filings.toolsItem 7. MANAGEMENT’S DISCUSSION AND ANALYSIS
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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. Palo Verde experienced strong performance during 2016, with the completion of two refueling outages. The fall refueling outage was completed in 28 days with the lowest collective radiation exposure dose for any pressurized water reactor outage.
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. (See Note 10 for information regarding challenges to the legality of the Clean Power Plan and a court-ordered stay of the Clean Power Plan pending judicial review of the rule, which temporarily delays compliance obligations.) 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 air 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. On January 13, 2017, EPA approved a final rule incorporating APS's compromise proposal. Once the final rule is published in the Federal Register, parties have 60 days to file a petition for review in the Ninth Circuit Court of Appeals. APS cannot predict at this time whether such petitions will be filed or if they will be successful. In addition, under the terms of an executive memorandum issued on January 20, 2017, this final rule will not be published in the Federal Register until after it has been reviewed by an appointee of the President. We cannot predict when such review will occur and what may result from the additional review.
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 prior 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 suspended the appeal pending the Arizona Supreme Court's decision in the SIB matter discussed below. On August 8, 2016, the Arizona Supreme Court issued its opinion in the SIB matter, and the Arizona Court of Appeals has now ordered supplemental briefing on how that SIB decision should affect the challenge to the Four Corners rate adjustment. We cannot predict when or how this matter will be resolved.
Concurrently with the closing of the SCE transaction described above, 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 was retained by NTEC under contract as the mine manager and operator through 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 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 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. 4CA purchased the El Paso interest on July 6, 2016. The purchase price was immaterial in amount, and 4CA assumed El Paso's reclamation and decommissioning obligations associated with the 7% interest.
NTEC has the option to purchase the 7% interest within a certain timeframe pursuant to an option granted to NTEC. On December 29, 2015, NTEC provided notice of its intent to exercise the option. 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
- 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 justifying the agency action extending the life of the plant and the adjacent mine.
On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at the Four Corners Power Plant and the adjacent Navajo Mine past July 6, 2016. APS filed a motion to intervene in the proceedings, which was granted on August 3, 2016. Briefing on the merits of this litigation is expected to extend through May 2017. On September 15, 2016, NTEC filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. Because the court has placed a stay on all litigation deadlines pending its decision regarding NTEC's motion to dismiss, the schedule for briefing and the anticipated timeline for completion of this litigation will likely be extended. We cannot predict the outcome of this matter or its potential effect on Four Corners.
Navajo Plant
On February 13, 2017, the co-owners of the Navajo Plant voted not to pursue continued operation of the plant beyond December 2019, the expiration of the current lease term, and to pursue a new lease or lease extension with the Navajo Nation that would allow decommissioning activities to begin after December 2019 instead of later this year. Various stakeholders including regulators, tribal representatives and others interested in the continued operation of the plant intend to meet to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. We cannot predict whether any alternate solutions will be found that would be acceptable to all of the stakeholders and feasible to implement. APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant. APS will seek continued recovery in rates for the book value of its remaining investment in the plant ($108 million as of December 31, 2016, see Note 9 for additional details) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and which may be material. We cannot predict whether APS would obtain such recovery.
On February 14, 2017, the ACC opened a docket titled "ACC Investigation Concerning the Future of the Navajo Generating Station" with the stated goal of engaging stakeholders and negotiating a sustainable pathway for the Navajo Plant to continue operating in some form after December 2019. APS cannot predict the outcome of this proceeding.
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. (See Note 3 for proposed rate recovery in our current retail rate case filing.) On September 9, 2016, Maricopa County issued a final permit decision that authorizes construction of the Ocotillo modernization project.
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 2019, 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 manage their energy usage, minimize system outage durations and frequency, enable customer choice for behind-the-meter technologies, and facilitate greater cost savings to APS through improved reliability and the automation of certain distribution functions.
Energy Imbalance Market. In 2015, APS and the CAISO, the operator for the majority of California's transmission grid, signed an agreement for APS to begin participation in EIM. APS's participation in the EIM began on October 1, 2016. The EIM allows for rebalancing supply and demand in 15-minute blocks with dispatching every five minutes before the energy is needed, instead of the traditional one hour blocks. APS expects that its participation in EIM will lower its fuel costs, improve visibility and situational awareness for system operations in the Western Interconnection power grid, and improve integration of APS’s renewable resources.
