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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 2018, with its three units achieving a combined year-end capacity factor of 90.2% and an all-time best collective radiation exposure dose performance in the history of Palo Verde’s operation. For additional information, see "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generation Facilities - Nuclear."
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 August 3, 2015, EPA finalized a rule to limit carbon dioxide emissions from existing power plants (the "Clean Power Plan"), which the EPA later proposed repealing. EPA is considering a proposed replacement to the Clean Power Plan, which was published on August 21, 2018. This new proposal, the "Affordable Clean Energy Rule," is more narrow than its predecessor regulation, and is based entirely upon heat-rate improvements at steam-electric power plants. See "Business - Environmental Matters - Climate Change - Regulatory Initiatives" for additional information on the current status of EPA's carbon pollution standards for EGUs. APS continually analyzes its long-range capital management plans to assess the potential effects of such proposals, 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 the other APS-owned units (Units 1 and 3) at the plant 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, which was later addressed in the 2017 Settlement Agreement. (See Note 3 for details related to the resulting cost recovery.) 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. In early 2017, EPA approved a final rule incorporating APS's compromise proposal, which took effect for Cholla on April 26, 2017. For additional information, see "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Coal-Fueled Generating Facilities - Cholla."
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 general 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. This decision was appealed and, on September 26, 2017, the Arizona Court of Appeals affirmed the ACC's decision on the Four Corners rate adjustment.
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 served 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. 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. (See Note 10 for a discussion of a settlement related to the 2016 Coal Supply Agreement and an advance purchase of coal inventory made under the agreement.) 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 had 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 purchase did not occur during the originally contemplated timeframe. Concurrent with the settlement of the 2016 Coal Supply Agreement matter described in Note 10, NTEC and 4CA agreed to allow for the purchase by NTEC of the 7% interest, consistent with the option. On June 29, 2018, 4CA and NTEC entered into an asset purchase agreement providing for the sale to NTEC of 4CA's 7% interest in Four Corners. Completion of the sale was subject to the receipt of approval by FERC, which was received on July 2, 2018, and the sale transaction closed on July 3, 2018. NTEC purchased the 7% interest at 4CA’s book value, approximately $70 million, and will pay 4CA the purchase price over a period of four years pursuant to a secured interest-bearing promissory note. In connection with the sale, Pinnacle West guaranteed certain obligations that NTEC will have to the other owners of Four Corners, such as NTEC's 7% share of capital expenditures and operating and maintenance expenses. Pinnacle West's guarantee is secured by a portion of APS's payments to be owed to NTEC under the 2016 Coal Supply Agreement.
The 2016 Coal Supply Agreement contained alternate pricing terms for the 7% interest in the event NTEC did not purchase the interest. Until the time that NTEC purchased the 7% interest, the alternate pricing provisions were applicable to 4CA, as the holder of the 7% interest. These terms included a formula under which NTEC must make certain payments to 4CA for reimbursement of operations and maintenance costs and a specified rate of return, offset by revenue generated by 4CA’s power sales. Such payments are due to 4CA at the end of each calendar year. A $10 million payment was due to 4CA at December 31, 2017, which NTEC satisfied by directing to 4CA a prepayment from APS of a portion of a future mine reclamation obligation. The balance of the amount due under this formula at December 31, 2018 for calendar year 2017 was approximately $20 million, which was paid to 4CA on December 14, 2018. The balance of the amount under this formula for calendar year 2018 (up to the date that NTEC purchased the 7% interest) is approximately $10 million, which is due to 4CA at December 31, 2019.
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 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.
On September 15, 2016, NTEC, the company that owns the adjacent mine, filed a motion to intervene for the purpose of dismissing the lawsuit based on NTEC's tribal sovereign immunity. On September 11, 2017, the Arizona District Court issued an order granting NTEC's motion, dismissing the litigation with prejudice, and terminating the proceedings. On November 9, 2017, the environmental group plaintiffs appealed the district court order dismissing their lawsuit. Oral argument for this appeal has been scheduled for March 2019. We cannot predict whether this appeal will be successful and, if it is successful, the outcome of further district court proceedings.
Wastewater Permit. On July 16, 2018, several environmental groups filed a petition for review before the EPA EAB concerning the NPDES wastewater discharge permit for Four Corners, which was reissued on June 12, 2018. The environmental groups allege that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning EPA’s 2015 revised effluent limitation guidelines for steam-electric EGUs, 2014 existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. To address certain of these issues through a reconsidered permit, EPA took action on December 19, 2018 to withdraw the NPDES permit reissued in June 2018. Withdrawal of the permit moots the EAB appeal, and EPA filed a motion to dismiss on that basis. EPA indicated that it anticipates proposing a replacement NPDES permit by March 2019 and, depending on the extent of public comments concerning that proposal, taking final action on a new NPDES permit by June 2019. At this time, we cannot predict the outcome of EPA's reconsideration of the NPDES permit and whether reconsideration will have a material impact on our financial position, results of operations or cash flows.
For additional information, see "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities - Four Corners."
Navajo Plant
The co-owners of the Navajo Plant and the Navajo Nation agreed that the Navajo Plant will remain in operation until December 2019 under the existing plant lease. The co-owners and the Navajo Nation executed a lease extension on November 29, 2017 that will allow for decommissioning activities to begin after the plant ceases operations in December 2019. Various stakeholders including regulators, tribal representatives, the plant's coal supplier and DOI have been meeting to determine if an alternate solution can be reached that would permit continued operation of the plant beyond 2019. Although we cannot predict whether any alternate plans will be found that would be acceptable to all of the stakeholders and feasible to implement, we believe it is probable that the current owners of the Navajo Plant will cease plant operations in December 2019.
APS is currently recovering depreciation and a return on the net book value of its interest in the Navajo Plant over its previously estimated life through 2026. APS will seek continued recovery in rates for the book value of its remaining investment in the plant (see Note 3 for details related to the resulting regulatory asset) plus a return on the net book value as well as other costs related to retirement and closure, which are still being assessed and may be material.
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.
For additional information, see "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities - Navajo Plant."
Natural Gas. APS has six natural gas power plants located throughout Arizona, including Ocotillo. Ocotillo was originally 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 the middle of 2019. (See Note 3 for details of the rate recovery in our 2017 Rate Case Decision.) For additional information, see "Business of Arizona Public Service Company - Energy Sources and Resource Planning - Generation Facilities - Coal-Fueled Generating Facilities - Natural Gas and Oil-Fueled Generating Facilities."
Transmission and Delivery. APS continues to work closely with customers, stakeholders, and regulators to identify and plan for transmission needs that support new customers, 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, 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 new customer sited 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 continues to expect 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.
Energy Storage. APS deploys a number of advanced technologies on its system, including energy storage. Storage can provide capacity, improve power quality, be utilized for system regulation, integrate renewable generation, and can be used to defer certain traditional infrastructure investments. Battery storage can also aid in integrating higher levels of renewables by storing excess energy when system demand is low and renewable production is high and then releasing the stored energy during peak demand hours later in the day and after sunset. APS is utilizing grid-scale battery storage projects to evaluate the potential benefits for customers and further our understanding of how storage works with other advanced technologies and the grid. We are preparing for additional battery storage in the future.
In early 2018, APS entered into a 15-year power purchase agreement for a 65 MW solar facility that charges a 50 MW solar-fueled battery. Service under this agreement is scheduled to begin in 2021. APS issued a request for proposal for approximately 106 MW of battery storage to be located at up to five of its AZ Sun sites. Based upon our evaluation of the RFP responses, APS has decided to expand the initial phase of battery deployment to 141 MW by adding a sixth AZ Sun site. In February 2019, we contracted for the 141 MW and anticipate such facilities could be in service by mid-2020. Additionally, in February 2019, APS signed two 20-year power purchase agreements for energy storage totaling 150 MW. Service under these agreements are scheduled to begin in 2021. We plan to install at least an additional 660 MW of APS-owned solar plus battery storage and stand-alone battery storage systems by the summer of 2025, with the first 260 MW being procured in 2019 (60 MW on additional AZ Sun sites and 100 MW of solar plus 100 MW of battery storage).
Regulatory Matters
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 excluded amounts that were then collected on customer bills through adjustor mechanisms. The application requested 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 had an incremental effect on average customer bills. The average annual customer bill impact of APS’s request was an increase of 5.74% (the average annual bill impact for a typical APS residential customer was 7.96%). See Note 3 for details regarding the principal provisions of APS's application.
