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

[February 22, 2013]

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. In 2012, Palo Verde achieved its best generation year ever, producing over 31 million megawatt-hours, with an overall station capacity factor of 92.3%. In 2012, Palo Verde successfully refueled both Unit 2 and Unit 3. APS management continues to work closely with regulators and others in the nuclear industry to analyze the lessons learned and address any rulemaking or improvements resulting from the March 2011 events impacting the Fukushima Daiichi Nuclear Power Station in Japan.

Coal and Related Environmental Matters. APS-operated coal plants, Four Corners and Cholla, achieved net capacity factors for APS of 71% and 75%, respectively, in 2012. These capacity factors were lower than in prior years primarily due to lower gas prices resulting in higher production from our gas fleet. APS is focused on the impacts on its coal fleet that may result from increased regulation and potential legislation concerning greenhouse gas 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.

SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit 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. The purchase price is $294 million, subject to certain adjustments. Completion of the purchase by APS is subject to the receipt of approvals by the ACC, the CPUC and the FERC. On March 29, 2012, the CPUC issued an order approving the sale. On April 18, 2012, the ACC voted to allow APS to move forward with the purchase. The Asset Purchase Agreement provides that the purchase price will be reduced by $7.5 million for each month between October 1, 50 -------------------------------------------------------------------------------- Table of Contents 2012 and the closing date. The ACC reserved the right to review the prudence of the transaction for cost recovery purposes in a future proceeding if the purchase closes. The ACC also authorized an accounting deferral of certain costs associated with the purchase until any such cost recovery proceeding concludes. The FERC application seeking authorization for the transaction was approved on November 27, 2012. The principal remaining condition to closing is the negotiation and execution of a new coal supply contract on terms reasonably acceptable to APS.

On December 19, 2012, BHP Billiton, the parent company of BNCC, the coal supplier and operator of the mine that serves Four Corners, announced that it has entered into a Memorandum of Understanding with the Navajo Nation setting out the key terms under which full ownership of BNCC would be sold to the Navajo Nation. BHP Billiton would be retained by BNCC under contract as the mine manager and operator until July 2016. Key terms of the new coal supply contract are being finalized by the Navajo Nation and APS and the other Four Corners co-owners.

As a result of this proposed change in ownership of BNCC, APS now expects that a new coal supply contract would be executed upon completion of negotiations and following the endorsement of the transfer of ownership of the stock of BNCC to a new Navajo Nation commercial enterprise to be established by the Navajo Nation Tribal Council. The decision of the Tribal Council is currently expected to occur in the second quarter of 2013.

Pursuant to the Asset Purchase Agreement, either APS or SCE has a right to terminate the Agreement if satisfaction of the closing conditions had not occurred by December 31, 2012, unless the party seeking to terminate is then in breach of the Agreement.

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 will pursue. A federal environmental review is underway as part of the DOI review process.

APS has announced that, if APS's purchase of SCE's interests in Units 4 and 5 at Four Corners is consummated, it will close Units 1, 2 and 3 at the plant. APS owns 100% of Units 1-3. These events will change the plant's overall generating capacity from 2,100 MW to 1,540 MW and APS's entitlement from the plant from 791 MW to 970 MW. When the ACC approved APS moving forward with the purchase of Units 4 and 5, it also approved the recovery of any unrecovered costs associated with the closure of Units 1, 2 and 3. The Settlement Agreement in APS's most recent retail rate case allows APS to seek a rate adjustment to reflect the Four Corners transaction should the transaction close (see Note 3).

APS cannot predict whether the mutual right to terminate in the Asset Purchase Agreement will be exercised by a party to that agreement in the future, whether BHP Billiton and the Navajo Nation will consummate the transfer of ownership of BNCC, or whether the coal supply contract will be finalized and executed, such that closing of APS's purchase of SCE's interest in Four Corners can occur.

Transmission and Delivery. APS is working closely with regulators to identify and plan for transmission needs resulting from the current focus on renewable energy. The capital expenditures table presented in the "Liquidity and Capital Resources" section below includes the next three years of new 51 -------------------------------------------------------------------------------- Table of Contents transmission projects along with other transmission costs for upgrades and replacements. APS is also working to establish and expand smart grid technologies throughout its service territory designed to provide long-term benefits both to APS and its customers. APS is piloting and 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% of retail electric sales in 2013 and increases annually until it reaches 15% in 2025. In the settlement agreement related to the 2008 retail rate case, APS agreed to exceed the RES standards, committing to 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 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 is focused on stimulating development of distributed energy systems (generally speaking, small-scale renewable technologies that are located on customers' properties).

