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TMCNet:  ARIZONA PUBLIC SERVICE CO - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS

[February 21, 2014]

ARIZONA PUBLIC SERVICE CO - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS

(Edgar Glimpses Via Acquire Media NewsEdge) 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 accounts for essentially all of our revenues and earnings, and is expected to continue to do so.

Areas of Business Focus Operational Performance, Reliability and Recent Developments.

Nuclear. APS operates and is a joint owner of Palo Verde. The March 2011 earthquake and tsunamis in Japan and the resulting accident at Japan's Fukushima Daiichi nuclear power station had a significant impact on nuclear power operators worldwide. In the aftermath of the accident, the NRC conducted an independent assessment to consider actions to ensure that its regulations reflect lessons learned from the Fukushima events.

Although the NRC has repeatedly affirmed its position that continued operation of U.S. commercial nuclear power plants does not impose an immediate risk to public health and safety, the NRC has proposed enhancements to U.S. commercial nuclear power plant equipment and emergency plans. APS management continues to work closely with the NRC and others in the nuclear industry to ensure that the enhancements are implemented in an organized, sequential and structured way consistent with their safety benefit and significance of the issue being addressed.

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.

Concern over climate change and other emission-related issues could have a significant impact on our capital expenditures and operating costs in the form of taxes, emissions allowances or required equipment upgrades for these plants.

APS is closely monitoring its long-range capital management plans, 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 fund any such equipment upgrades.

49 -------------------------------------------------------------------------------- Table of Contents Four Corners Asset Purchase Agreement and Coal Supply Matters. SCE, a participant in Four Corners, previously indicated that certain California legislation prohibited it from making emission control expenditures at the plant. On November 8, 2010, APS and SCE entered into the Asset Purchase Agreement, providing for the purchase by APS of SCE's 48% interest in each of Units 4 and 5 of Four Corners.

On December 30, 2013, APS and SCE closed this transaction. The final purchase price for the interest was approximately $182 million, subject to certain minor post-closing adjustments.

In connection with APS's most recent retail rate case with the ACC, the ACC reserved the right to review the prudence of the Four Corners transaction for cost recovery purposes upon the closing of the transaction. On December 30, 2013, APS filed an application with the ACC to request rate adjustments prior to its next general rate case related to APS's acquisition of SCE's interest in Four Corners. If approved, these would result in an average bill impact to residential customers of approximately 2%. APS cannot predict the outcome of this request.

Concurrently with the closing of the SCE transaction, BHP Billiton, the parent company of BNCC, the coal supplier and operator of the mine that serves Four Corners, transferred its ownership of BNCC to NTEC, a company formed by the Navajo Nation to own the mine and develop other energy projects. BHP Billiton will be retained by NTEC under contract as the mine manager and operator until July 2016. Also occurring concurrently with the closing, the Four Corners' co-owners executed the 2016 Coal Supply Agreement. El Paso, a 7% owner in Units 4 and 5 of Four Corners, did not sign the 2016 Coal Supply Agreement. Under the 2016 Coal Supply Agreement, APS has agreed to assume the 7% shortfall obligation. When APS ultimately acquires a right to EPE's interest in Four Corners, by agreement or operation of law, NTEC will have an option to purchase the interest within a certain timeframe pursuant to an option granted by APS to NTEC. The 2016 Coal Supply Agreement contains alternate pricing terms for the 7% shortfall obligations in the event NTEC does not exercise its option.

Pollution Control Investments and Shutdown of Units 1, 2 and 3. EPA, in its final regional haze rule for Four Corners, required the Four Corners' owners to elect one of two emissions alternatives to apply to the plant. On December 30, 2013, APS, on behalf of the co-owners, notified EPA that they chose the alternative BART compliance strategy requiring the permanent closure of Units 1, 2 and 3 by January 1, 2014 and installation and operation of SCR controls on Units 4 and 5 by July 31, 2018. On December 30, 2013, APS retired Units 1, 2 and 3.

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 requires the approval of the DOI, as does a related federal rights-of-way grant which the Four Corners participants are pursuing. A federal environmental review is underway as part of the DOI review process. APS will also require a PSD permit from EPA to install SCR control technology at Four Corners. APS cannot predict whether these federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to the Four Corners owners.

Transmission and Delivery. APS is working closely with regulators to identify and plan for transmission needs that continue to support system reliability, access to markets and renewable energy development. The capital expenditures table presented in the "Liquidity and Capital Resources" section 50 -------------------------------------------------------------------------------- Table of Contents below includes new transmission projects through 2016, along with other transmission costs for upgrades and replacements. APS is also working to establish and expand smart grid technologies throughout its service territory to provide long-term benefits both to APS and its customers. APS is strategically deploying a variety of technologies that are intended to allow customers to better monitor their energy use and needs, minimize system outage durations, as well as the number of customers that experience outages, and facilitate greater cost savings to APS through improved reliability and the automation of certain distribution functions, including remote meter reading and remote connects and disconnects.

Renewable Energy. The ACC approved the RES in 2006. The renewable energy requirement is 4.5% of retail electric sales in 2014 and increases annually until it reaches 15% in 2025. In the 2009 Settlement Agreement, APS agreed to exceed the RES standards, committing to use APS's best efforts to obtain 1,700 GWh of new renewable resources to be in service by year-end 2015, in addition to its 2008 renewable resource commitments. Taken together, APS's commitment is currently estimated to be approximately 12% of APS's estimated retail energy sales by year-end 2015, which is more than double the existing RES target of 5% for that year. A component of the RES targets development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers' properties).