Renewable Energy. The ACC approved the RES in 2006. The renewable energy requirement is 7% of retail electric sales in 2017 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 2016. A component of the RES targets development of distributed energy systems.
In December 2014, the ACC voted that it had no objection to APS implementing an APS-owned rooftop solar research and development program aimed at learning how to efficiently enable the integration of rooftop solar and battery storage with the grid. The first stage of the program, called the "Solar Partner Program," placed 8 MW of residential rooftop solar on strategically selected distribution feeders in an effort to maximize potential system benefits, as well as made systems available to limited-income customers who could not easily install solar through transactions with third parties. The second stage of the program, which included an additional 2 MW of rooftop solar and energy storage, placed two energy storage systems sized at 2 MW on two different high solar penetration feeders to test various grid-related operation improvements and system interoperability, and was in operation by the end of 2016. The ACC expressly reserved that any determination of prudency of the residential rooftop solar program for rate making purposes would not be made until the project was fully in service, and APS has requested cost recovery for the project in its currently pending rate case. On September 30, 2016, APS presented its preliminary findings from the residential rooftop solar program in a filing with the ACC.
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.
On July 1, 2016, APS filed its 2017 RES Implementation Plan and proposed a budget of approximately $150 million. APS’s budget request included additional funding to process the high volume of residential rooftop solar interconnection requests and also requested a permanent waiver of the residential distributed energy requirement for 2017 contained in the RES rules. The ACC has not yet ruled on the Company’s 2017 RES Implementation Plan.
In September of 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES. The ACC noted that many of the provisions of the original rule may no longer be appropriate, and the underlying economic assumptions associated with the rule have changed dramatically. The proceeding will review such issues as the rapidly declining cost of solar generation, an increased interest in community solar projects, energy storage options, and the decline in fossil fuel generation due to stringent EPA regulations. The proceeding will also examine the feasibility of increasing the standard to 30% of retail sales by 2030, in contrast to the current standard of 15% of retail sales by 2025. APS cannot predict the outcome of this proceeding.
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.
In March 2014, the ACC 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 LFCR 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. On April 1, 2016, APS filed an amended 2016 DSM Plan that sought minor modifications to its existing DSM Plan and requested to continue the current DSMAC and current budget of $68.9 million. On July 12, 2016, the ACC approved APS’s amended DSM Plan and directed APS to spend up to an additional $4 million on a new residential demand response or load management program that facilitates energy storage technology. On December 5, 2016, APS filed for ACC approval of a $4 million Residential Demand Response, Energy Storage and Load Management Program.
On June 1, 2016, the Company filed its 2017 DSM Implementation Plan, in which APS proposes programs and measures that specifically focus on reducing peak demand, shifting load to off-peak periods and educating customers about strategies to manage their energy and demand. The requested budget in the 2017 DSM Implementation Plan is $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Implementation Plan that incorporated the proposed Residential Demand Response, Energy Storage and Load Management Program and the requested budget increased to $66.6 million. The ACC has not yet ruled on the Company’s 2017 DSM Plan.
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. On July 12, 2016, the ACC ordered that ACC staff convene a workshop within 120 days to discuss a number of issues related to the Electric Energy Efficiency Standards, including the process of determining the cost effectiveness of DSM programs and the treatment of
peak demand and capacity reductions, among others. ACC staff convened the workshop on November 29, 2016 and sought public comment on potential revisions to the Electric Energy Efficiency Standards. APS cannot predict the outcome of this proceeding.
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. See Note 3 for information on APS’s FERC rates.
On June 1, 2016, APS filed an application with the ACC for an annual increase in retail base rates of $165.9 million. This amount excludes amounts that are currently collected on customer bills through adjustor mechanisms. The application requests that some of the balances in these adjustor accounts (aggregating to approximately $267.6 million as of December 31, 2015) be transferred into base rates through the ratemaking process. This transfer would not have an incremental effect on average customer bills. The average annual customer bill impact of APS’s request is an increase of 5.74% (the average annual bill impact for a typical APS residential customer is 7.96%). See Note 3 for details regarding the principal provisions of APS's application.