On June 29, 2012, APS filed its annual RES implementation plan, covering the 2013-2017 timeframe and requesting 2013 RES funding of $97 million to $107 million. In a final order dated January 31, 2013, the ACC approved a budget of $103 million for APS's 2013 RES plan. That budget includes $4 million for residential distributed energy incentives and $0.1 million for commercial distributed energy up-front incentives, but did not include any funds for commercial distributed energy production-based incentives. The ACC further ordered that a hearing take place to consider: (i) APS's proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits; and (ii) removing retail sales to APS's largest industrial customers when calculating APS's compliance with the annual RES requirements.

APS has a diverse portfolio of existing and planned renewable resources totaling 1,090 MW, including solar, wind, geothermal, biomass and biogas. Of this portfolio, 667 MW are currently in operation and 423 MW are under contract for development or are under construction. Renewable resources in operation include 81 MW of solar facilities owned by APS, 349 MW of long-term purchased power agreements, and an estimated 237 MW of customer-sited, third-party owned distributed energy resources.

To achieve our RES requirements, as mentioned above, to date APS has entered into contracts for 423 MW of renewable resources that are planned, in development or under construction. APS's strategy to procure these resources includes new facilities to be owned by APS, purchased power contracts for new facilities and ongoing development of distributed energy resources. Through the AZ Sun Program, APS has executed contracts for the development of 118 MW of new solar generation, representing an investment commitment of approximately $502 million. See Note 3 for additional details of the AZ Sun Program, including the related cost recovery. APS has also entered into long-term purchased power agreements for 280 MW from solar facilities currently planned, in development or under construction, and 94 MW from distributed energy resources. Agreements for the development and completion of future resources are subject to various conditions, including successful siting, permitting and interconnection of the project to the electric grid.

52 -------------------------------------------------------------------------------- Table of Contents Demand Side Management. In recent years, Arizona regulators have 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. In December 2009, the ACC initiated an Energy Efficiency rulemaking, with a proposed Energy Efficiency Standard of 22% cumulative annual energy savings by 2020. The 22% figure represents the cumulative reduction in future energy usage through 2020 attributable to energy efficiency initiatives. This ambitious standard became effective on January 1, 2011 and will likely impact Arizona's future energy resource needs. 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 over a twelve-month period beginning March 1, 2012. This amount does not include $10 million already being recovered in general retail base rates.

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

In 2013, the standards will 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. APS expects to receive a decision from the ACC in the second quarter of 2013.

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 the 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 a Settlement Agreement detailing the terms upon which the parties have agreed to settle the rate case. See Note 3 for details regarding the 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 proposed acquisition of SCE's interest in Units 4 and 5 of Four Corners, APS and SCE agreed that upon closing of the acquisition (or in 2016 if the closing does not occur), the companies will terminate an existing agreement that provides transmission capacity for SCE to transmit its portion of the output from Four Corners to California. APS expects to file a request with FERC seeking authorization to cancel the existing agreement and defer a $40 million payment to be made by APS associated with the termination and recover the payment through amortization over a 29-year period. APS believes the costs associated with the termination of the existing agreement are recoverable, but cannot predict whether FERC will approve our request; however, if the recovery is disallowed by FERC, APS would record a charge to its results of operations at the time of the disallowance.

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. 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. As a result of the continuing distressed conditions in the real estate markets, during 2009 our other first-tier subsidiary, SunCor, undertook a program to dispose of its homebuilding operations, master-planned 53 -------------------------------------------------------------------------------- Table of Contents communities, land parcels, commercial assets and golf courses in order to eliminate its outstanding debt and, as of December 31, 2012, SunCor had no assets. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business. All activities of SunCor are now reported as discontinued operations (see Note 21).

SunCor's loss in 2012 is primarily related to a contribution Pinnacle West expects to make to SunCor's estate as part of a negotiated resolution to the bankruptcy. We do not expect SunCor's bankruptcy to have a material impact on Pinnacle West's financial position, results of operations or cash flows.

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 2010 through 2012, retail electric revenues comprised approximately 93% of our total electric operating revenues.