On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million. In a final order dated January 7, 2014, the ACC approved the requested budget. Also in 2013, the ACC conducted a hearing to consider APS's proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits. On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules so that utilities can establish compliance without using renewable energy credits.

On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules. In its application, APS requested that the ACC cause all new residential customers installing new rooftop solar systems to either: (i) take electric service under APS's demand-based ECT-2 rate and remain eligible for net metering; or (ii) take service under the customer's existing rate as if no distributed energy system was installed and receive a bill credit for 100% of the distributed energy system's output at a market-based price. APS also proposed that the ACC: (i) grandfather current rates and use of net metering for existing and immediately pending distributed energy customers; and (ii) continue using direct cash incentives for new distributed energy installations.

On December 3, 2013, the ACC issued its order on APS's net metering proposal.

The ACC instituted a charge on future customers who install rooftop solar panels and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases. The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid. The new policy will be in effect until the next APS rate case.

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid. ACC staff and the state's Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists. The fixed charge does not increase APS's revenue, 51 -------------------------------------------------------------------------------- Table of Contents but instead will modestly reduce the impact of the cost shift on non-solar customers. The ACC acknowledged that the new charge addresses only a portion of the cost shift.

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 ambitious standard became effective on January 1, 2011. The ACC issued an order on April 4, 2012, approving recovery of approximately $72 million of APS's energy efficiency and demand side management program costs.

This amount was recovered by the then-existing DSMAC over a twelve-month period beginning March 1, 2012. This amount did not include $10 million already being recovered in general retail base rates, but did include amortization of 2009 costs (approximately $5 million of the $72 million).

On June 1, 2012, APS filed its 2013 Demand Side Management Implementation Plan.

In 2013, the standards require APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales. Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.

The ACC Staff recommendation and proposed order, issued on October 30, 2013, largely recommended continuing the status quo, although at lower funding levels. ACC Staff recommended approval of all existing cost-effective energy efficiency and demand response programs and a budget of $68.9 million going forward. APS expects to receive a decision from the ACC in early 2014.

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified or abolished. This spring the ACC will hold a series of three workshops to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

Rate Matters. APS needs timely recovery through rates of its capital and operating expenditures to maintain its financial health. APS's retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by FERC. On June 1, 2011, APS filed a rate case with the ACC. APS and other parties to the retail rate case subsequently entered into the 2012 Settlement Agreement detailing the terms upon which the parties have agreed to settle the rate case. See Note 3 for details regarding the 2012 Settlement Agreement terms and for information on APS's FERC rates.

APS has several recovery mechanisms in place that provide more timely recovery to APS of its fuel and transmission costs, and costs associated with the promotion and implementation of its demand side management and renewable energy efforts and customer programs. These mechanisms are described more fully in Note 3.

As part of APS's acquisition of SCE's interest in Units 4 and 5 of Four Corners, APS and SCE agreed, via a "Transmission Termination Agreement," that upon closing of the acquisition, the companies would terminate an existing transmission agreement ("Transmission Agreement") between the parties that provides transmission capacity on a system (the "Arizona Transmission System") for SCE to transmit its portion of the output from Four Corners to California.

APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination. APS and SCE negotiated an 52 -------------------------------------------------------------------------------- Table of Contents alternate arrangement under which SCE will assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS's marketing and trading group for transmission of the additional power received from Four Corners. This arrangement becomes effective upon FERC approval and will remain in effect until the net payments received by SCE in connection with the assignments reach $40 million, at which time the arrangement and the Transmission Agreement will terminate. APS believes that FERC will approve the alternate arrangement as filed but, if not approved, SCE and APS will again be subject to the terms of the Transmission Termination Agreement. APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement. If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration. APS is unable to predict the outcome of this matter if it proceeds to arbitration.

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona. The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state. One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a "market" basis, would be consistent with the requirements of the Arizona Constitution. On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Arizona Constitutional authority before any further examination of this matter. The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.

The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry. Workshops in this docket are expected to be held in 2014.

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.

El Dorado. The operations of El Dorado, our only other operating subsidiary, are not expected to have any material impact on our financial results, or to require any material amounts of capital, over the next three years.

Key Financial Drivers In addition to the continuing impact of the matters described above, many factors influence our financial results and our future financial outlook, including those listed below. We closely monitor these factors to plan for the Company's current needs, and to adjust our expectations, financial budgets and forecasts appropriately.

Electric Operating Revenues. For the years 2011 through 2013, retail electric revenues comprised approximately 93% of our total electric operating revenues.

Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery 53 -------------------------------------------------------------------------------- Table of Contents mechanisms. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including competition, demand and prices.

Customer and Sales Growth. Retail customer growth in APS's service territory in 2013 was 1.3% compared with the prior year. For the three years 2011 through 2013, APS's customer growth averaged 1.0% per year. We currently expect annual customer growth to average about 2.5% for 2014 through 2016 based on our assessment of modestly improving economic conditions, both nationally and in Arizona. Retail electricity sales in kWh, adjusted to exclude the effects of weather variations, decreased 0.5% in 2013 compared with the prior year, reflecting the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, offset by mildly improving economic conditions and customer growth. For the three years 2011 through 2013, APS experienced annual increases in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations. We currently estimate that annual retail electricity sales in kWh will increase on average about 1% during 2014 through 2016, including the effects of customer conservation and energy efficiency and distributed renewable generation initiatives, but excluding the effects of weather variations. A failure of the Arizona economy to improve could further impact these estimates.

Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and energy conservation, impacts of energy efficiency programs and growth in distributed generation, and responses to retail price changes. Based on past experience, a reasonable range of variation in our kWh sales projection attributable to such economic factors under normal business conditions can result in increases or decreases in annual net income of up to $10 million.