APS requested that the increase become effective July 1, 2017. On July 22, 2016, the ALJ set a procedural schedule for the rate proceeding, which supported completing the case within 12 months. The ACC staff and intervenors began filing their direct testimony in late December 2016 and additional filings of testimony are ongoing. On January 12, 2017, APS began settlement discussions with all parties. On January 13, 2017, the ALJ hearing the case before the ACC issued a procedural order delaying hearings on the case from the originally scheduled March 22, 2017 to April 24, 2017, to allow parties to participate in settlement discussions and prepare testimony on the distributed generation ("DG") rate design issues addressed in the value and cost of DG decision described below. According to the procedural order, settlement discussions are to be completed and, if applicable, any related settlement must be filed by March 17, 2017. The procedural order also extended the rate case completion date as calculated by Commission rule for an additional 33 days. APS cannot predict the outcome of this case.
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 Four Corners Units 4 and 5, 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. 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 established a regulatory asset of $12 million in 2015 in connection with the payment required under the terms of the Transmission Agreement. On July 1, 2016, FERC issued an order denying APS’s request to recover the regulatory asset through its FERC-jurisdictional rates. APS and SCE completed the termination of the Transmission Agreement on July 6, 2016. APS made the required payment to SCE and wrote-off the $12 million regulatory asset and charged operating revenues to reflect the effects of this order in the second quarter of 2016. On July 29, 2016, APS filed for a rehearing with FERC. In its order denying recovery, FERC also referred to its enforcement division a question of whether the agreement between APS and SCE relating to the settlement of obligations under the
Transmission Agreement was a jurisdictional contract that should have been filed with FERC. APS cannot predict the outcome of either matter.
Net Metering. In 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 was held in April 2016. On October 7, 2016, an ALJ issued a recommendation in the docket concerning the value and cost of DG solar installations. On December 20, 2016, the ACC completed its open meeting to consider the recommended decision by the ALJ. After making several amendments, the ACC approved the recommended decision by a 4-1 vote. As a result of the ACC’s action, effective following APS’s pending rate case, the current net metering tariff that governs payments for energy exported to the grid from rooftop solar systems will be replaced by a more formula-driven approach that will utilize inputs from historical wholesale solar power costs and eventually an avoided cost methodology.
As amended, the decision provides that payments by utilities for energy exported to the grid from DG solar facilities will be determined using a resource comparison proxy methodology, a method that is based on the price that APS pays for utility-scale solar projects on a five year rolling average, while a forecasted avoided cost methodology is being developed. The price established by this resource comparison proxy method will be updated annually (between rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by that utility for exported distributed energy.
In addition, the ACC made the following determinations:
| • | Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to the date new rates are effective based on APS's pending rate case will be grandfathered for a period of 20 years from the date of interconnection; |
| • | Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and |
| • | Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years. |
This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future rate cases, and the policy determinations themselves may be subject to future change as are all ACC policies. The determination of the initial export energy price to be paid by APS will be made in APS’s currently pending rate case, which is scheduled for hearing by the ACC in April 2017. APS cannot predict the outcome of this determination.
The ACC’s decision did not make any policy determinations as to any specific costs to be charged to DG solar system customers for their use of the grid. The determination of any such costs will be made in APS's future rate cases.
On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserts that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC's request for rehearing is required for
TASC to challenge this decision in court. To date, the ACC has taken no action on the rehearing request. The ACC's decision is expected to remain in effect during any legal challenge.
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 on August 8, 2016, the Arizona Supreme Court vacated the Court of Appeals opinion and affirmed the ACC’s orders approving the water company’s SIB adjustor.
System Benefits Charge. The 2012 Settlement Agreement provides that once APS achieved full funding of its decommissioning obligation under the sale leaseback agreements covering Unit 2 of Palo Verde, APS was required to implement a reduced System Benefits charge effective January 1, 2016. Beginning on January 1, 2016, APS began implementing a reduced System Benefits charge. The impact on APS retail revenues from the new System Benefits charge is an overall reduction of approximately $14.6 million per year with a corresponding reduction in depreciation and amortization expense.
Subpoena from Arizona Corporation Commissioner Robert Burns. On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, filed subpoenas in APS’s current retail rate proceeding to APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.
On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that Commissioner Burns’ subpoenas are contrary to law. On September 15, 2016, APS produced all non-confidential and responsive documents and offered to produce any remaining responsive documents that are confidential after an appropriate confidentiality agreement is signed.
On February 7, 2017, Commissioner Burns opened a new ACC docket and indicated that its purpose is to study and rectify problems with transparency and disclosure regarding financial contributions from regulated monopolies or other stakeholders who may appear before the ACC that may directly or indirectly benefit an ACC Commissioner, a candidate for ACC Commissioner, or key ACC staff. As part of this docket, Commissioner Burns set March 24, 2017 as a deadline for APS to produce all information previously requested through the subpoenas. Commissioner Burns has also scheduled a workshop in this matter for March 17, 2017. APS and Pinnacle West 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.