On March 27, 2017, a majority of the stakeholders in the general retail rate case, including the ACC Staff, the Residential Utility Consumer Office, limited income advocates and private rooftop solar organizations signed the 2017 Settlement Agreement and filed it with the ACC. The average annual customer bill impact under the 2017 Settlement Agreement was calculated as an increase of 3.28% (the average annual bill impact for a typical APS residential customer was calculated as 4.54%). (See Note 3 for details of the 2017 Settlement Agreement.)
On August 15, 2017, the ACC approved (by a vote of 4-1), the 2017 Settlement Agreement without material modifications. On August 18, 2017, the ACC issued the 2017 Rate Case Decision, which is subject to requests for rehearing and potential appeal. The new rates went into effect on August 19, 2017.
On October 17, 2017, Warren Woodward (an intervener in APS's general retail rate case) filed a Notice of Appeal in the Arizona Court of Appeals, Division One. The notice raises a single issue related to the application of certain rate schedules to new APS residential customers after May 1, 2018. Mr. Woodward filed a second notice of appeal on November 13, 2017 challenging APS’s $5 per month automated metering infrastructure opt-out program. Mr. Woodward’s two appeals have been consolidated and APS requested and was granted intervention. Mr. Woodward filed his opening brief on March 28, 2018. The ACC and APS filed responsive briefs on June 21, 2018. The Arizona Court of Appeals issued a Memorandum Decision on December 11, 2018 affirming the ACC decisions challenged by Mr. Woodward. Mr. Woodward filed a petition for review with the Arizona Supreme Court on January 9, 2019. Review by the Arizona Supreme Court is discretionary. APS cannot predict the outcome of this consolidated appeal but does not believe it will have a material impact on our financial position, results of operations or cash flows.
On January 3, 2018, an APS customer filed a petition with the ACC that was determined by the Administrative Law Judge to be a complaint filed pursuant to Arizona Revised Statute §40-246 and not a request for rehearing. Arizona Revised Statute §40-246 requires the ACC to hold a hearing regarding any complaint alleging that a public service corporation is in violation of any commission order or that the rates being charged are not just and reasonable if the complaint is signed by at least twenty-five customers of the public service corporation. The Complaint alleged that APS is “in violation of commission order” [sic]. On February 13, 2018, the complainant filed an amended Complaint alleging that the rates and charges in the 2017 Rate Case Decision are not just and reasonable. The complainant requested that the ACC hold a hearing on the amended Complaint to determine if the average bill impact on residential customers of the rates and charges approved in the 2017 Rate Case Decision is greater than 4.54% (the average annual bill impact for a typical APS residential customer estimated by APS) and, if so, what effect the alleged greater bill impact has on APS's revenues and the overall reasonableness and justness of APS's rates and charges, in order to determine if there is sufficient evidence to warrant a full-scale rate hearing. The ACC held a hearing on this matter beginning in September 2018 and the hearing was concluded on October 1, 2018. Post-hearing briefing was concluded on December 14, 2018. APS expects a recommended opinion and order from the judge within the first quarter of 2019. APS cannot predict the outcome of this matter.
On December 24, 2018, certain ACC Commissioners filed a letter stating that because the ACC had received a substantial number of complaints that the rate increase authorized by the 2017 Rate Case Decision was much more than anticipated, they believe there is a possibility that APS is earning more than was authorized by the 2017 Rate Case Decision. Accordingly, the ACC Commissioners requested the ACC Staff to perform a rate review of APS using calendar year 2018 as a test year and file a report by May 3, 2019. The ACC Commissioners also asked the ACC Staff to evaluate APS’s efforts to educate its customers regarding the new rates approved in the 2017 Rate Case Decision. On January 9, 2019, the ACC Commissioners voted to open a docket for this matter. APS does not believe that the rate review will have a material impact on our financial position, results of operations or cash flows. However, depending upon the results of the rate review, the ACC may take further actions, including potentially attempting to reopen the 2017 Rate Case Decision. APS cannot predict the outcome of this matter.
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 below and in Note 3.
SCR Cost Recovery. On December 29, 2017, in accordance with the 2017 Rate Case Decision, APS filed a Notice of Intent to file its SCR Adjustment to permit recovery of costs associated with the installation of SCR equipment at Four Corners Units 4 and 5. APS filed the SCR Adjustment request in April 2018. Consistent with the 2017 Rate Case Decision, the request was narrow in scope and addressed only costs associated with this specific environmental compliance equipment. The SCR Adjustment request provided that there would be a $67.5 million annual revenue impact that would be applied as a percentage of base rates for all applicable customers. Also, as provided for in the 2017 Rate Case Decision, APS requested that the rate adjustment become effective no later than January 1, 2019. The hearing for this matter occurred in September 2018. At the hearing, APS accepted ACC Staff's recommendation of a lower annual revenue impact of approximately $58.5 million. The Administrative Law Judge issued a Recommended Opinion and Order finding that the costs for the SCR project were prudently incurred and recommending authorization of the $58.5 million dollar annual revenue requirement related to the installation and operation of the SCRs. Exceptions to the Recommended Opinion and Order were filed by the parties and intervenors on December 7, 2018. The ACC has not issued a decision on this matter. APS anticipates a decision later in 2019.
Renewable Energy**.** The ACC approved the RES in 2006. The renewable energy requirement is 9% of retail electric sales in 2019 and increases annually until it reaches 15% in 2025. In APS’s 2009 general retail rate case settlement agreement, APS agreed to exceed the RES standards, committing to use APS’s best efforts to have 1,700 GWh of new renewable resources in service by year-end 2015, in addition to its RES renewable resource commitments. APS met its settlement commitment in 2015. A component of the RES targets development of distributed energy systems. For additional information, see “Business of Arizona Public Service Company-Energy Sources and Resource Planning - Current and Future Resources-Renewable Energy Standard.”
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. On April 7, 2017, APS filed an amended 2017 RES Implementation Plan and updated budget request which included the revenue neutral transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement. On August 15, 2017, the ACC approved the 2017 RES Implementation Plan.
On June 30, 2017, APS filed its 2018 RES Implementation Plan and proposed a budget of approximately $90 million. APS’s budget request supports existing approved projects and commitments and includes the anticipated transfer of specific revenue requirements into base rates in accordance with the 2017 Settlement Agreement and also requests a permanent waiver of the residential distributed energy requirement for 2018 contained in the RES rules. APS's 2018 RES budget request is lower than the 2017 RES budget due in part to a certain portion of the RES being collected by APS in base rates rather than through the RES adjustor.
On November 20, 2017, APS filed an updated 2018 RES budget to include budget adjustments for APS Solar Communities (formerly known as AZ Sun II), which was approved as part of the 2017 Rate Case Decision. APS Solar Communities is a three-year program authorizing APS to spend $10 million - $15 million in capital costs each year to install utility-owned distributed generation ("DG") systems for low to moderate income residential homes, buildings of non-profit entities, Title I schools and rural government facilities. The 2017 Rate Case Decision provided that all operations and maintenance expenses, property taxes, marketing and advertising expenses, and the capital carrying costs for this program will be recovered through the RES. On June 12, 2018, the ACC approved the 2018 RES Implementation Plan.
On June 29, 2018, APS filed its 2019 RES Implementation Plan and proposed a budget of approximately $89.9 million. APS’s budget request supports existing approved projects and commitments and requests a permanent waiver of the residential distributed energy requirement for 2019 contained in the RES rules. The ACC has not yet ruled on the 2019 RES Implementation Plan.
In September 2016, the ACC initiated a proceeding which will examine the possible modernization and expansion of the RES. On January 30, 2018, ACC Commissioner Tobin proposed a plan in this proceeding which would broaden the RES to include a series of energy policies tied to clean energy sources (the "Energy Modernization Plan"). The Energy Modernization Plan includes replacing the current RES standard with a new standard called the Clean Resource Energy Standard and Tariff ("CREST"), which incorporates the proposals in the Energy Modernization Plan. A set of CREST rules for the ACC's consideration was issued by Commissioner Tobin's office on July 5, 2018. See Note 3 for more information on the RES and the Energy Modernization Plan.
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 EES 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, 2016, APS filed its 2017 Demand Side Management Implementation Plan ("DSM Plan"), in which APS proposed 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 Plan was $62.6 million. On January 27, 2017, APS filed an updated and modified 2017 DSM Plan that incorporated the proposed $4 million Residential Demand Response, Energy Storage and Load Management Program that was filed with the ACC on December 5, 2016 and requested that the budget for the 2017 DSM Plan be increased to $66.6 million. On August 15, 2017, the ACC approved the amended 2017 DSM Plan.