Weather. In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Historically, extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.

Fuel and Purchased Power Costs. Fuel and purchased power costs included on our Consolidated Statements of Income are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, changes in our generation resource allocation, our hedging program for managing such costs and PSA deferrals and the related amortization.

Operations and Maintenance Expenses. Operations and maintenance expenses are impacted by customer and sales growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors.

In the 2009 Settlement Agreement, APS committed to operational expense reductions from 2010 through 2014, and received approval to defer certain pension and other postretirement benefit cost increases incurred in 2011 and 2012, which totaled $25 million, as a regulatory asset, until the most recent general retail rate case decision became effective on July 1, 2012. In July 2012, we began amortizing the regulatory asset over a 36-month period.

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 54 -------------------------------------------------------------------------------- Table of Contents distribution facilities), and changes in depreciation and amortization rates.

See "Capital Expenditures" below for information regarding the planned additions to our facilities. See Note 1 regarding deferral of certain costs pursuant to an ACC order.

Property Taxes. Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate in Arizona for APS, which owns essentially all of our property, was 10.5% of the assessed value for 2013, 9.6% for 2012, and 9.0% for 2011. We expect property taxes to increase as we add new generating units and continue with improvements and expansions to our existing generating units, transmission and distribution facilities. (See Note 3 for property tax deferrals contained in the 2012 Settlement Agreement).

Income Taxes. Income taxes are affected by the amount of pretax book income, income tax rates, certain deductions and non-taxable items, such as AFUDC. In addition, income taxes may also be affected by the settlement of issues with taxing authorities.

Interest Expense. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt (see Note 6). The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, equity issuances and internally generated cash flow.

An allowance for borrowed funds used during construction offsets a portion of interest expense while capital projects are under construction. We stop accruing AFUDC on a project when it is placed in commercial operation.

RESULTS OF OPERATIONS Pinnacle West's only reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities and includes electricity generation, transmission and distribution.

Operating Results - 2013 compared with 2012.

Our consolidated net income attributable to common shareholders for the year ended December 31, 2013 was $406 million, compared with net income of $382 million for the prior year. The results reflect an increase of approximately $21 million for the regulated electricity segment, primarily due to increases related to the retail regulatory settlement effective July 1, 2012 (see Note 3); higher retail transmission revenues; and lower net interest charges due to lower debt balances and lower interest rates in the current-year period. These positive factors were partially offset by higher operations and maintenance expenses; higher fuel and purchased power costs, net of related deferrals; lower retail sales as a result of changes in customer usage related to energy efficiency, customer conservation and distributed generation, partially offset by customer growth; and higher depreciation and amortization expenses.

55 -------------------------------------------------------------------------------- Table of Contents The following table presents net income attributable to common shareholders by business segment compared with the prior year: Year Ended December 31, 2013 2012 Net Change (dollars in millions) Regulated Electricity Segment: Operating revenues less fuel and purchased power expenses $ 2,356 $ 2,299 $ 57 Operations and maintenance (925 ) (885 ) (40 ) Depreciation and amortization (416 ) (404 ) (12 ) Taxes other than income taxes (164 ) (159 ) (5 ) Other income (expenses), net 11 6 5 Interest charges, net of allowance for borrowed funds used during construction (187 ) (200 ) 13 Income taxes (232 ) (237 ) 5 Less income related to noncontrolling interests (Note 19) (34 ) (32 ) (2 ) Regulated electricity segment net income 409 388 21 All other (3 ) - (3 ) Income from Continuing Operations Attributable to Common Shareholders 406 388 18 Loss from Discontinued Operations Attributable to Common Shareholders (a) - (6 ) 6 Net Income Attributable to Common Shareholders $ 406 $ 382 $ 24 -------------------------------------------------------------------------------- (a) Includes activities related to SunCor.

Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $57 million higher for the year ended December 31, 2013 compared with the prior year. The following table summarizes the major components of this change: 56 -------------------------------------------------------------------------------- Table of Contents Increase (Decrease) Fuel and purchased Operating power revenues expenses Net change (dollars in millions) Impacts of retail regulatory settlement effective July 1, 2012 $ 64 $ 6 $ 58 Higher demand-side management, renewable energy and similar regulatory surcharges 34 7 27 Higher retail transmission revenues 11 - 11 Lower retail sales due to changes in customer usage patterns and related pricing, partially offset by customer growth (17 ) (4 ) (13 ) Higher fuel and purchased power costs, net of related deferrals and off-system sales 74 95 (21 ) Miscellaneous items, net (8 ) (3 ) (5 ) Total $ 158 $ 101 $ 57 Operations and maintenance. Operations and maintenance expenses increased $40 million for the year ended December 31, 2013 compared with the prior year primarily because of: † An increase of $14 million related to technical analysis, consulting, advertising and communications costs; † An increase of $13 million related to costs for demand-side management, renewable energy and similar regulatory programs, which were largely offset in operating revenues; † An increase of $9 million related to the closure of Four Corners Units 1, 2, and 3, deferred for regulatory recovery in depreciation; † An increase of $6 million in energy delivery and customer service costs; † An increase of $6 million in information technology costs; † A decrease of $6 million in generation costs primarily related to lower fossil generation outage costs and lower nuclear generation costs; and † A decrease of $2 million related to other miscellaneous factors.

Depreciation and amortization. Depreciation and amortization expenses were $12 million higher for the year ended December 31, 2013 compared with the prior year, primarily because of 57 -------------------------------------------------------------------------------- Table of Contents increased plant in service, partially offset by the regulatory deferral of operating expenses associated with the closure of Four Corners Units 1, 2, and 3.