Our electric operating revenues are affected by customer growth or decline, variations in weather from period to period, customer mix, average usage per customer and the impacts of energy efficiency programs, distributed energy additions, electricity rates and tariffs, the recovery of PSA deferrals and the operation of other recovery mechanisms. Off-system sales of excess generation output, purchased power and natural gas are included in operating revenues and related fuel and purchased power because they are credited to APS's retail customers through the PSA. 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 2012 was 1.1% compared with the comparable prior year. For the three years 2010 through 2012, APS's customer growth averaged 0.7% per year. We currently expect annual customer growth to average about 2% for 2013 through 2015 based on our assessment of modestly improving economic conditions, both nationally and in Arizona. Retail electricity sales in kilowatt-hours, adjusted to exclude the effects of weather variations, increased 0.1% in 2012 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. For the three years 2010 through 2012, APS experienced annual declines in retail electricity sales averaging 0.1%, adjusted to exclude the effects of weather variations. We currently estimate that annual retail electricity sales in kilowatt-hours will remain about flat on average during 2013 through 2015, 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 continue 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, impacts of energy efficiency programs and growth in distributed generation, and responses to retail price changes. Our experience indicates that a reasonable range of variation in our kilowatt-hour 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.

54 -------------------------------------------------------------------------------- Table of Contents Weather. In forecasting the retail sales growth numbers provided above, we assume normal weather patterns based on historical data. Historical 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 growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, higher-trending pension and other postretirement benefit costs, renewable energy and demand side management related expenses (which are offset by the same amount of operating revenues) and other factors. In the settlement agreement related to the 2008 retail rate case, 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 distribution facilities), and changes in depreciation and amortization rates. See "Capital Expenditures" below for information regarding the planned additions to our facilities. As a result of the twenty-year extensions of the operating licenses for each of the Palo Verde units granted by the NRC in 2011, we decreased our pretax depreciation expense related to Palo Verde by approximately $34 million per year starting on January 1, 2012.

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 9.6% of the assessed value for 2012, 9.0% for 2011, and 8.0% for 2010. 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 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 55 -------------------------------------------------------------------------------- Table of Contents 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 reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution.

APSES's and SunCor's operations have been classified as discontinued operations. Pinnacle West sold its investment in APSES in August 2011. In February 2012, SunCor filed for protection under the United States Bankruptcy Code to complete an orderly liquidation of its business (see Note 21).

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 expects to make to SunCor's estate as part of a negotiated resolution to the bankruptcy (see Note 21) 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: 56 -------------------------------------------------------------------------------- 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 20) (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: 57 -------------------------------------------------------------------------------- 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.

58 -------------------------------------------------------------------------------- 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 expects to make to SunCor's estate as part of a negotiated resolution to the bankruptcy (see Note 21) and absence of a gain related to the sale of our investment in APSES in 2011.

Operating Results - 2011 compared with 2010 Our consolidated net income attributable to common shareholders for the year ended December 31, 2011 was $339 million, compared with net income of $350 million for the prior year. The $11 million net decrease consisted of a $14 million decrease in income from discontinued operations and a $3 million increase in income from continuing operations primarily related to the regulated electricity segment. Regulated electricity segment results reflect increased revenues related to weather and higher retail transmission charges and decreased operations and maintenance expenses. These positive factors were offset by higher depreciation and amortization due to increased plant in service, higher property taxes due to increased property tax rates and higher income taxes, including income tax benefits recognized in the prior year.

In addition, income from discontinued operations for the year ended December 31, 2011 included a gain of approximately $10 million after income taxes related to the sale of our investment in APSES. Income from discontinued operations in the prior year was due to a $25 million gain after income taxes related to the sale of APSES's district cooling business (see Note 21).

The following table presents net income attributable to common shareholders by business segment compared with the prior year: 59 -------------------------------------------------------------------------------- Table of Contents Year Ended December 31, 2011 2010 Net Change (dollars in millions) Regulated Electricity Segment: Operating revenues less fuel and purchased power expenses (a) (b) $ 2,228 $ 2,134 $ 94 Operations and maintenance (a) (b) (904 ) (870 ) (34 ) Depreciation and amortization (427 ) (415 ) (12 ) Taxes other than income taxes (148 ) (135 ) (13 ) Other income (expenses), net 16 18 (2 ) Interest charges, net of allowance for borrowed funds used during construction (224 ) (226 ) 2 Income taxes (184 ) (161 ) (23 ) Less income related to noncontrolling interests (Note 20) (28 ) (20 ) (8 ) Regulated electricity segment net income 329 325 4 All other (1 ) - (1 ) Income from Continuing Operations Attributable to Common Shareholders 328 325 3 Income from Discontinued Operations Attributable to Common Shareholders (c) 11 25 (14 ) Net Income Attributable to Common Shareholders $ 339 $ 350 $ (11 ) -------------------------------------------------------------------------------- (a) Includes effects of 2011 settlement of certain prior-period transmission rights-of-way related to Four Corners, 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) Operating revenues less fuel and purchased power expensesincludes amounts related to demand-side management, renewable energy and similar regulatory surcharges, which were substantially offset in operations and maintenance.