On September 1, 2017, APS filed its 2018 DSM Plan, which proposes modifications to the demand side management portfolio to better meet system and customer needs by focusing on peak demand reductions, storage, load shifting and demand response programs in addition to traditional energy savings measures. The 2018 DSM Plan seeks a reduced requested budget of $52.6 million and requests a waiver of the EES for 2018. On November 14, 2017, APS filed an amended 2018 DSM Plan, which revised the allocations between budget items to address customer participation levels, but kept the overall budget at $52.6 million. The ACC has not yet ruled on the APS 2018 amended DSM Plan.
On December 31, 2018, APS filed its 2019 DSM Plan, which requests a budget of $34.1 million and continues APS's focus on DSM strategies such as peak demand reduction, load shifting, storage and electrification strategies. The ACC has not yet ruled on the APS 2019 DSM Plan. See Note 3 for more information on demand side management.
Tax Expense Adjustor Mechanism and FERC Tax Filing. As part of the 2017 Settlement Agreement, the parties agreed to a rate adjustment mechanism to address potential federal income tax reform and enable the pass-through of certain income tax effects to customers. On December 22, 2017 the Tax Cuts and Jobs Act (“Tax Act”) was enacted. This legislation made significant changes to the federal income tax laws including a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018.
On January 8, 2018, APS filed an application with the ACC requesting that the TEAM be implemented in two steps. The first addresses the change in the marginal federal tax rate from 35% to 21% resulting from the Tax Act and, if approved, would reduce rates by $119.1 million annually through an equal cents per kWh credit. APS asked that this decrease become effective February 1, 2018. On February 22, 2018, the ACC approved the reduction of rates by $119.1 million for the remainder of 2018 through an equal cents per kWh credit applied to all but a small subset of customers who are taking service under specially-approved tariffs. The rate reduction was effective the first billing cycle in March 2018.
The impact of the TEAM, over time, is expected to be earnings neutral. However, on a quarterly basis, there is a difference between the timing and amount of the income tax benefit and the reduction in revenues refunded through the TEAM related to the lower federal income tax rate. The amount of the benefit of the lower federal income tax rate is based on quarterly pre-tax results, while the reduction in revenues from the prior year due to lower customer rates through the TEAM is based on a per kWh sales credit which follows our seasonal kWh sales pattern and is not impacted by earnings of the Company.
On August 13, 2018, APS filed a second request with the ACC to return an additional $86.5 million in tax savings to customers. This second request addresses amortization of non-depreciation related excess deferred taxes previously collected from customers. The ACC has not yet approved this request.
Additionally, as part of this second request, APS informed the ACC of its intent to file a third future request to address the amortization of depreciation related excess deferred taxes, as the Company is currently in the process of seeking IRS guidance regarding the amortization method and period applicable to these depreciation related excess deferred taxes.
The TEAM expressly applies to APS's retail rates with the exception of a small subset of customers taking service under specially-approved tariffs noted above. As discussed in Note 3, FERC issued an order on May 22, 2018 authorizing APS to provide for the cost reductions resulting from the income tax changes in its wholesale transmission rates.
See Note 3 for additional details.
Net Metering. In 2015, the ACC voted to conduct a generic evidentiary hearing on the value and cost of DG 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 Administrative Law Judge 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 opinion and order by the Administrative Law Judge. After making several amendments, the ACC approved the recommended opinion and order by a 4-1 vote. As a result of the ACC’s action, effective with APS’s 2017 Rate Case Decision, the net metering tariff that governs payments for energy exported to the grid from residential rooftop solar systems was replaced by a more formula-driven approach that utilizes inputs from historical wholesale solar power until an avoided cost methodology is developed by the ACC.
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 most recent five-year rolling average price that APS pays for utility-scale solar projects, while a forecasted avoided cost methodology is being developed. The price established by this resource comparison proxy method will be updated annually (between general retail rate cases) but will not be decreased by more than 10% per year. Once the avoided cost methodology is developed, the ACC will determine in APS's subsequent general retail rate cases which method (or a combination of methods) is appropriate to determine the actual price to be paid by APS for exported distributed energy.
In addition, the ACC made the following determinations:
| • | Customers who have interconnected a DG system or submitted an application for interconnection for DG systems prior to September 1, 2017, the date new rates were effective based on APS's 2017 Rate Case Decision, will be grandfathered for a period of 20 years from the date the customer’s interconnection application was accepted by the utility; |
| • | Customers with DG solar systems are to be considered a separate class of customers for ratemaking purposes; and |
| • | Once an export price is set for APS, no netting or banking of retail credits will be available for new DG customers, and the then-applicable export price will be guaranteed for new customers for a period of 10 years. |
This decision of the ACC addresses policy determinations only. The decision states that its principles will be applied in future general retail rate cases, and the policy determinations themselves may be subject to future change, as are all ACC policies. A first-year export energy price of 12.9 cents per kWh is included in the 2017 Settlement Agreement and became effective on September 1, 2017.
In accordance with the 2017 Rate Case Decision, APS filed its request for a second-year export energy price of 11.6 cents per kWh on May 1, 2018. This price reflects the 10% annual reduction discussed above. The new tariff became effective on October 1, 2018.
On January 23, 2017, The Alliance for Solar Choice ("TASC") sought rehearing of the ACC's decision regarding the value and cost of DG. TASC asserted that the ACC improperly ignored the Administrative Procedure Act, failed to give adequate notice regarding the scope of the proceedings, and relied on information that was not submitted as evidence, among other alleged defects. TASC filed a Notice of Appeal in the Arizona Court of Appeals and filed a Complaint and Statutory Appeal in the Maricopa County Superior Court on March 10, 2017. As part of the 2017 Settlement Agreement described above, TASC agreed to withdraw these appeals when the ACC decision implementing the 2017 Settlement Agreement is no longer subject to appellate review.
Subpoena from Arizona Corporation Commissioner Robert Burns. On August 25, 2016, Commissioner Burns, individually and not by action of the ACC as a whole, served subpoenas in APS’s then current retail rate proceeding on APS and Pinnacle West for the production of records and information relating to a range of expenditures from 2011 through 2016. The subpoenas requested information concerning marketing and advertising expenditures, charitable donations, lobbying expenses, contributions to 501(c)(3) and (c)(4) nonprofits and political contributions. The return date for the production of information was set as September 15, 2016. The subpoenas also sought testimony from Company personnel having knowledge of the material, including the Chief Executive Officer.
On September 9, 2016, APS filed with the ACC a motion to quash the subpoenas or, alternatively, to stay APS's obligations to comply with the subpoenas and decline to decide APS's motion pending court proceedings. Contemporaneously with the filing of this motion, APS and Pinnacle West filed a complaint for special action and declaratory judgment in the Superior Court of Arizona for Maricopa County, seeking a declaratory judgment that 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 the production of all information previously requested through the subpoenas. Neither APS nor Pinnacle West produced the information requested and instead objected to the subpoena. On March 10, 2017, Commissioner Burns filed suit against APS and Pinnacle West in the Superior Court of Arizona for Maricopa County in an effort to enforce his subpoenas. On March 30, 2017, APS filed a motion to dismiss Commissioner Burns' suit against APS and Pinnacle West. In response to the motion to dismiss, the court stayed the suit and ordered Commissioner Burns to file a motion to compel the production of the information sought by the subpoenas with the ACC. On June 20, 2017, the ACC denied the motion to compel.
On August 4, 2017, Commissioner Burns amended his complaint to add all of the ACC Commissioners and the ACC itself as defendants. All defendants moved to dismiss the amended complaint. On February 15, 2018, the Superior Court dismissed Commissioner Burns’ amended complaint. On March 6, 2018, Commissioner Burns filed an objection to the proposed final order from the Superior Court and a motion to further amend his complaint. The Superior Court permitted Commissioner Burns to amend his complaint to add a claim regarding his attempted investigation into whether his fellow commissioners should have been disqualified from voting on APS’s 2017 rate case. Commissioner Burns filed his second amended complaint, and all defendants filed responses opposing the second amended complaint and requested that it be dismissed. Oral argument occurred in November 2018 regarding the motion to dismiss. On December 18, 2018, the trial court granted the defendants’ motions to dismiss and entered final judgment on January 18, 2019. On February 13, 2019, Commissioner Burns filed a notice of appeal. APS and Pinnacle West cannot predict the outcome of this matter.