Interest charges, net of allowance for borrowed funds used during construction.

Interest charges, net of allowance for borrowed funds used during construction, decreased $13 million for the year ended December 31, 2013 compared with the prior year, primarily because of lower debt balances and lower interest rates in the current year.

Income taxes. Income taxes were $5 million lower for the year ended December 31, 2013 compared with the prior year primarily due to a lower effective tax rate in the current period, partially offset by the effects of higher pretax income in the current year.

Operating Results - 2012 compared with 2011.

Our consolidated net income attributable to common shareholders for the year ended December 31, 2012 was $382 million, compared with net income of $339 million for the prior year. The results reflect an increase of approximately $59 million for the regulated electricity segment, primarily due to increases related to the retail regulatory settlement effective July 1, 2012 (see Note 3); higher retail transmission revenues, lower depreciation and amortization due to 20-year Palo Verde license extensions received in 2011; and lower net interest charges due to lower debt balances and lower interest rates in the current year.

The $17 million decrease in discontinued operations is primarily related to a contribution Pinnacle West made to SunCor's estate as part of a negotiated resolution to the bankruptcy (see Note 1) and absence of the 2011 gain on sale of our investment in APSES.

The following table presents net income attributable to common shareholders by business segment compared with the prior year: 58 -------------------------------------------------------------------------------- Table of Contents Year Ended December 31, 2012 2011 Net Change (dollars in millions) Regulated Electricity Segment: Operating revenues less fuel and purchased power expenses (a) $ 2,299 $ 2,228 $ 71 Operations and maintenance (a) (885 ) (904 ) 19 Depreciation and amortization (404 ) (427 ) 23 Taxes other than income taxes (159 ) (148 ) (11 ) Other income (expenses), net 6 16 (10 ) Interest charges, net of allowance for borrowed funds used during construction (200 ) (224 ) 24 Income taxes (237 ) (184 ) (53 ) Less income related to noncontrolling interests (Note 19) (32 ) (28 ) (4 ) Regulated electricity segment net income 388 329 59 All other - (1 ) 1 Income from Continuing Operations Attributable to Common Shareholders 388 328 60 Income (Loss) from Discontinued Operations Attributable to Common Shareholders (b) (6 ) 11 (17 ) Net Income Attributable to Common Shareholders $ 382 $ 339 $ 43 -------------------------------------------------------------------------------- (a) Includes effects of 2011 settlement of certain transmission right-of-way costs, which did not affect net income, but increased both electric operating revenues and operations and maintenance expenses by $28 million.

Costs related to the settlement were offset by related revenues from SCE, which leases the related transmission line from APS.

(b) Includes activities related to APSES and SunCor.

Operating revenues less fuel and purchased power expenses. Regulated electricity segment operating revenues less fuel and purchased power expenses were $71 million higher for the year ended December 31, 2012 compared with the prior year. The following table summarizes the major components of this change: 59 -------------------------------------------------------------------------------- Table of Contents Increase (Decrease) Fuel and purchased Operating power revenues expenses Net change (dollars in millions) Impacts of retail regulatory settlement effective July 1, 2012 $ 64 $ 1 $ 63 Higher retail transmission revenues 41 - 41 Lower fuel and purchased power costs, net of related deferrals and off-system sales (11 ) (14 ) 3 Lower demand-side management, renewable energy and similar regulatory surcharges (3 ) 4 (7 ) Settlement in 2011 of certain prior-period transmission right-of-way revenues (28 ) - (28 ) Miscellaneous items, net (7 ) (6 ) (1 ) Total $ 56 $ (15 ) $ 71 Operations and maintenance. Operations and maintenance expenses decreased $19 million for the year ended December 31, 2012 compared with the prior year primarily because of: † A decrease of $28 million related to settlement in 2011 of certain transmission right-of-way costs, which was offset in operating revenues; † A decrease of $22 million related to costs fordemand-side management, renewable energy and similar regulatory programs; † A decrease of $15 million in generation costs, primarily related to lower nuclear generation costs; † An increase of $21 million related to employee benefit costs, including approximately $12 million of pension and other postretirement costs; † An increase of $9 million related to higher stock compensation costs resulting from an improved company stock price and estimated performance results; † An increase of $7 million in information technologycosts, primarily related to higher software maintenance; and † An increase of $9 million due to other miscellaneous factors.

Depreciation and amortization. Depreciation and amortization expenses were $23 million lower for the year ended December 31, 2012 compared with the prior year, primarily due to the impacts of Palo Verde operating license extensions, partially offset by increased plant in service.

60 -------------------------------------------------------------------------------- Table of Contents Taxes other than income taxes. Taxes other than income taxes increased $11 million for the year ended December 31, 2012 compared with the prior year, primarily because of higher property tax rates in the current year.

Other income (expenses), net. Other income (expenses), net, decreased $10 million for the year ended December 31, 2012 compared with the prior year, primarily because of higher investment losses of approximately $2 million and other non-operating expenses of approximately $8 million in the current year.

Interest charges, net of allowance for borrowed funds used during construction.

Interest charges, net of allowance for borrowed funds used during construction, decreased $24 million for the year ended December 31, 2012 compared with the prior year, primarily because of lower debt balances and lower interest rates in the current year.

Income taxes. Income taxes were $53 million higher for the year ended December 31, 2012 compared with the prior year, primarily due to higher pre-tax income in the current year and a lower effective tax rate in 2011.

Discontinued Operations Results from discontinued operations decreased $17 million, primarily due to a contribution Pinnacle West made to SunCor's estate as part of a negotiated resolution to the bankruptcy (see Note 1) and absence of a gain related to the sale of our investment in APSES in 2011.

