | Amount | |||||||||||||||
| 2015 | 0.40 | % | $ | 147 | 0.03 | % | $ | 32 | 4.32 | % | $ | 352 | |||||||||
| 2016 | — | — | 0.04 | % | 44 | 6.15 | % | 314 | |||||||||||||
| 2017 | — | — | 0.03 | % | 32 | — | — | ||||||||||||||
| 2018 | — | — | — | — | 1.75 | % | 32 | ||||||||||||||
| 2019 | — | — | — | — | 8.75 | % | 500 | ||||||||||||||
| Years thereafter | — | — | 0.27 | % | 49 | 4.90 | % | 1,940 | |||||||||||||
| Total | $ | 147 | $ | 157 | $ | 3,138 | |||||||||||||||
| Fair value | $ | 147 | $ | 157 | $ | 3,558 |
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 2015 and 2014 (dollars in millions):
| 2015 | 2014 | ||||||
| Mark-to-market of net positions at beginning of year | $ | (115 | ) | $ | (73 | ) | |
| Increase in regulatory asset | (44 | ) | (64 | ) | |||
| Recognized in OCI: | |||||||
| Change in mark-to-market losses for future deliveries | (1 | ) | — | ||||
| Mark-to-market losses realized during the period | 6 | 22 | |||||
| Change in valuation techniques | — | — | |||||
| Mark-to-market of net positions at end of year | $ | (154 | ) | $ | (115 | ) |
The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2015 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 | 2016 | 2017 | 2018 | 2019 | 2020 | Total fair value | ||||||||||||||||||
| Observable prices provided by other external sources | $ | (65 | ) | $ | (40 | ) | $ | (16 | ) | $ | — | $ | — | $ | (121 | ) | ||||||||
| Prices based on unobservable inputs | (11 | ) | (7 | ) | (7 | ) | (6 | ) | (2 | ) | (33 | ) | ||||||||||||
| Total by maturity | $ | (76 | ) | $ | (47 | ) | $ | (23 | ) | $ | (6 | ) | $ | (2 | ) | $ | (154 | ) |
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, 2015 and 2014 (dollars in millions):
| December 31, 2015 Gain (Loss) | December 31, 2014 Gain (Loss) | ||||||||||||||
| Price Up 10% | Price Down 10% | Price Up 10% | Price Down 10% | ||||||||||||
| Mark-to-market changes reported in: | |||||||||||||||
| Regulatory asset (liability) or OCI (a) | |||||||||||||||
| Electricity | $ | 2 | $ | (2 | ) | $ | 3 | $ | (3 | ) | |||||
| Natural gas | 35 | (35 | ) | 29 | (29 | ) | |||||||||
| Total | $ | 37 | $ | (37 | ) | $ | 32 | $ | (32 | ) |
| (a) | These contracts are economic hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability. |
Credit Risk
We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 16 for a discussion of our credit valuation adjustment policy.
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