(c) Includes activities related to APSES and SunCor.

Regulated electricity segment This section includes a discussion of major variances in income and expense amounts for the regulated electricity segment.

Operating revenues less fuel and purchased power expenses Regulated electricity segment operating revenues less fuel and purchased power expenses were $94 million higher for the year ended December 31, 2011 compared with the prior year. The following table describes the major components of this change: 60 -------------------------------------------------------------------------------- Table of Contents Increase (Decrease) Fuel and purchased Operating power revenues expenses Net change (dollars in millions) Higher demand-side management, renewable energy and similar regulatory surcharges $ 29 $ 1 $ 28 Settlement of certain prior-period transmission rights-of-way 28 - 28 Effects of weather on usage per customer 33 13 20 Higher retail transmission charges 10 - 10 Higher line extension revenues (Note 3) 7 - 7 Higher usage per customer 8 6 2 Refund of PSA deferrals (33 ) (40 ) 7 Higher fuel and purchased power costs, net of off-system sales (27 ) (24 ) (3 ) Miscellaneous items, net 2 7 (5 ) Total $ 57 $ (37 ) $ 94 Operations and maintenance Operations and maintenance expenses increased $34 million for the year ended December 31, 2011 compared with the prior year primarily because of: † An increase of $28 million related to settlement in 2011 of certain transmission rights-of-way costs, which was offset in operating revenues; † An increase of $27 million related to costs for demand-side management, renewable energy, and similar regulatory programs, which were offset in operating revenues; † A decrease of $16 million related to employee benefit costs; and † A decrease of $5 million due to other miscellaneous factors.

Depreciation and amortization Depreciation and amortization expenses were $12 million higher for the year ended December 31, 2011 compared with the prior year primarily because of increased plant in service.

Taxes other than income taxes Taxes other than income taxes increased $13 million for the year ended December 31, 2011 compared with the prior year primarily because of higher property tax rates in the current period.

Income taxes Income taxes were $23 million higher for the year ended December 31, 2011 compared with the prior year. This increase was primarily due to the effects of higher pretax income in the current year and income tax benefits recognized in the prior year related to a reduction in the Company's 2010 effective income tax rate.

61 -------------------------------------------------------------------------------- Table of Contents Discontinued Operations Income from discontinued operations for year ended December 31, 2011 included a gain of $10 million related to the sale of our investment in APSES. Income from discontinued operations for the year ended December 31, 2010 included an after tax gain of $25 million related to the sale of APSES's district cooling business (see Note 21).

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. On December 19, 2012, the Pinnacle West Board of Directors declared a quarterly dividend of $0.545 per share of common stock, payable on March 1, 2013 to shareholders of record on February 1, 2013. During 2012, Pinnacle West increased its indicated annual dividend from $2.10 per share to $2.18 per share. The level of our common stock dividends and future dividend growth will be dependent on declaration by our Board of Directors 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, 2012, APS's common equity ratio, as defined, was 57%. Its total shareholder equity was approximately $4.1 billion, and total capitalization was approximately $7.2 billion. Under this order, APS would be prohibited from paying dividends if such payment would reduce its total shareholder equity below approximately $2.9 billion, assuming APS's total capitalization remains the same. This restriction does not materially affect Pinnacle West's ability to meet its ongoing cash needs or ability to pay dividends to shareholders.

APS's capital requirements consist primarily of capital expenditures and maturities of long-term debt. APS funds its capital requirements with cash from operations and, to the extent necessary, external debt financing and equity infusions from Pinnacle West.

Many of APS's current capital expenditure projects qualify for bonus depreciation. The American Taxpayer Relief Act of 2012, signed into law on January 2, 2013, includes provisions extending the eligibility for 50% bonus depreciation to qualified property placed in service in 2013. As a result of this provision, and the previously enacted bonus depreciation provisions provided for in the Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010, total cash tax benefits of up to $400-$500 million are expected to be generated for APS through accelerated depreciation. The cash generated is an acceleration of the tax benefits that APS would have otherwise received over 20 years. It is anticipated that these cash benefits will be fully realized by APS by the end of 2013, with a majority of the benefit realized as of December 31, 2012.