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 ACC order, the common equity ratio is 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, 2013, APS's common equity ratio, as defined, was 58%. Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.5 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $3.0 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.

61 -------------------------------------------------------------------------------- Table of Contents 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, 2013, 2012 and 2011 (dollars in millions): Pinnacle West Consolidated 2013 2012 2011 Net cash flow provided by operating activities $ 1,153 $ 1,171 $ 1,125 Net cash flow used for investing activities (1,009 ) (873 ) (782 ) Net cash flow used for financing activities (161 ) (305 ) (420 ) Net decrease in cash and cash equivalents $ (17 ) $ (7 ) $ (77 ) Arizona Public Service Company 2013 2012 2011 Net cash flow provided by operating activities $ 1,194 $ 1,176 $ 1,128 Net cash flow used for investing activities (1,009 ) (873 ) (834 ) Net cash flow used for financing activities (185 ) (319 ) (374 ) Net decrease in cash and cash equivalents $ - $ (16 ) $ (80 ) Operating Cash Flows 2013 Compared with 2012. Pinnacle West's consolidated net cash provided by operating activities was $1,153 million in 2013, compared to $1,171 million in 2012, a decrease of $18 million in net cash provided. The decrease is primarily related to a $127 million change in cash collateral posted and $76 million of higher pension contributions made in 2013 compared to 2012 (approximately $18 million of which is reflected in capital expenditures). The decrease is partially offset by approximately $167 million of higher cash inflows primarily due to higher authorized revenue requirements resulting from the retail regulatory settlement effective July 1, 2012 and other changes in working capital.

2012 Compared with 2011. Pinnacle West's consolidated net cash provided by operating activities was $1,171 million in 2012, compared to $1,125 million in 2011, an increase of $46 million in net cash provided. The increase is primarily related to a $77 million reduction of cash collateral posted and a decrease of $23 million in cash paid for interest in the current year, partially offset by a $26 million increase in property tax payments, a $65 million pension contribution in 2012 (approximately $12 million of which is reflected in capital expenditures) and other changes in working capital.

Other. 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 107% funded as of January 1, 2013 and is estimated to be approximately 103% funded as of January 1, 2014. 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 $141 million in 2013, $65 million in 2012, and zero in 2011. The minimum contributions for the pension plan total $141 million for the next three years under the recently enacted Moving Ahead 62 -------------------------------------------------------------------------------- Table of Contents for Progress in the 21st Century Act (zero in 2014, $19 million in 2015 and $122 million in 2016). Instead, we expect to make voluntary contributions totaling $300 million for the next three years ($175 million in 2014, of which $70 million was already contributed in early 2014, up to $100 million in 2015, and up to $25 million in 2016). With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $14 million in 2013, $23 million in 2012, and $19 million in 2011. The contributions to our other postretirement benefit plans for 2014, 2015 and 2016 are expected to be approximately $10 million each year.

The $70 million long-term income tax receivable on the Consolidated Balance Sheets as of December 31, 2012 represented the anticipated refund related to an APS tax accounting method change approved by the Internal Revenue Service ("IRS") in the third quarter of 2009. On July 9, 2013, IRS guidance was released which provided clarification regarding the timing and amount of this cash receipt. As a result of this guidance, uncertain tax positions decreased $67 million during the third quarter. This decrease in uncertain tax positions resulted in a corresponding increase to the total anticipated refund due from the IRS and an offsetting increase in long-term deferred tax liabilities.

Additionally, as a result of this IRS guidance, the resulting $137 million anticipated refund was reclassified to current income tax receivable.

During the year ended December 31, 2013, the IRS finalized the examination of tax returns for the years ended December 31, 2008 and 2009, and the $137 million anticipated refund was reduced by approximately $4 million to reflect the outcome of this examination. On December 17, 2013, the Joint Committee on Taxation approved the anticipated refund. Cash related to this refund was received in the first quarter of 2014.

Investing Cash Flows 2013 Compared with 2012. Pinnacle West's consolidated net cash used for investing activities was $1,009 million in 2013, compared to $873 million in 2012, an increase of $136 million in net cash used. The increase in net cash used for investing activities is primarily related to APS's purchase of SCE's interest in Units 4 and 5 of Four Corners of approximately $209 million, partially offset by a decrease of approximately $73 million in other capital expenditures.

2012 Compared with 2011. Pinnacle West's consolidated net cash used for investing activities was $873 million in 2012, compared to $782 million in 2011, an increase of $91 million in net cash used. The increase in net cash used for investing activities is primarily due to the absence of $55 million in proceeds from the sale of life insurance policies in 2011 and the absence of $45 million in proceeds from the sale of Pinnacle West's investment in APSES in 2011.

63 -------------------------------------------------------------------------------- Table of Contents 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, 2014 2015 2016 APS Generation: Nuclear Fuel $ 80 $ 86 $ 88 Renewables 118 7 - Environmental 30 57 213 Other Generation 230 248 355 Distribution 255 374 363 Transmission 198 213 196 Other (a) 54 41 48 Total APS $ 965 $ 1,026 $ 1,263 -------------------------------------------------------------------------------- (a) Primarily information systems and facilities projects.

Generation capital expenditures are comprised of various improvements to APS's existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment, such as turbines, boilers and environmental equipment.