On March 29, 2016, TransCanyon entered into a strategic alliance agreement with PG&E to jointly pursue competitive transmission opportunities solicited by the CAISO, the operator for the majority of California's transmission grid. TransCanyon and PG&E intend to jointly engage in the development of future transmission infrastructure and compete to develop, build, own and operate transmission projects approved by the CAISO.
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.
4CA. See "Four Corners - Asset Purchase Agreement and Coal Supply Matters" above for information regarding 4CA.
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 2014 through 2016, retail electric revenues comprised approximately 94% 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.
Actual and Projected Customer and Sales Growth. Retail customers in APS’s service territory increased 1.4% for the year ended December 31, 2016 compared with the prior year. For the three years 2014 through 2016, APS’s customer growth averaged 1.3% per year. We currently project annual customer growth to be 1.5-2.5% for 2017 and to average in the range of 2.0-3.0% for 2017 through 2019 based on our assessment of modestly improving economic conditions in Arizona.
Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, were flat for the year ended December 31, 2016 compared with the prior year. Improving economic conditions and customer
growth and an additional day of sales due to the leap year were equally offset by energy savings driven by customer conservation, energy efficiency and distributed renewable generation initiatives. For the three years 2014 through 2016, APS experienced annual increases in retail electricity sales averaging 0.2%, adjusted to exclude the effects of weather variations. We currently project that annual retail electricity sales in kWh will increase in the range of 0-1.0% for 2017 and increase on average in the range of 0.5-1.5% during 2017 through 2019, 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 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 $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.
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 11.2% of the assessed value for 2016, 11.0% for 2015 and 10.7% for 2014. 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. The prospects for broad-based federal tax reform have increased due to the results of the 2016 elections. Any such reform may impact the Company's effective tax
rate, cash taxes paid and other financial results such as earnings per share, gross revenues and cash flows. Given the number of unknown variables and the lack of detailed legislative reform language, we are unable to predict any impacts to the Company at this time.
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 – 2016 compared with 2015.
Our consolidated net income attributable to common shareholders for the year ended December 31, 2016 was $442 million, compared with $437 million for the prior year. The results reflect an increase of approximately $4 million for the regulated electricity segment primarily due to higher transmission revenues, higher retail revenues due to customer growth and changes in customer usage patterns and related pricing, partially offset by higher operations and maintenance expense primarily related to transmission, distribution and customer service costs.
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
| Year Ended December 31, | |||||||||||
| 2016 | 2015 | Net change | |||||||||
| (dollars in millions) | |||||||||||
| Regulated Electricity Segment: | |||||||||||
| Operating revenues less fuel and purchased power expenses | $ | 2,407 | $ | 2,391 | $ | 16 | |||||
| Operations and maintenance | (906 | ) | (868 | ) | (38 | ) | |||||
| Depreciation and amortization | (485 | ) | (494 | ) | 9 | ||||||
| Taxes other than income taxes | (166 | ) | (172 | ) | 6 | ||||||
| All other income and expenses, net | 35 | 19 | 16 | ||||||||
| Interest charges, net of allowance for borrowed funds used during construction | (186 | ) | (179 | ) | (7 | ) | |||||
| Income taxes | (237 | ) | (239 | ) | 2 | ||||||
| Less income related to noncontrolling interests (Note 18) | (19 | ) | (19 | ) | — | ||||||
| Regulated electricity segment income | 443 | 439 | 4 | ||||||||
| All other | (1 | ) | (2 | ) | 1 | ||||||
| Net Income Attributable to Common Shareholders | $ | 442 | $ | 437 | $ | 5 |
Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $16 million higher for the year ended December 31, 2016 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) | |||||||||||
| Lost fixed cost recovery | $ | 17 | $ | — | $ | 17 | |||||
| Effects of weather | 6 | 2 | 4 | ||||||||
| Transmission revenues (Note 3): | |||||||||||
| Higher transmission revenues | 27 | — | 27 | ||||||||
| FERC disallowance | (12 | ) | — | (12 | ) | ||||||
| Higher retail revenues due to changes in customer usage patterns and related pricing | 10 | — | 10 | ||||||||
| Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals | (15 | ) | (17 | ) | 2 | ||||||
| Palo Verde system benefits charge (offset in depreciation and amortization, see Note 3) | (14 | ) | — | (14 | ) | ||||||
| Lower demand side management regulatory surcharges and renewable energy regulatory surcharges and purchased power partially offset in operations and maintenance costs | (16 | ) | (1 | ) | (15 | ) | |||||