Renewable Energy Ballot Initiative. On February 20, 2018, a renewable energy advocacy organization filed with the Arizona Secretary of State a ballot initiative for an Arizona constitutional amendment requiring Arizona public service corporations to provide at least 50% of their annual retail sales of electricity from renewable sources by 2030. For purposes of the proposed amendment, eligible renewable sources would not include nuclear generating facilities. The initiative was placed on the November 2018 Arizona elections ballot. On November 6, 2018, the initiative failed to receive adequate voter support and was defeated.
Energy Modernization Plan. On January 30, 2018, ACC Commissioner Tobin proposed the Energy Modernization Plan, which consists of a series of energy policies tied to clean energy sources such as energy storage, biomass, energy efficiency, electric vehicles, and expanded energy planning through the IRP process. The Energy Modernization Plan includes replacing the current RES standard with a new standard called the CREST, which incorporates the proposals in the Energy Modernization Plan. On February 22, 2018, the ACC Staff filed a Notice of Inquiry to further examine the matter. As a part of this proposal, the ACC voted in March 2018 to direct utilities to develop a comprehensive biomass generation plan to be included in each utility’s RES Implementation Plan. On July 5, 2018, Commissioner Tobin’s office issued a set of draft CREST rules for the ACC’s consideration.
In August 2018, the ACC directed ACC Staff to open a new rulemaking docket which will address a wide range of energy issues, including the Energy Modernization Plan proposals. The rulemaking will consider possible modifications to existing ACC rules, such as the Renewable Energy Standard, Electric and Gas Energy Efficiency Standards, Net Metering, Resource Planning, and the Biennial Transmission Assessment, as well as the development of new rules regarding forest bioenergy, electric vehicles, interconnection of distributed generation, baseload security, blockchain technology and other technological developments, retail competition, and other energy-related topics. Workshops on these energy issues are scheduled to be held throughout 2019. APS cannot predict the outcome of this matter.
Integrated Resource Planning**.** ACC rules require utilities to develop fifteen-year IRPs which describe how the utility plans to serve customer load in the plan timeframe. The ACC reviews each utility’s IRP to determine if it meets the necessary requirements and whether it should be acknowledged. In March of 2018, the ACC reviewed the 2017 IRPs of its jurisdictional utilities and voted to not acknowledge any of the plans. APS does not believe that this lack of acknowledgment will have a material impact on our financial position, results of operations or cash flows. Based on an ACC decision, APS is required to file a Preliminary Resource Plan by April 1, 2019 and its final IRP by April 1, 2020.
FERC Matter. 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. On October 5, 2017, FERC issued an order denying APS's request for rehearing. FERC also upheld its prior determination that the agreement relating to the settlement was a jurisdictional contract and should have been filed with FERC. APS cannot predict whether or if the enforcement division will take any action. APS filed an appeal of FERC's July 1, 2016 and October 5, 2017 orders with the United States Court of Appeals for the Ninth Circuit on December 4, 2017. That proceeding is pending and APS cannot predict the outcome of the proceeding.
Financial Strength and Flexibility
Pinnacle West and APS currently have ample borrowing capacity under their respective credit facilities, and may readily access these facilities ensuring adequate liquidity for each company. Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.
Other Subsidiaries
Bright Canyon Energy. On July 31, 2014, Pinnacle West announced its creation of a wholly-owned subsidiary, BCE. BCE's focus is on new growth opportunities that leverage the Company’s core expertise in the electric energy industry. BCE’s first initiative is a 50/50 joint venture with BHE U.S. Transmission LLC, a subsidiary of Berkshire Hathaway Energy Company. The joint venture, named TransCanyon, is pursuing independent transmission opportunities within the eleven states that comprise the Western Electricity Coordinating Council, excluding opportunities related to transmission service that would otherwise be provided under the tariffs of the retail service territories of the venture partners’ utility affiliates. 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.
Operating Revenues. For the years 2016 through 2018, retail electric revenues comprised approximately 95% of our total operating revenues. Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.
Actual and Projected Customer and Sales Growth. Retail customers in APS’s service territory increased 1.7% for the year ended December 31, 2018 compared with the prior year. For the three years 2016 through 2018, APS’s customer growth averaged 1.6% per year. We currently project annual customer growth to be 1.5 - 2.5% for 2019 and to average in the range of 1.5 - 2.5% for 2019 through 2021 based on our assessment of improving economic conditions in Arizona.
Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, increased 0.1% for the year ended December 31, 2018 compared with the prior year. Improving economic conditions and customer growth were offset by energy savings driven by customer conservation, energy efficiency, and distributed renewable generation initiatives. For the three years 2016 through 2018, annual retail electricity sales were about flat, adjusted to exclude the effects of weather variations. We currently project that annual retail electricity sales in kWh will increase in the range of 1.0 - 2.0% for 2019 and increase on average in the range of 1.5 - 2.5% during 2019 through 2021, 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 DG, and responses to retail price changes. Based on past experience, a reasonable range of variation in our kWh sales projections attributable to such economic factors
under normal business conditions can result in increases or decreases in annual net income of up to approximately $15 million.
Weather. In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Historically, extreme weather variations have resulted in annual variations in net income in excess of $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, unplanned outages, planned outages (typically scheduled in the spring and fall), renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors. See Note 2 for discussion of new accounting guidance related to the presentation of net periodic pension and postretirement benefit costs.
Depreciation and Amortization Expenses. Depreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See "Liquidity and Capital Resources" below for information regarding the planned additions to our facilities and income tax impacts related to bonus depreciation.
Pension and Other Postretirement Non-Service Credits - Net*.* Pension and other postretirement non-service credits can be impacted by changes in our actuarial assumptions. The most relevant actuarial assumptions are the discount rate used to measure our net periodic costs/credit, the expected long-term rate of return on plan assets used to estimate earnings on invested funds over the long-term, the mortality assumptions and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary. See Note 2 for discussion of new accounting guidance related to the presentation of net periodic pension and postretirement benefit costs.
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 2018, 11.2% for 2017 and 2016. We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units and transmission and distribution facilities.
Income Taxes**.** Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions and non-taxable items, such as AFUDC. In addition, income taxes may also be affected by the settlement of issues with taxing authorities. On December 22, 2017, the Tax Act was enacted and was generally effective on January 1, 2018. Changes which will impact the Company include a reduction in the corporate tax rate to 21%, revisions to the rules related to tax bonus depreciation, limitations on interest deductibility and an associated exception for certain public utilities, and requirements that certain excess deferred tax amounts of regulated utilities be normalized. (See Note 4 for details of the impacts on the Company as of December 31, 2018.) In APS's recent general retail rate case, the ACC approved a Tax Expense
Adjustor Mechanism which will be used to pass through the income tax effects to retail customers of the Tax Act. (See Note 3 for details of the TEAM.)
Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 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 – 2018 compared with 2017.
Our consolidated net income attributable to common shareholders for the year ended December 31, 2018 was $511 million, compared with $488 million for the prior year. The results reflect an increase of approximately $19 million for the regulated electricity segment primarily due to higher revenue resulting from the retail regulatory settlement effective August 19, 2017, higher transmission revenues, higher retail revenues due to customer growth and higher average effective prices due to customer usage patterns and changes relating to customer program eligibility, partially offset by higher operations and maintenance expense and higher depreciation and amortization.