The estimated Renewables expenditures include 20 MW of utility-scale solar projects which were approved by the ACC in the 2014 RES Implementation Plan. We have not included estimated costs for Cholla's compliance with MATS or EPA's regional haze rule since we have challenged the regional haze rule judicially and are considering our future options with respect to that plant if the regional haze rule is upheld. The portion of estimated costs through 2016 for installation of pollution control equipment needed to ensure Four Corners' compliance with EPA's regional haze rules have been included in the table above. We are monitoring the status of other environmental matters, which, depending on their final outcome, could require modification to our planned environmental expenditures.

Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, and new customer construction. Examples of the types of projects included in the forecast include power lines, substations, and line extensions to new residential and commercial developments.

Capital expenditures will be funded with internally generated cash and external financings, which may include issuances of long-term debt and Pinnacle West common stock.

Financing Cash Flows and Liquidity 2013 Compared with 2012. Pinnacle West's consolidated net cash used for financing activities was $161 million in 2013, compared to $305 million of net cash used in 2012, a decrease of $144 64 -------------------------------------------------------------------------------- Table of Contents million in net cash used. The decrease in net cash used for financing activities is primarily due to $531 million in lower repayments of long-term debt, largely offset by $340 million in lower issuances of long-term debt and a $31 million net change in APS's commercial paper borrowings, which is classified as short-term borrowings on the Consolidated Balance Sheets. On December 30, 2013, commercial paper issuances were used to fund the acquisition of SCE's 48% ownership interest in each of Units 4 and 5 of Four Corners (see below).

2012 Compared with 2011. Pinnacle West's consolidated net cash used for financing activities was $305 million in 2012, compared to $420 million in 2011, a decrease of $115 million in net cash used. The decrease in net cash used for financing activities is primarily due to an increase of $92 million in APS's short-term debt borrowings in 2012. In addition, APS had $56 million in higher issuances of long-term debt, partially offset by $99 million in higher repayments of long-term debt. Pinnacle West had $100 million in lower repayments of long-term debt, partially offset by $50 million in lower debt issuances (see below).

Significant Financing Activities. On December 18, 2013, the Pinnacle West Board of Directors declared a quarterly dividend of $0.5675 per share of common stock, payable on March 3, 2014, to shareholders of record on February 3, 2014. During 2013, Pinnacle West increased its indicated annual dividend from $2.18 per share to $2.27 per share. For the year ended December 31, 2013, Pinnacle West's total dividends paid per share of common stock were $2.20 per share, which resulted in dividend payments of $235 million.

On March 22, 2013, APS issued an additional $100 million par amount of its outstanding 4.50% unsecured senior notes that mature on April 1, 2042. The net proceeds from the sale were used to repay short-term commercial paper borrowings and replenish cash used to redeem certain tax-exempt indebtedness in November 2012.

On May 1, 2013, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series C, due 2029. On May 28, 2013, we remarketed the bonds. The interest rate for these bonds was set to a new term rate. The new term rate for these bonds ends, subject to a mandatory tender, on May 30, 2018. During this time, the bonds will bear interest at a rate of 1.75% per annum. These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2013 and were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029. On January 15, 2014, these bonds were canceled. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024. On January 15, 2014, these bonds were canceled. These bonds were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2012.

On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044. The proceeds from the sale were used to repay commercial paper which was used to fund the purchase price and costs associated with the acquisition of SCE's 48% ownership interest in 65 -------------------------------------------------------------------------------- Table of Contents each of Units 4 and 5 of Four Corners and to replenish cash used to re-acquire two series of tax-exempt 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.

At December 31, 2013, Pinnacle West's $200 million credit facility, which matures in November 2016, was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program. 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, 2013, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding, and no commercial paper borrowings.

On April 9, 2013, APS refinanced its $500 million revolving credit facility that would have matured in February 2015, with a new $500 million facility. The new revolving credit facility matures in April 2018.

At December 31, 2013, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that was refinanced in April 2013 (see above) and a $500 million credit facility that matures in November 2016. APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders. APS can use these facilities to refinance indebtedness and for other general corporate purposes. Interest rates are based on APS's senior unsecured debt credit ratings.

The facilities described above are available to support APS's $250 million commercial paper program, for bank borrowings or for issuances of letters of credit. At December 31, 2013, APS had no outstanding borrowings or letters of credit under its revolving credit facilities. APS had commercial paper borrowings of $153 million at December 31, 2013.

See "Financial Assurances" in Note 11 for a discussion of APS's separate outstanding letters of credit.

Other Financing Matters. See Note 3 for information regarding the PSA approved by the ACC.

See Note 3 for information regarding the settlement related to the 2008 retail rate case, which includes ACC authorization and requirements of equity infusions into APS.

See Note 17 for information related to the change in our margin and collateral accounts.

Debt Provisions Pinnacle West's and APS's debt covenants related to their respective bank financing arrangements include maximum debt to capitalization ratios. Pinnacle West and APS comply with 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, 2013, the ratio was approximately 47% for Pinnacle West and 45% 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 66 -------------------------------------------------------------------------------- Table of Contents 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 14, 2014 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 Baa1 A- BBB+ Commercial paper P-2 A-2 F2 Outlook Stable Stable Stable APS Corporate credit rating A3 A- BBB+ Senior unsecured A3 A- A- Secured lease obligation bonds A3 A- A- Commercial paper P-2 A-2 F2 Outlook Stable Stable Stable 67 -------------------------------------------------------------------------------- Table of Contents Off-Balance Sheet Arrangements See Note 19 for a discussion of the impacts on our financial statements of consolidating certain VIEs.