| Miscellaneous items, net | (6 | ) | (3 | ) | (3 | ) | |||||
| Total | $ | (3 | ) | $ | (19 | ) | $ | 16 |
Operations and maintenance. Operations and maintenance expenses increased $38 million for the year ended December 31, 2016 compared with the prior year primarily because of:
| • | An increase of $16 million for transmission, distribution, and customer service costs primarily related to increased maintenance costs and implementation of new systems; |
| • | An increase of $9 million primarily for costs to support the company's positions on a solar net metering ballot initiative in Arizona and increased political participation costs; |
| • | An increase of $8 million in fossil generation costs primarily related to $33 million in higher planned outage costs, partially offset by $25 million of lower other fossil operating costs; |
| • | An increase of $7 million for costs related to legal, regulatory, information systems and other corporate support; |
| • | An increase of $5 million for employee benefit costs primarily related to increased pension, medical claims and other benefit costs; |
| • | An increase of $5 million related to higher nuclear generation costs; |
| • | An offsetting decrease of $13 million related to costs for demand-side management, renewable energy and similar regulatory programs, which is partially offset in operating revenues and purchased power; and |
| • | An increase of $1 million related to miscellaneous other factors. |
Additionally, stock compensation costs were flat compared to the prior year as a $12 million increase in costs was offset by a one-time $12 million reduction for the adoption of new stock compensation guidance (See Notes 2 and 15);
Depreciation and amortization. Depreciation and amortization expenses were $9 million lower for the year ended December 31, 2016 compared with the prior year primarily related to:
| • | A decrease of $20 million related to the regulatory treatment of the Palo Verde sale leaseback lease extension; |
| • | A decrease of $14 million due to lower Palo Verde decommissioning expense recovered through the system benefits charge (offset in operating revenues); and |
| • | An increase of $25 million due to increased plant in service. |
Taxes other than income taxes. Taxes other than income taxes were $6 million lower for the year ended December 31, 2016 compared with the prior year primarily due to lower assessed values resulting from a lower Arizona statutory rate, partially offset by higher property tax rates.
All other income and expenses, net. All other income and expenses, net, were $16 million higher for the year ended December 31, 2016 compared with the prior year primarily due to higher allowance for equity funds used during construction and the gain on sale of a transmission line.
Interest charges, net of allowance for borrowed funds used during construction. Interest charges, net of allowance for borrowed funds used during construction, increased $7 million for the year ended December 31, 2016 compared with the prior year, primarily because of higher debt balances in the current year.
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.
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, 2016, APS’s common equity ratio, as defined, was 54%. Its total shareholder equity was approximately $4.9 billion, and total capitalization was approximately $9.1 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.6 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 contained an extension of bonus depreciation through 2019. Enactment of this legislation is expected to generate approximately $300-$350 million of cash tax benefits over the next three years, which is expected to be fully realized by APS and Pinnacle West 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 and reduces rate base for ratemaking purposes. At Pinnacle West Consolidated, the extension of bonus depreciation will, in turn, delay until 2019 full cash realization of approximately $98 million of currently unrealized Investment Tax Credits, which are recorded as a deferred tax asset on the Condensed Consolidated Balance Sheet as of December 31, 2016.
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, 2016, 2015 and 2014 (dollars in millions):
Pinnacle West Consolidated
| 2016 | 2015 | 2014 | |||||||||
| Net cash flow provided by operating activities | $ | 1,023 | $ | 1,094 | $ | 1,100 | |||||
| Net cash flow used for investing activities | (1,252 | ) | (1,066 | ) | (923 | ) | |||||
| Net cash flow provided by (used for) financing activities | 198 | 4 | (179 | ) | |||||||
| Net increase (decrease) in cash and cash equivalents | $ | (31 | ) | $ | 32 | $ | (2 | ) |
Arizona Public Service Company
| 2016 | 2015 | 2014 | |||||||||
| Net cash flow provided by operating activities | $ | 1,010 | $ | 1,100 | $ | 1,124 | |||||
| Net cash flow used for investing activities | (1,219 | ) | (1,060 | ) | (922 | ) | |||||
| Net cash flow used for financing activities | 196 | (22 | ) | (201 | ) | ||||||
| Net increase (decrease) in cash and cash equivalents | $ | (13 | ) | $ | 18 | $ | 1 |
Operating Cash Flows
2016 Compared with 2015. Pinnacle West’s consolidated net cash provided by operating activities was $1,023 million in 2016 compared to $1,094 million in 2015. The decrease of $71 million in net cash provided is primarily due to higher operations and maintenance costs.