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
| Year Ended December 31, | |||||||||||
| 2018 | 2017 | Net change | |||||||||
| (dollars in millions) | |||||||||||
| Regulated Electricity Segment: | |||||||||||
| Operating revenues less fuel and purchased power expenses | $ | 2,590 | $ | 2,561 | $ | 29 | |||||
| Operations and maintenance | (1,025 | ) | (936 | ) | (89 | ) | |||||
| Depreciation and amortization | (581 | ) | (532 | ) | (49 | ) | |||||
| Taxes other than income taxes | (212 | ) | (183 | ) | (29 | ) | |||||
| Pension and other postretirement non-service credits - net | 50 | 25 | 25 | ||||||||
| All other income and expenses, net | 59 | 29 | 30 | ||||||||
| Interest charges, net of allowance for borrowed funds used during construction | (218 | ) | (198 | ) | (20 | ) | |||||
| Income taxes (Note 4) | (134 | ) | (256 | ) | 122 | ||||||
| Less income related to noncontrolling interests (Note 18) | (19 | ) | (19 | ) | — | ||||||
| Regulated electricity segment income | 510 | 491 | 19 | ||||||||
| All other | 1 | (3 | ) | 4 | |||||||
| Net Income Attributable to Common Shareholders | $ | 511 | $ | 488 | $ | 23 |
Operating revenues less fuel and purchased power expenses**.** Regulated electricity segment operating revenues less fuel and purchased power expenses were $29 million higher for the year ended December 31, 2018 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) | |||||||||||
| Impacts of retail regulatory settlement effective August 19, 2017 (Note 3) | |||||||||||
| Increase in net retail base rates | $ | 104 | $ | — | $ | 104 | |||||
| Change in residential rate design and seasonal rates (a) | 7 | — | 7 | ||||||||
| Higher transmission revenues (Note 3) | 27 | — | 27 | ||||||||
| Higher retail revenues due to higher customer growth and changes in customer usage patterns, partially offset by the impacts of energy efficiency and distributed generation | 26 | 2 | 24 | ||||||||
| Higher demand side management regulatory surcharges and renewable energy regulatory surcharges and purchased power, partially offset in operations and maintenance costs | 1 | (9 | ) | 10 | |||||||
| Refunds due to lower federal corporate income tax rate (Note 3) | (143 | ) | — | (143 | ) | ||||||
| Effects of weather | (15 | ) | (6 | ) | (9 | ) | |||||
| Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals | 120 | 121 | (1 | ) | |||||||
| Miscellaneous items, net | 3 | (7 | ) | 10 | |||||||
| Total | $ | 130 | $ | 101 | $ | 29 |
(a) As part of the 2017 Settlement Agreement, rate design changes were implemented that moved some revenue responsibility from summer to non-summer months. The change was made to better align revenue collections with costs of service.
Operations and maintenance. Operations and maintenance expenses increased $89 million for the year ended December 31, 2018 compared with the prior-year period primarily because of:
| • | An increase of $37 million related to public outreach costs at the parent company primarily associated with the ballot initiative (see Note 3); |
| • | An increase of $21 million in fossil generation costs primarily due to higher planned outage and operating costs; |
| • | An increase of $12 million related to costs for renewable energy and similar regulatory programs, which was partially offset in operating revenues and purchased power; |
| • | An increase of $11 million for costs related to information technology; |
| • | An increase of $9 million in transmission, distribution, and customer service costs primarily due to maintenance costs and customer bad debt expense; |
| • | An increase of $6 million to inform customers about APS's clean energy focus; |
| • | A decrease of $6 million related to employee benefit cost; |
| • | A decrease of $5 million related to the absence of the Navajo Plant capital projects canceled in 2017 due to the expected plant retirement, which were deferred for regulatory recovery in depreciation; and |
| • | An increase of $4 million related to miscellaneous other factors. |
Depreciation and amortization. Depreciation and amortization expenses were $49 million higher for the year ended December 31, 2018 compared with the prior-year period primarily due to increased depreciation and amortization rates of $36 million, increased plant in service of $8 million and the absence of the regulatory deferral of the canceled capital projects in 2017 associated with the expected Navajo Plant retirement of $5 million.
Taxes other than income taxes. Taxes other than income taxes were $29 million higher for the year ended December 31, 2018 compared with the prior-year period primarily due to higher property values and the amortization of our property tax deferral regulatory asset.
Pension and other postretirement non-service credits, net. Pension and other postretirement non-service credits, net were $25 million higher for the year ended December 31, 2018 compared to the prior-year period primarily due to higher market returns and the adoption of new pension and other postretirement accounting guidance in 2018 (see Notes 2 and 7).
All other income and expenses, net. All other income and expenses, net were $30 million higher for the year ended December 31, 2018 compared with the prior-year period primarily due to the debt return on the Four Corners SCR deferrals (Note 3) and increased allowance for equity funds used during construction.
Interest charges, net of allowance for borrowed funds used during construction. Interest charges, net of allowance for borrowed funds used during construction, were $20 million higher for the year ended December 31, 2018 compared with the prior-year period primarily due to higher debt balances in the current period.
Income taxes. Income taxes were $122 million lower for the year ended December 31, 2018 compared with the prior-year period primarily due to the effects of the federal tax reform and lower pretax income in the current year period, partially offset by certain non-deductible costs (See Note 4).
Operating Results – 2017 compared with 2016.
Our consolidated net income attributable to common shareholders for the year ended December 31, 2017 was $488 million, compared with $442 million for the prior year. The results reflect an increase of approximately $48 million for the regulated electricity segment primarily due to higher revenue resulting from the retail regulatory settlement effective August 19, 2017, higher transmission revenues, higher retail revenues due to customer growth and higher average effective prices due to customer usage patterns and changes relating to customer program eligibility, partially offset by higher depreciation and amortization primarily due to increased plant in service and higher depreciation and amortization rates.
The following table presents net income attributable to common shareholders by business segment compared with the prior year:
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | Net change | |||||||||
| (dollars in millions) | |||||||||||
| Regulated Electricity Segment: | |||||||||||
| Operating revenues less fuel and purchased power expenses | $ | 2,561 | $ | 2,407 | $ | 154 | |||||
| Operations and maintenance | (936 | ) | (926 | ) | (10 | ) | |||||
| Depreciation and amortization | (532 | ) | (485 | ) | (47 | ) | |||||
| Taxes other than income taxes | (183 | ) | (166 | ) | (17 | ) | |||||
| Pension and other postretirement non-service credits - net | 25 | 20 | 5 | ||||||||
| All other income and expenses, net | 29 | 35 | (6 | ) | |||||||
| Interest charges, net of allowance for borrowed funds used during construction | (198 | ) | (186 | ) | (12 | ) | |||||
| Income taxes | (256 | ) | (237 | ) | (19 | ) | |||||
| Less income related to noncontrolling interests (Note 18) | (19 | ) | (19 | ) | — | ||||||
| Regulated electricity segment income | 491 | 443 | 48 | ||||||||
| All other | (3 | ) | (1 | ) | (2 | ) | |||||
| Net Income Attributable to Common Shareholders | $ | 488 | $ | 442 | $ | 46 |
Operating revenues less fuel and purchased power expenses**.** Regulated electricity segment operating revenues less fuel and purchased power expenses were $154 million higher for the year ended December 31, 2017 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) | |||||||||||
| Impacts of retail regulatory settlement effective August 19, 2017 (Note 4) | $ | 55 | $ | — | $ | 55 | |||||
| Transmission revenues (Note 4): | |||||||||||
| Higher transmission revenues | 30 | — | 30 | ||||||||
| Absence of 2016 FERC disallowance | 12 | — | 12 | ||||||||
| Higher retail revenues due to customer growth and higher average effective prices due to customer usage patterns and changes relating to customer program participation (a) | 21 | (3 | ) | 24 | |||||||
| Lost fixed cost recovery | 14 | — | 14 | ||||||||
| Effects of weather | 9 | 3 | 6 | ||||||||
| Changes in net fuel and purchased power costs, including off-system sales margins and related deferrals | (83 | ) | (92 | ) | 9 | ||||||
| Higher demand side management regulatory surcharges and renewable energy regulatory surcharges and purchased power partially offset in operations and maintenance costs | 9 | 2 | 7 | ||||||||
| Miscellaneous items, net | (3 | ) | — | (3 | ) | ||||||
| Total | $ | 64 | $ | (90 | ) | $ | 154 |
(a) Partially offset by the impacts of efficiency programs and distributed generation.
Operations and maintenance**.** Operations and maintenance expenses increased $10 million for the year ended December 31, 2017 compared with the prior year primarily because of:
| • | An increase of $15 million for employee benefit costs; |
| • | An increase of $9 million for costs primarily related to information technology and other corporate support; |
| • | An increase 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 $5 million related to the Navajo Plant capital projects canceled due to the expected plant retirement, which were deferred for regulatory recovery in depreciation; |
| • | A decrease of $12 million for lower Palo Verde operating costs; |
| • | A decrease of $11 million in fossil generation costs primarily due to less planned outage activity in the current year and lower Navajo Plant costs; |
| • | A decrease of $5 million primarily due to the absence of 2016 costs to support the Company's positions on a solar net metering ballot initiative in Arizona; and |
| • | An increase of $1 million related to miscellaneous other factors. |
Depreciation and amortization. Depreciation and amortization expenses were $47 million higher for the year ended December 31, 2017 compared with the prior year primarily related to increased plant in service of $32 million and increased depreciation and amortization rates of $19 million, partially offset by the regulatory deferral of the canceled capital projects associated with the expected Navajo Plant retirement of $5 million.
Taxes other than income taxes. Taxes other than income taxes were $17 million higher for the year ended December 31, 2017 compared with the prior year primarily due to higher property values and the amortization of our property tax deferral regulatory asset.