Contractual Obligations The following table summarizes Pinnacle West's consolidated contractual requirements as of December 31, 2013 (dollars in millions): 2015- 2017- 2014 2016 2018 Thereafter Total Long-term debt payments, including interest: (a) APS $ 710 $ 986 $ 270 $ 3,374 $ 5,340 Pinnacle West 2 127 - - 129 Total long-term debt payments, including interest 712 1,113 270 3,374 5,469 Short-term debt payments, including interest (b) 153 - - - 153 Fuel and purchased power commitments (c) 644 1,229 1,154 8,471 11,498 Renewable energy credits (d) 48 84 84 453 669 Purchase obligations (e) 85 37 39 246 407 Coal reclamation 1 9 28 170 208 Nuclear decommissioning funding requirements 17 19 4 66 106 Noncontrolling interests (f) 20 35 - - 55 Operating lease payments 20 23 9 59 111 Total contractual commitments $ 1,700 $ 2,549 $ 1,588 $ 12,839 $ 18,676 -------------------------------------------------------------------------------- (a) The long-term debt matures at various dates through 2042 and bears interest principally at fixed rates. Interest on variable-rate long-term debt is determined by using average rates at December 31, 2013 (see Note 6).

(b) The short-term debt represents commercial paper borrowings at APS (see Note 5).

(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 11). These amounts include commitments incurred from acquiring SCE's interest in Four Corners.

(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 19). We have committed to retain the assets relating to the noncontrolling interests beyond 2015, either through lease extensions or by purchasing the assets. If we elect to purchase the assets, the purchase price will be based on the fair value of the assets at the end of 2015. Such value is unknown at this time and is subject to an appraisal process.

68 -------------------------------------------------------------------------------- Table of Contents If we elect to extend the leases, we will be required to make annual payments beginning in 2016 of approximately $23 million; however, the length of the lease extensions is unknown at this time as it must be determined through an appraisal process. Due to these uncertainties, amounts relating to the noncontrolling interests beyond 2015 have not been included in the table above.

This table excludes $42 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. This table also excludes approximately zero, $19 million and $122 million in estimated minimum pension contributions for 2014, 2015 and 2016, respectively (see Note 8).

CRITICAL ACCOUNTING POLICIES In preparing the financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP"), management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the following accounting policies to be our most critical because of the uncertainties, judgments and complexities of the underlying accounting standards and operations involved.

Regulatory Accounting Regulatory accounting allows for the actions of regulators, such as the ACC and FERC, to be reflected in our financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in customer rates. Regulatory liabilities generally represent expected future costs that have already been collected from customers. Management continually assesses whether our regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes and recent rate orders to other regulated entities in the same jurisdiction. This determination reflects the current political and regulatory climate in Arizona and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. We had $809 million of regulatory assets and $901 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2013.

Included in the balance of regulatory assets at December 31, 2013 is a regulatory asset of $314 million for pension and other postretirement benefits.

This regulatory asset represents the future recovery of these costs through retail rates as these amounts are charged to earnings. If these costs are disallowed by the ACC, this regulatory asset would be charged to OCI and result in lower future earnings.

See Notes 1 and 3 for more information.

Pensions and Other Postretirement Benefit Accounting Changes in our actuarial assumptions used in calculating our pension and other postretirement benefit liability and expense can have a significant impact on our earnings and financial position. The most relevant actuarial assumptions are the discount rate used to measure our liability and net periodic cost, the expected long-term rate of return on plan assets used to estimate earnings on invested funds 69 -------------------------------------------------------------------------------- Table of Contents over the long-term, and the assumed healthcare cost trend rates. We review these assumptions on an annual basis and adjust them as necessary.

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2013 reported pension liability on the Consolidated Balance Sheets and our 2013 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) Impact on Impact on Pension Pension Actuarial Assumption (a) Liability Expense Discount rate: Increase 1% $ (280 ) $ (14 ) Decrease 1% 337 16 Expected long-term rate of return on plan assets: Increase 1% - (10 ) Decrease 1% - 10 -------------------------------------------------------------------------------- (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, 2013 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2013 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) Impact on Other Impact on Other Postretirement Benefit Postretirement Actuarial Assumption (a) Obligation Benefit Expense Discount rate: Increase 1% $ (120 ) $ (7 ) Decrease 1% 151 9 Healthcare cost trend rate (b): Increase 1% 149 13 Decrease 1% (120 ) (10 ) Expected long-term rate of return on plan assets - pretax: Increase 1% - (3 ) Decrease 1% - 3 70 -------------------------------------------------------------------------------- Table of Contents -------------------------------------------------------------------------------- (a) Each fluctuation assumes that the other assumptions of the calculation are held constant while the rates are changed by one percentage point.

(b) This assumes a 1% change in the initial and ultimate healthcare cost trend rate.

See Note 8 for further details about our pension and other postretirement benefit plans.

Fair Value Measurements We account for derivative instruments, investments held in our nuclear decommissioning trust fund, 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. The significance of a particular input determines how the instrument is classified in a fair value hierarchy. We utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The determination of fair value sometimes requires subjective and complex judgment. Our assessment of the inputs and the significance of a particular input to fair value measurement may affect the valuation of the instruments and their placement within a fair value hierarchy. Actual results could differ from our estimates of fair value. See Note 1 for a discussion on accounting policies and Note 14 for further fair value measurement discussion.

OTHER ACCOUNTING MATTERS During 2013, we adopted new accounting guidance relating to balance sheet offsetting disclosures, and disclosures of amounts reclassified from accumulated OCI. During the first quarter of 2014 we are required to adopt new accounting guidance related to balance sheet presentation of certain unrecognized tax benefits. See Note 2.

MARKET AND CREDIT RISKS Market Risks Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund and benefit plan assets.