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.
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, 2016 and 115% as of January 1, 2017. Under GAAP, the qualified pension plan was 88% funded as of January 1, 2016 and January 1, 2017. 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 have made voluntary contributions to our pension plan of $100 million in 2016, $100 million in 2015 and $175 million in 2014. 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 2017-2019 period. With regard to our contributions to our other postretirement benefit plans, we made a contribution of approximately $1 million in each of 2016, 2015 and 2014. We expect to make contributions of less than $1 million in total for the next three years to our other postretirement benefit plans.
Investing Cash Flows
2016 Compared with 2015. Pinnacle West’s consolidated net cash used for investing activities was $1,252 million in 2016, compared to $1,066 million in 2015. The increase of $186 million in net cash used primarily related to increased capital expenditures.
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.
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, | |||||||||||
| 2017 | 2018 | 2019 | |||||||||
| APS | |||||||||||
| Generation: | |||||||||||
| Nuclear Fuel | $ | 69 | $ | 71 | $ | 65 | |||||
| Renewables | 4 | 1 | — | ||||||||
| Environmental | 195 | 105 | 61 | ||||||||
| New Gas Generation | 237 | 119 | 8 | ||||||||
| Other Generation | 150 | 213 | 149 | ||||||||
| Distribution | 402 | 406 | 480 | ||||||||
| Transmission | 206 | 137 | 150 | ||||||||
| Other (a) | 74 | 72 | 81 | ||||||||
| Total APS | $ | 1,337 | $ | 1,124 | $ | 994 |
(a) Primarily information systems and facilities projects.
Generation capital expenditures are comprised of various improvements to APS’s existing fossil, renewable 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. We have not included estimated costs for Cholla's compliance with EPA’s regional haze rule since we have challenged the rule judicially and we have proposed a compromise strategy to EPA, which would allow us to avoid expenditures related to environmental control equipment. (See Note 10 for details regarding the status of the final rule for Cholla and a related executive memorandum.) We are monitoring the status of other environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.
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 in July 2017. 4CA purchased the El Paso interest on July 6, 2016. The table above does not include capital expenditures related to 4CA's interest in Four Corners Units 4 and 5 of approximately $27 million in 2017, $15 million in 2018 and $6 million in 2019, which will be assumed by the ultimate owner of the 7% interest.
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
2016 Compared with 2015. Pinnacle West’s consolidated net cash provided by financing activities was $198 million in 2016, compared to $4 million in 2015, an increase of $194 million in net cash provided. The increase in net cash provided by financing activities is primarily due to a $325 million net increase in short-term borrowings and $45 million in lower long-term debt repayments partially offset by $149 million lower issuances of long-term debt through December 31, 2016 (see below).
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.
Significant Financing Activities. On December 21, 2016, the Pinnacle West Board of Directors declared a dividend of $0.655 per share of common stock, payable on March 1, 2017 to shareholders of record on February 1, 2017. During 2016, Pinnacle West increased its indicated annual dividend from $2.50 per share to $2.62 per share. For the year ended December 31, 2016, Pinnacle West's total dividends paid per share of common stock were $2.53 per share, which resulted in dividend payments of $274 million.
On December 27, 2016, Pinnacle West infused cash to APS of $42 million. APS used these funds to repay commercial paper borrowings.
On April 22, 2016, APS entered into a $100 million term loan facility that matures April 22, 2019. 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 May 6, 2016, APS issued $350 million of 3.75% unsecured senior notes that mature on May 15, 2046. The net proceeds from the sale were used to redeem and cancel pollution control bonds (see details below), and to repay commercial paper borrowings and replenish cash temporarily used to fund capital expenditures.
On June 1, 2016, APS redeemed at par and canceled all $64 million of the Navajo County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series D and E.
On June 1, 2016, APS redeemed at par and canceled all $13 million of the Coconino County, Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series A.