Pension and other postretirement non-service credits, net. Pension and other postretirement non-service credits, net were $5 million higher for the year ended December 31, 2017 compared to the prior-year period primarily due to higher market returns.
All other income and expenses, net. All other income and expenses, net, were $6 million lower for the year ended December 31, 2017 compared with the prior year primarily due to the absence of a gain on sale of a transmission line, which occurred in 2016.
Interest charges, net of allowance for borrowed funds used during construction**.** Interest charges, net of allowance for borrowed funds used during construction, increased $12 million for the year ended December 31, 2017 compared with the prior year, primarily because of higher debt balances in the current year.
Income taxes. Income taxes were $19 million higher for the year ended December 31, 2017 compared with the prior year primarily due to the effects of higher pretax income in the current year and the effects of the federal tax reform, partially offset by a lower effective tax rate primarily due to stock compensation. The stock compensation guidance requires all excess income tax benefits and deficiencies arising from share-based payments to be recognized in earnings in the period they occur, which causes effective tax rate fluctuations when stock compensation payouts occur.
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, 2018, APS’s common equity ratio, as defined, was 54%. Its total shareholder equity was approximately $5.7 billion, and total capitalization was approximately $10.5 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $4.2 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.
On December 20, 2018, the Joint Committee on Taxation (“JCT”) released the general explanation of the Tax Act. The document - commonly referred to as the "Blue Book" - provides a comprehensive technical description of the Tax Act and includes the legislative intent of Congress with respect to the changes made by provisions of the Tax Act. The “Blue Book” provides clarification that the intent of the Tax Act was to exclude from the definition of bonus depreciation qualified property any property placed in service by a regulated public utility after December 31, 2017. As a result, the Company currently does not anticipate recognizing any cash tax benefits related to bonus depreciation for property placed in service on or after January 1, 2018 (See Note 4).
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, 2018, 2017 and 2016 (dollars in millions):
Pinnacle West Consolidated
| 2018 | 2017 | 2016 | |||||||||
| Net cash flow provided by operating activities | $ | 1,277 | $ | 1,118 | $ | 1,023 | |||||
| Net cash flow used for investing activities | (1,193 | ) | (1,429 | ) | (1,252 | ) | |||||
| Net cash flow provided by (used for) financing activities | (92 | ) | 316 | 198 | |||||||
| Net increase (decrease) in cash and cash equivalents | $ | (8 | ) | $ | 5 | $ | (31 | ) |
Arizona Public Service Company
| 2018 | 2017 | 2016 | |||||||||
| Net cash flow provided by operating activities | $ | 1,255 | $ | 1,162 | $ | 1,010 | |||||
| Net cash flow used for investing activities | (1,187 | ) | (1,401 | ) | (1,219 | ) | |||||
| Net cash flow provided by (used for) financing activities | (76 | ) | 244 | 196 | |||||||
| Net increase (decrease) in cash and cash equivalents | $ | (8 | ) | $ | 5 | $ | (13 | ) |
Operating Cash Flows
2018 Compared with 2017. Pinnacle West’s consolidated net cash provided by operating activities was $1,277 million in 2018 compared to $1,118 million in 2017. The increase of $159 million in net cash provided is primarily due to higher cash receipts from operating activities as a result of the retail regulatory settlement effective August 19, 2017, higher transmission receipts and higher receipts due to customer growth and higher average effective prices. These items are partially offset by higher payments for operations and maintenance, income taxes, other taxes and interest. The difference between APS and Pinnacle West's net cash provided by operating activities primarily relates to Pinnacle West's cash payments for 4CA's operating costs and differences in other operating cash payments.
2017 Compared with 2016. Pinnacle West’s consolidated net cash provided by operating activities was $1,118 million in 2017 compared to $1,023 million in 2016. The increase of $95 million in net cash provided
is primarily due to lower payments of operations and maintenance, fuel and purchased power costs and higher cash receipts, partially offset by no collateral posted in 2017 compared to $17 million returned in 2016. The difference between APS and Pinnacle West's net cash provided by operating activities primarily relates to Pinnacle West's cash payments for 4CA's operating costs and differences in other operating cash payments.
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 110% funded as of January 1, 2019 and 117% as of January 1, 2018. Under GAAP, the qualified pension plan was 90% funded as of January 1, 2019 and 95% funded as of January 1, 2018. 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 $50 million in 2018, $100 million in 2017, and $100 million in 2016. 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 $350 million during the 2019-2021 period. With regard to contributions to our other postretirement benefit plan, we did not make a contribution in 2018. We made a contribution of approximately $1 million in each of 2017 and 2016. We do not expect to make any contributions over the next three years to our other postretirement benefit plans. In 2018, the Company was reimbursed $72 million for prior years retiree medical claims from the other postretirement benefit plan trust assets.
Because of plan changes in 2014, the Company sought IRS approval to move approximately $186 million of other postretirement benefit trust assets into a new trust account to pay for active union employee medical costs. In December 2016, FERC approved a methodology for determining the amount of other postretirement benefit trust assets to transfer into a new trust account to pay for active union employee medical costs. On January 2, 2018, these funds were moved to the new trust account, which is included in the other special use funds on the Consolidated Balance Sheets. The Company and the IRS executed a final Closing Agreement on March 2, 2018. The Company made an informational filing with FERC during February 2018. It is the Company’s understanding that completion of these regulatory requirements permits access to approximately $186 million for the sole purpose of paying active union employee medical benefits.
Investing Cash Flows
2018 Compared with 2017. Pinnacle West’s consolidated net cash used for investing activities was $1,193 million in 2018, compared to $1,429 million in 2017. The decrease of $236 million in net cash used primarily related to decreased capital expenditures. The difference between APS and Pinnacle West's net cash used for investing activities primarily relates to Pinnacle West's investing cash activity related to 4CA.
2017 Compared with 2016. Pinnacle West’s consolidated net cash used for investing activities was $1,429 million in 2017, compared to $1,252 million in 2016. The increase of $177 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, | |||||||||||
| 2019 | 2020 | 2021 | |||||||||
| APS | |||||||||||
| Generation: | |||||||||||
| Clean: | |||||||||||
| Nuclear Fuel | $ | 72 | $ | 64 | $ | 64 | |||||
| Nuclear Generation | 70 | 68 | 67 | ||||||||
| Renewables (a) | 16 | 18 | 3 | ||||||||
| New Resources (b) | 77 | 119 | 305 | ||||||||
| Environmental | 30 | 40 | 71 | ||||||||
| New Gas Generation | 16 | — | — | ||||||||
| Other Generation | 109 | 116 | 108 | ||||||||
| Distribution | 508 | 462 | 559 | ||||||||
| Transmission | 202 | 169 | 199 | ||||||||
| Other (c) | 126 | 147 | 108 | ||||||||
| Total APS | $ | 1,226 | $ | 1,203 | $ | 1,484 |
| (a) | Primarily APS Solar Communities program |
| (b) | Projected future generation resources, which may include energy storage, renewable projects, and other clean energy projects |
| (c) | Primarily information systems and facilities projects |
Generation capital expenditures are comprised of various additions and improvements to APS’s clean resources, including nuclear plants, renewables and projected future new resources. Generation capital expenditures also include improvements to existing fossil plants. Examples of the types of projects included in the forecast of generation capital expenditures are additions of roof top solar systems, new clean resources, and upgrades and capital replacements of various nuclear and fossil power plant equipment, such as turbines, boilers and environmental equipment. We are monitoring the status of environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.
Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction. Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.
Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.
Financing Cash Flows and Liquidity
2018 Compared with 2017. Pinnacle West’s consolidated net cash used for financing activities was $92 million in 2018, compared to $316 million of net cash provided in 2017, an increase of $408 million in net
cash used. The increase in net cash used by financing activities includes $403 million in lower issuances of long-term debt, higher long-term debt repayments of $57 million and higher dividend payments of $19 million through December 31, 2018, which are partially offset by $63 million in lower net short-term debt.
APS’s consolidated net cash used by financing activities was $76 million in 2018, compared to $244 million of net cash provided in 2017, an increase of $320 million in net cash used. The increase in net cash used by financing activities includes $254 million in lower issuances of long-term debt, higher long-term debt repayments of $182 million and higher dividend payments of $19 million through December 31, 2018, which are partially offset by $136 million in lower net short-term debt.
2017 Compared with 2016. Pinnacle West’s consolidated net cash provided by financing activities was $316 million in 2017, compared to $198 million in 2016, an increase of $118 million in net cash provided. The net cash provided by financing activities includes $245 million in lower long-term debt repayments and $155 million higher issuances of long-term debt through December 31, 2017, partially offset by a $259 million net decrease in short-term borrowings and $16 million of higher dividend payments.