Interest Rate and Equity Risk We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear decommissioning trust fund (see Note 14 and Note 20) and benefit plan assets. The nuclear decommissioning trust fund and benefit plan assets also have risks associated with the changing market value of their equity and other non-fixed income investments. Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

The tables below present contractual balances of our consolidated long-term and short-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2013 and 71 -------------------------------------------------------------------------------- Table of Contents 2012. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2013 and 2012 (dollars in thousands): Pinnacle West - Consolidated Short-Term Variable-Rate Fixed-Rate Debt Long-Term Debt Long-Term Debt Interest Interest Interest 2013 Rates Amount Rates Amount Rates Amount 2014 0.23 % $ 153,125 - $ - 5.58 % $ 540,424 2015 - - 1.02 % 157,000 4.79 % 313,420 2016 - - 0.06 % 43,580 6.15 % 314,000 2017 - - - - - - 2018 - - - - 1.75 % 32,000 Years thereafter - - - - 6.12 % 1,940,150 Total $ 153,125 - $ 200,580 $ 3,139,994 Fair value $ 153,125 $ 200,580 $ 3,378,102 Short-Term Variable-Rate Fixed-Rate Debt Long-Term Debt Long-Term Debt Interest Interest Interest 2012 Rates Amount Rates Amount Rates Amount 2013 0.38 % $ 92,175 - $ - 4.94 % $ 122,828 2014 - - - - 5.58 % 540,424 2015 - - 1.07 % 157,000 4.79 % 313,420 2016 - - 0.15 % 43,580 6.15 % 314,000 2017 - - - - - - Years thereafter - - - - 6.21 % 1,840,150 Total $ 92,175 $ 200,580 $ 3,130,822 Fair value $ 92,175 $ 200,268 $ 3,674,958 72 -------------------------------------------------------------------------------- Table of Contents The tables below present contractual balances of APS's long-term debt at the expected maturity dates, as well as the fair value of those instruments on December 31, 2013 and 2012. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2013 and 2012 (dollars in thousands): APS - Consolidated Short-Term Variable-Rate Fixed-Rate Debt Long-Term Debt Long-Term Debt Interest Interest Interest 2013 Rates Amount Rates Amount Rates Amount 2014 0.23 % $ 153,125 - $ - 5.58 % $ 540,424 2015 - - 0.03 % 32,000 4.79 % 313,420 2016 - - 0.06 % 43,580 6.15 % 314,000 2017 - - - - - - 2018 - - - - 1.75 % 32,000 Years thereafter - - - - 6.12 % 1,940,150 Total $ 153,125 - $ 75,580 $ 3,139,994 Fair value $ 153,125 $ 75,580 $ 3,378,102 Short-Term Variable-Rate Fixed-Rate Debt Long-Term Debt Long-Term Debt Interest Interest Interest 2012 Rates Amount Rates Amount Rates Amount 2013 0.38 % $ 92,175 - $ - 4.94 % $ 122,828 2014 - - - - 5.58 % 540,424 2015 - - 0.13 % 32,000 4.79 % 313,420 2016 - - 0.15 % 43,580 6.15 % 314,000 2017 - - - - - - Years thereafter - - - - 6.21 % 1,840,150 Total $ 92,175 $ 75,580 $ 3,130,822 Fair value $ 92,175 $ 75,580 $ 3,674,958 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.

73 -------------------------------------------------------------------------------- Table of Contents The following table shows the net pretax changes in mark-to-market of our derivative positions in 2013 and 2012 (dollars in millions): 2013 2012 Mark-to-market of net positions at beginning of year $ (122 ) $ (222 ) Recognized in earnings (a): Change in mark-to-market gains (losses) for future period deliveries (1 ) 1 Decrease in regulatory asset 6 37 Recognized in OCI: Change in mark-to-market losses for future period deliveries (b) - (37 ) Mark-to-market losses realized during the period 44 99 Change in valuation techniques - - Mark-to-market of net positions at end of year $ (73 ) $ (122 ) --------------------------------------------------------------------------------(a) Represents the amounts reflected in income after the effect of PSA deferrals.

(b) The changes in mark-to-market recorded in OCI are dueprimarily to changes in forward natural gas prices.

The table below shows the fair value of maturities of our derivative contracts (dollars in millions) at December 31, 2013 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.

Total Years fair Source of Fair Value 2014 2015 2016 2017 2018 thereafter value Observable prices provided by other external sources $ (15 ) $ (6 ) $ (3 ) $ - $ - $ - $ (24 ) Prices based on unobservable inputs (11 ) (12 ) (12 ) (5 ) (4 ) (5 ) (49 ) Total by maturity $ (26 ) $ (18 ) $ (15 ) $ (5 ) $ (4 ) $ (5 ) $ (73 ) 74 -------------------------------------------------------------------------------- Table of Contents 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, 2013 and 2012 (dollars in millions): December 31, 2013 December 31, 2012 Gain (Loss) Gain (Loss) Price Up 10% Price Down 10% Price Up 10% Price Down 10% Mark-to-market changes reported in: Earnings (a) Natural gas $ - $ - $ - $ - Regulatory asset (liability) or OCI (b) Electricity 6 (6 ) 7 (7 ) Natural gas 26 (26 ) 25 (25 ) Total $ 32 $ (32 ) $ 32 $ (32 ) --------------------------------------------------------------------------------(a) Represents the amounts reflected in income after the effect of PSA deferrals.

(b) These contracts are economic hedges of our forecastedpurchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

Credit Risk We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 17 for a discussion of our credit valuation adjustment policy.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See "Market and Credit Risks" in Item 7 above for a discussion of quantitative and qualitative disclosures about market risk.

75 -------------------------------------------------------------------------------- Table of Contents

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