On August 1, 2016, APS repaid at maturity APS's $250 million aggregate principal amount of 6.25% senior notes due August 1, 2016.
On September 20, 2016, APS issued $250 million of 2.55% unsecured senior notes that mature on September 15, 2026. The net proceeds from the sale were used to repay commercial paper borrowings and replenish cash temporarily used in connection with the payment at maturity of our $250 million aggregate principal amount of 6.25% Notes due August 1, 2016.
On September 20, 2016, APS redeemed at par and canceled all $27 million of the Coconino County Arizona Pollution Control Corporation Revenue Refunding Bonds (Arizona Public Service Company Navajo Project), 2009 Series B.
On December 6, 2016, APS redeemed at par and canceled all $17 million of the Coconino County Arizona Pollution Control Corporation Revenue Bonds (Arizona Public Service Company Project), Series 1998.
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.
During the first quarter of 2016, APS increased its commercial paper program from $250 million to $500 million.
On May 13, 2016, Pinnacle West replaced its $200 million revolving credit facility that would have matured in May 2019, with a new $200 million facility that matures in May 2021. 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, 2016, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $1.7 million in commercial paper borrowings.
On May 13, 2016, APS replaced its $500 million revolving credit facility that would have matured in May 2019, with a new $500 million facility that matures in May 2021.
On August 31, 2016, PNW entered into a $75 million 364-day unsecured revolving credit facility that matures in August 2017. PNW will use the new facility to fund or otherwise support obligations related to 4CA, and borrowings under the facility will bear interest at LIBOR plus 0.80% per annum. At December 31, 2016, Pinnacle West had $40 million outstanding under the facility.
At December 31, 2016, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in September 2020 and the $500 million facility that matures in May 2021. 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, 2016, APS had $135.5 million of commercial paper outstanding and 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 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, 2016, the ratio was approximately 48% 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 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 17, 2017 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, 2016 (dollars in millions):
| 2017 | 2018- 2019 | 2020- 2021 | Thereafter | Total | |||||||||||||||
| Long-term debt payments, including interest: (a) | |||||||||||||||||||
| APS | $ | 187 | $ | 1,033 | $ | 523 | $ | 5,248 | $ | 6,991 | |||||||||
| Pinnacle West | 127 | — | — | — | 127 | ||||||||||||||
| Total long-term debt payments, including interest | 314 | 1,033 | 523 | 5,248 | 7,118 | ||||||||||||||
| Short-term debt payments, including interest (b) | 177 | — | — | — | 177 | ||||||||||||||
| Fuel and purchased power commitments (c) | 617 | 1,135 | 1,033 | 7,127 | 9,912 | ||||||||||||||
| Renewable energy credits (d) | 40 | 80 | 80 | 420 | 620 | ||||||||||||||
| Purchase obligations (e) | 360 | 200 | 16 | 212 | 788 | ||||||||||||||
| Coal reclamation | 18 | 40 | 46 | 258 | 362 | ||||||||||||||
| Nuclear decommissioning funding requirements | 2 | 4 | 4 | 58 | 68 | ||||||||||||||
| Noncontrolling interests (f) | 23 | 46 | 46 | 204 | 319 | ||||||||||||||
| Operating lease payments | 12 | 20 | 13 | 60 | 105 | ||||||||||||||
| Total contractual commitments | $ | 1,563 | $ | 2,558 | $ | 1,761 | $ | 13,587 | $ | 19,469 |
| (a) | The long-term debt matures at various dates through 2046 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2016 (see Note 6). |
| (b) | See Note 5 - Lines of credit and short-term borrowings 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 3 and 10). |
| (d) | Contracts to purchase renewable energy credits in compliance with the RES (see Note 3). |
| (e) | These contractual obligations include commitments for capital expenditures and other obligations. |
| (f) | Payments to the noncontrolling interests relate to the Palo Verde Sale Leaseback (see Note 18). |
This table excludes $36 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. Estimated minimum required pension contributions are zero for 2017, 2018 and 2019 (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 $1,420 million of regulatory assets and $1,049 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2016.