APS’s consolidated net cash provided by financing activities was $244 million in 2017, compared to $196 million in 2016, an increase of $48 million in net cash provided. The net cash provided by financing activities includes $370 million in lower long-term debt repayments and $108 million in higher equity infusions from Pinnacle West, partially offset by $143 million lower issuances of long-term debt through December 31, 2017, $271 million net decrease in short-term borrowings and $16 million of higher dividend payments.
Significant Financing Activities. On December 19, 2018, the Pinnacle West Board of Directors declared a dividend of $0.7375 per share of common stock, payable on March 1, 2019 to shareholders of record on February 1, 2019. During 2018, Pinnacle West increased its indicated annual dividend from $2.78 per share to $2.95 per share. For the year ended December 31, 2018, Pinnacle West's total dividends paid per share of common stock were $2.82 per share, which resulted in dividend payments of $309 million.
On May 30, 2018, APS purchased all $32 million of Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series C, due 2029. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2017.
On June 26, 2018, APS repaid at maturity APS's $50 million term loan facility.
On August 9, 2018, APS issued $300 million of 4.20% unsecured senior notes that mature on August 15, 2048. The net proceeds from the sale of the notes were used to repay commercial paper borrowings.
On November 30, 2018, APS repaid its $100 million term loan facility that would have matured April 22, 2019.
On December 21, 2018, Pinnacle West entered into a $150 million term loan facility that matures December 2020. The proceeds were used for general corporate purposes.
On December 21, 2018, Pinnacle West contributed $150 million into APS in the form of an equity infusion. APS used this contribution to repay short-term indebtedness.
Available Credit Facilities**.** Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.
On June 28, 2018, Pinnacle West refinanced its 364-day $125 million unsecured revolving credit facility that would have matured on July 30, 2018 with a new 364-day $150 million credit facility that matures June 27, 2019. Borrowings under the facility bear interest at LIBOR plus 0.70% per annum. At December 31, 2018, Pinnacle West had $54 million outstanding under the facility.
On July 12, 2018, Pinnacle West replaced its $200 million revolving credit facility that would have matured in May 2021, with a new $200 million facility that matures in July 2023. Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders. At December 31, 2018, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and $22 million of commercial paper borrowings.
On July 12, 2018, APS replaced its $500 million revolving credit facility that would have matured in May 2021, with a new $500 million facility that matures in July 2023.
At December 31, 2018, APS had two revolving credit facilities totaling $1 billion, including a $500 million credit facility that matures in June 2022 and the above-mentioned $500 million facility. 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, 2018, APS had no 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 other outstanding letters of credit.
Other Financing Matters. See Note 16 for information related to the change in our margin and collateral accounts.
Debt Provisions
Pinnacle West’s and APS’s debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with 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, 2018, the ratio was approximately 50% 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 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 15, 2019 are shown below. We are disclosing these credit ratings to enhance understanding of our cost of short-term and long-term capital and our ability to access the markets for liquidity and long-term debt. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’s securities and/or result in an increase in the cost of, or limit access to, capital. Such revisions may also result in substantial additional cash or other collateral requirements related to certain derivative instruments, insurance policies, natural gas transportation, fuel supply, and other energy-related contracts. At this time, we believe we have sufficient available liquidity resources to respond to a downward revision to our credit ratings.
| Moody’s | Standard & Poor’s | Fitch | |||
| Pinnacle West | |||||
| Corporate credit rating | A3 | A- | A- | ||
| Senior unsecured | A3 | BBB+ | A- | ||
| Commercial paper | P-2 | A-2 | F2 | ||
| Outlook | 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, 2018 (dollars in millions):
| 2019 | 2020- 2021 | 2022- 2023 | Thereafter | Total | |||||||||||||||
| Long-term debt payments, including interest: (a) | |||||||||||||||||||
| APS | $ | 695 | $ | 589 | $ | 336 | $ | 6,419 | $ | 8,039 | |||||||||
| Pinnacle West | 12 | 461 | — | — | 473 | ||||||||||||||
| Total long-term debt payments, including interest | 707 | 1,050 | 336 | 6,419 | 8,512 | ||||||||||||||
| Short-term debt payments, including interest (b) | 76 | — | — | — | 76 | ||||||||||||||
| Fuel and purchased power commitments (c) | 574 | 1,093 | 1,103 | 5,701 | 8,471 | ||||||||||||||
| Renewable energy credits (d) | 37 | 70 | 61 | 155 | 323 | ||||||||||||||
| Purchase obligations (e) | 48 | 20 | 20 | 206 | 294 | ||||||||||||||
| Coal reclamation | 32 | 42 | 46 | 167 | 287 | ||||||||||||||
| Nuclear decommissioning funding requirements | 2 | 4 | 4 | 52 | 62 | ||||||||||||||
| Noncontrolling interests (f) | 23 | 46 | 46 | 159 | 274 | ||||||||||||||
| Operating lease payments (g) | 14 | 22 | 12 | 42 | 90 | ||||||||||||||
| Total contractual commitments | $ | 1,513 | $ | 2,347 | $ | 1,628 | $ | 12,901 | $ | 18,389 |
| (a) | The long-term debt matures at various dates through 2048 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2018 (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). |
| (g) | Commitments relating to purchased power lease contracts are included within the fuel and purchased power commitments line above. |
This table excludes $41 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. Estimated minimum required pension contributions are zero for 2019, 2020 and 2021 (see Note 7).
CRITICAL ACCOUNTING POLICIES
In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.
Regulatory Accounting
Regulatory accounting allows for the actions of regulators, such as the ACC and FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent amounts collected in rates to recover costs expected to be incurred in the future or amounts collected in excess of costs incurred and are refundable to customers. Management 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, except for pension benefits which would be charged to OCI and result in lower future earnings. We had $1,510 million of regulatory assets and $2,492 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2018.
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.
On January 1, 2018, we adopted new accounting standard ASU 2017-07, Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This new standard changed our income statement presentation of net periodic benefit cost and allows only the service cost component of periodic net benefit cost to be eligible for capitalization. See Note 2 for additional information.
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2018 reported pension liability on the Consolidated Balance Sheets and our 2018 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% | $ | (328 | ) | $ | (12 | ) | ||
| Decrease 1% | 397 | 15 | ||||||
| Expected long-term rate of return on plan assets: | ||||||||
| Increase 1% | — | (21 | ) | |||||
| Decrease 1% | — | 21 |
| (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, 2018 other postretirement benefit obligation and our 2018 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% | $ | (85 | ) | $ | (1 | ) | ||
| Decrease 1% | 108 | 6 | ||||||
| Healthcare cost trend rate (b): | ||||||||
| Increase 1% | 101 | 10 | ||||||
| Decrease 1% | (81 | ) | (4 | ) | ||||
| Expected long-term rate of return on plan assets – pretax: | ||||||||
| Increase 1% | — | (5 | ) | |||||
| Decrease 1% | — | 5 |
| (a) | Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point. |
| (b) | This assumes a 1% change in the initial and ultimate healthcare cost trend rate. |
See Notes 2 and 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, investments held in our other special use funds, certain cash equivalents, and plan assets held in our retirement and other benefit plans at fair value on a recurring basis. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use inputs, or assumptions that market participants would use, to determine fair market value. We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The significance of a particular input determines how the instrument is classified in a fair value hierarchy. The determination of fair value sometimes requires subjective and complex judgment. Our assessment of the inputs and the significance of a particular input to fair value measurement may affect the valuation of the instruments and their placement within a fair value hierarchy. Actual results could differ from our estimates of fair value. See Note 1 for a discussion of accounting policies and Note 13 for fair value measurement disclosures.
Asset Retirement Obligations
We recognize an ARO for the future decommissioning or retirement of our tangible long-lived assets for which a legal obligation exists. The ARO liability represents an estimate of the fair value of the current obligation related to decommissioning and the retirement of those assets. ARO measurements inherently involve uncertainty in the amount and timing of settlement of the liability. We use an expected cash flow approach to measure the amount we recognize as an ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the asset’s current license or lease term and expected decommissioning dates. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related assets. In addition, we accrete the ARO liability to reflect the passage of time. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets. In accordance with GAAP accounting, APS accrues removal costs for its regulated utility assets, even if there is no legal obligation for removal.
AROs as of December 31, 2018 are described further in Note 11.
Income Taxes
Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best estimate of current and future taxes to be paid.