Included in the balance of regulatory assets at December 31, 2016 is a regulatory asset of $711 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 all or a portion of 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, 2016 reported pension liability on the Consolidated Balance Sheets and our 2016 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% | $ | (344 | ) | $ | (12 | ) | ||
| Decrease 1% | 418 | 15 | ||||||
| Expected long-term rate of return on plan assets: | ||||||||
| Increase 1% | — | (12 | ) | |||||
| Decrease 1% | — | 12 |
| (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, 2016 other postretirement benefit obligation and our 2016 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% | $ | (91 | ) | $ | (3 | ) | ||
| Decrease 1% | 116 | 5 | ||||||
| Healthcare cost trend rate (b): | ||||||||
| Increase 1% | 108 | 8 | ||||||
| Decrease 1% | (87 | ) | (5 | ) | ||||
| 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 2016, we early adopted a new accounting standard relating to stock-based compensation; see Notes 2 and 15 for discussion of how this standard impacted our financial statements and results of operations.
We are currently evaluating the impacts of the pending adoption of new accounting standards relating to revenue recognition, leases, financial instruments and the definition of a business. See Note 2 for information relating to these 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, 2016 and 2015. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2016 and 2015 (dollars in millions):
Pinnacle West – Consolidated
| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||||||||
| Interest | Interest | Interest | |||||||||||||||||||
| 2016 | Rates | Amount | Rates | Amount | Rates | Amount | |||||||||||||||
| 2017 | 1.01 | % | $ | 177 | 1.52 | % | $ | 125 | — | % | $ | — | |||||||||
| 2018 | — | — | 1.37 | % | 50 | 1.75 | % | 32 | |||||||||||||
| 2019 | — | — | 1.46 | % | 100 | 8.75 | % | 500 | |||||||||||||
| 2020 | — | — | — | — | 2.20 | % | 250 | ||||||||||||||
| 2021 | — | — | — | — | — | — | |||||||||||||||
| Years thereafter | — | — | 0.81 | % | 36 | 4.37 | % | 3,090 | |||||||||||||
| Total | $ | 177 | $ | 311 | $ | 3,872 | |||||||||||||||
| Fair value | $ | 177 | $ | 311 | $ | 4,115 |
| 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 |
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, 2016 and 2015. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2016 and 2015 (dollars in millions):
APS — Consolidated
| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||||||||
| Interest | Interest | Interest | |||||||||||||||||||
| 2016 | Rates | Amount | Rates | Amount | Rates | Amount | |||||||||||||||
| 2017 | 0.88 | % | $ | 135 | — | % | $ | — | — | % | $ | — | |||||||||
| 2018 | — | — | 1.37 | % | 50 | 1.75 | % | 32 | |||||||||||||
| 2019 | — | — | 1.46 | % | 100 | 8.75 | % | 500 | |||||||||||||
| 2020 | — | — | — | — | 2.20 | % | 250 | ||||||||||||||
| 2021 | — | — | — | — | — | — | |||||||||||||||
| Years thereafter | — | — | 0.81 | % | 36 | 4.37 | % | 3,090 | |||||||||||||
| Total | $ | 135 | $ | 186 | $ | 3,872 | |||||||||||||||
| Fair value | $ | 135 | $ | 186 | $ | 4,115 |
| 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 |
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 2016 and 2015 (dollars in millions):
| 2016 | 2015 | ||||||
| Mark-to-market of net positions at beginning of year | $ | (154 | ) | $ | (115 | ) | |
| Decrease (Increase) in regulatory asset | 101 | (44 | ) | ||||
| Recognized in OCI: | |||||||
| Change in mark-to-market losses for future deliveries | — | (1 | ) | ||||
| Mark-to-market losses realized during the period | 4 | 6 | |||||
| Change in valuation techniques | — | — | |||||
| Mark-to-market of net positions at end of year | $ | (49 | ) | $ | (154 | ) |
The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2016 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 | 2017 | 2018 | 2019 | 2020 | Total fair value | |||||||||||||||
| Observable prices provided by other external sources | $ | 7 | $ | (4 | ) | $ | (4 | ) | $ | — | $ | (1 | ) | |||||||
| Prices based on unobservable inputs | (9 | ) | (20 | ) | (16 | ) | (3 | ) | (48 | ) | ||||||||||
| Total by maturity | $ | (2 | ) | $ | (24 | ) | $ | (20 | ) | $ | (3 | ) | $ | (49 | ) |
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, 2016 and 2015 (dollars in millions):
| December 31, 2016 Gain (Loss) | December 31, 2015 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 | ) | $ | 2 | $ | (2 | ) | |||||
| Natural gas | 46 | (46 | ) | 35 | (35 | ) | |||||||||
| Total | $ | 48 | $ | (48 | ) | $ | 37 | $ | (37 | ) |
| (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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