On December 22, 2017, the Tax Act was enacted, and is generally effective January 1, 2018. This legislation made significant changes to the federal income tax laws. Changes which impact the Company include, but are not limited to, a reduction in the corporate tax rate to 21%, revisions to the rules related to tax bonus depreciation, limitations on interest deductibility and an associated exception for certain public utility property, and requirements that certain excess deferred tax amounts of regulated utilities be normalized.
Deferred tax assets or liabilities are recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards and net operating loss carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period the change is enacted. Given the regulatory nature of the Company’s business, substantially all of the effect on deferred tax assets and liabilities for the reduction in the federal corporate tax
rate to 21% was recorded as a regulatory liability recoverable by ratepayers as of December 31, 2017. See Note 3 for further discussion of the accounting for the regulatory liability.
The calculation of our tax liabilities involves dealing with the application of complex laws and regulations which are voluminous and often ambiguous. Interpretations and guidance surrounding income tax laws and regulations change over time. Tax positions taken by Pinnacle West on its income tax returns that are recognized in the financial statements must satisfy a "more likely than not" recognition threshold, assuming that the position will be sustained upon examination by taxing authorities with full knowledge of all relevant information, including resolutions of any related appeals or litigation processes, on the basis of the technical merits. Additional guidance may be issued through legislation, Treasury regulations, or other technical guidance, which may materially affect amounts the Company has recognized in its financial statements.
We record unrecognized tax benefits for tax positions that may not satisfy this "more likely than not" recognition threshold as liabilities in accordance with generally accepted accounting principles. These liabilities are adjusted when management judgment changes as a result of the evaluation of new information not previously available. These changes will be reflected as an increase or decrease to income tax expense in the period in which new information is available.
OTHER ACCOUNTING MATTERS
We adopted the following new accounting standards on January 1, 2018:
| • | ASU 2014-09: Revenue from Contracts with Customers, and related amendments |
| • | ASU 2016-01: Financial Instruments, Recognition and Measurement |
| • | ASU 2016-15: Statement of Cash Flows, Classification of Certain Cash Receipts and Cash Payments |
| • | ASU 2016-18: Statement of Cash Flows, Restricted Cash |
| • | ASU 2017-01: Business Combinations, Clarifying the Definition of a Business |
| • | ASU 2017-05: Other Income, Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets |
| • | ASU 2017-07: Compensation-Retirement Benefits, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost |
| • | ASU 2018-02: Income Statement-Reporting Comprehensive Income, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income |
We adopted the following new accounting standards on January 1, 2019:
| • | ASU 2016-02: Leases, and related amendments |
| • | ASU 2017-12: Derivatives and Hedging, Targeted Improvements to Accounting for Hedging Activities |
We are currently evaluating the impacts of the pending adoption of the following new accounting standards effective for us on January 1, 2020:
| • | ASU 2016-13: Financial Instruments, Measurement of Credit Losses |
| • | ASU 2018-15: Internal-Use Software: Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract |
See Note 2 for additional information related to new accounting standards.
MARKET AND CREDIT RISKS
Market Risks
Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust 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, other special use funds (see Note 13 and Note 19), and benefit plan assets. The nuclear decommissioning trust, other special use funds and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments. Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.
The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2018 and 2017. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2018 and 2017 (dollars in millions):
Pinnacle West – Consolidated
| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||||||||
| Interest | Interest | Interest | |||||||||||||||||||
| 2018 | Rates | Amount | Rates | Amount | Rates | Amount | |||||||||||||||
| 2019 | 2.99 | % | $ | 76 | — | — | 8.75 | % | $ | 500 | |||||||||||
| 2020 | — | — | 3.02 | % | 150 | 2.23 | % | 550 | |||||||||||||
| 2021 | — | — | — | — | — | — | |||||||||||||||
| 2022 | — | — | — | — | — | — | |||||||||||||||
| 2023 | — | — | — | — | — | — | |||||||||||||||
| Years thereafter | — | — | 1.76 | % | 36 | 4.25 | % | 3,940 | |||||||||||||
| Total | $ | 76 | $ | 186 | $ | 4,990 | |||||||||||||||
| Fair value | $ | 76 | $ | 186 | $ | 5,048 |
| Short-Term Debt | Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | ||||||||||||||||||
| Interest | Interest | Interest | ||||||||||||||||||
| 2017 | Rates | Amount | Rates | Amount | Rates | Amount | ||||||||||||||
| 2018 | 2.14 | % | $ | 95 | 2.17 | % | $ | 50 | 1.75 | % | $ | 32 | ||||||||
| 2019 | — | — | 2.27 | % | 100 | 8.75 | % | 500 | ||||||||||||
| 2020 | — | — | — | — | 2.23 | % | 550 | |||||||||||||
| 2021 | — | — | — | — | — | — | ||||||||||||||
| 2022 | — | — | — | — | — | — | ||||||||||||||
| Years thereafter | — | — | 1.77 | % | 36 | 4.25 | % | 3,640 | ||||||||||||
| Total | $ | 95 | $ | 186 | $ | 4,722 | ||||||||||||||
| Fair value | $ | 95 | $ | 186 | $ | 5,119 |
The tables below present contractual balances of APS’s long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2018 and 2017. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2018 and 2017 (dollars in millions):
APS — Consolidated
| Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||
| Interest | Interest | |||||||||||||
| 2018 | Rates | Amount | Rates | Amount | ||||||||||
| 2019 | — | — | 8.75 | % | $ | 500 | ||||||||
| 2020 | — | — | 2.20 | % | 250 | |||||||||
| 2021 | — | — | — | — | ||||||||||
| 2022 | — | — | — | — | ||||||||||
| 2023 | — | — | — | — | ||||||||||
| Years thereafter | 1.76 | % | 36 | 4.25 | % | 3,940 | ||||||||
| Total | $ | 36 | $ | 4,690 | ||||||||||
| Fair value | $ | 36 | $ | 4,754 |
| Variable-Rate Long-Term Debt | Fixed-Rate Long-Term Debt | |||||||||||||
| Interest | Interest | |||||||||||||
| 2017 | Rates | Amount | Rates | Amount | ||||||||||
| 2018 | 2.17 | % | $ | 50 | 1.75 | % | $ | 32 | ||||||
| 2019 | 2.27 | % | 100 | 8.75 | % | 500 | ||||||||
| 2020 | — | — | 2.20 | % | 250 | |||||||||
| 2021 | — | — | — | — | ||||||||||
| 2022 | — | — | — | — | ||||||||||
| Years thereafter | 1.77 | % | 36 | 4.25 | % | 3,640 | ||||||||
| Total | $ | 186 | $ | 4,422 | ||||||||||
| Fair value | $ | 186 | $ | 4,820 |
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 2018 and 2017 (dollars in millions):
| 2018 | 2017 | ||||||
| Mark-to-market of net positions at beginning of year | $ | (91 | ) | $ | (49 | ) | |
| Decrease (Increase) in regulatory asset | 31 | (46 | ) | ||||
| Recognized in OCI: | |||||||
| Mark-to-market losses realized during the period | 2 | 4 | |||||
| Change in valuation techniques | — | — | |||||
| Mark-to-market of net positions at end of year | $ | (58 | ) | $ | (91 | ) |
The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2018 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 | 2019 | 2020 | 2021 | 2022 | 2023 | Total fair value | ||||||||||||||||||
| Observable prices provided by other external sources | $ | (29 | ) | $ | (10 | ) | $ | (7 | ) | $ | (4 | ) | $ | — | $ | (50 | ) | |||||||
| Prices based on unobservable inputs | (4 | ) | (4 | ) | — | — | — | (8 | ) | |||||||||||||||
| Total by maturity | $ | (33 | ) | $ | (14 | ) | $ | (7 | ) | $ | (4 | ) | $ | — | $ | (58 | ) |
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, 2018 and 2017 (dollars in millions):
| December 31, 2018 Gain (Loss) | December 31, 2017 Gain (Loss) | ||||||||||||||
| Price Up 10% | Price Down 10% | Price Up 10% | Price Down 10% | ||||||||||||
| Mark-to-market changes reported in: | |||||||||||||||
| Regulatory asset (liability) (a) | |||||||||||||||
| Electricity | $ | 1 | $ | (1 | ) | $ | 1 | $ | (1 | ) | |||||
| Natural gas | 44 | (44 | ) | 45 | (45 | ) | |||||||||
| Total | $ | 45 | $ | (45 | ) | $ | 46 | $ | (46 | ) |
| (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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