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, 2012, 2011 and 2010 (dollars in millions): 62 -------------------------------------------------------------------------------- Table of Contents Pinnacle West Consolidated 2012 2011 2010 Net cash flow provided by operating activities $ 1,171 $ 1,125 $ 750 Net cash flow used for investing activities (873 ) (782 ) (576 ) Net cash flow used for financing activities (305 ) (420 ) (209 ) Net decrease in cash and cash equivalents $ (7 ) $ (77 ) $ (35 ) Arizona Public Service Company 2012 2011 2010 Net cash flow provided by operating activities $ 1,176 $ 1,128 $ 695 Net cash flow used for investing activities (873 ) (834 ) (747 ) Net cash flow provided by (used for) financing activities (319 ) (374 ) 31 Net decrease in cash and cash equivalents $ (16 ) $ (80 ) $ (21 ) Operating Cash Flows 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.

2011 Compared with 2010 Pinnacle West's consolidated net cash provided by operating activities was $1,125 million in 2011, compared to $750 million in 2010, an increase of $375 million in net cash provided. The increase is primarily due to the $161 million change in collateral and margin posted, as a result of changes in commodity prices and expiration of prior hedge contracts, and a $200 million voluntary pension contribution in 2010 (approximately $40 million of which is reflected in capital expenditures). In addition, APS's operating cash flows included income tax payments to the parent company of approximately $81 million in 2010.

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 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 105% funded as of January 1, 2012 and 101% funded as of January 1, 2013. 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 $65 million in 2012, zero in 2011 and $200 million in 2010. The minimum contributions for the pension plan due in 2013, 2014 and 2015 under the recently enacted Moving Ahead for Progress in the 21st Century Act (MAP-21) are estimated to be zero, $89 million and $112 million, respectively.

We expect to make voluntary contributions totaling $140 million to the pension plan in 2013, and contributions up to approximately $175 million in each of 2014 and 2015. With regard to contributions to our other postretirement benefit plans, we made a contribution of approximately $23 million in 2012, $19 million in 2011, and $17 63 -------------------------------------------------------------------------------- Table of Contents million in 2010. The contributions to our other postretirement benefit plans for 2013, 2014 and 2015 are expected to be approximately $20 million each year.

The $70 million long-term income tax receivable on the Consolidated Balance Sheets represents the anticipated refunds related to an APS tax accounting method change approved by the Internal Revenue Service ("IRS") in the third quarter of 2009. This amount is classified as long-term, as there remains uncertainty regarding the timing of this cash receipt. Further clarification of the timing is expected from the IRS within the next twelve months.

Investing Cash Flows 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.

2011 Compared with 2010 Pinnacle West's consolidated net cash used for investing activities was $782 million in 2011, compared to $576 million in 2010, an increase of $206 million in net cash used. The increase in net cash used for investing activities is primarily due to an increase of $131 million in capital expenditures and a decrease of $126 million in net proceeds from the sales of our non-utility businesses (see Note 21), partially offset by $55 million of proceeds from the sale of life insurance policies in 2011.

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, 2013 2014 2015 APS Generation: Nuclear Fuel $ 58 $ 82 $ 83 Renewables 190 42 - Environmental 21 86 187 Four Corners Units 4 and 5 253 - - Other Generation 142 246 340 Distribution 260 304 312 Transmission 152 204 200 Other (a) 45 69 66 Total APS $ 1,121 $ 1,033 $ 1,188 --------------------------------------------------------------------------------(a) Primarily information systems and facilities projects.

64 -------------------------------------------------------------------------------- Table of Contents 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.

For purposes of this table, we have assumed the consummation of APS's purchase of SCE's interest in Four Corners Units 4 and 5 and the subsequent shutdown of Units 1-3, as discussed in the "Overview" section above. As a result, we included the estimated $253 million purchase price under Generation and have not included environmental expenditures for Units 1-3. We have not included estimated costs for Cholla's compliance with EPA's Arizona regional haze rule since we have challenged the rule judicially and are considering our future options with respect to that plant if the rule is upheld. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require modification to our 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 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).

2011 Compared with 2010 Pinnacle West's consolidated net cash used for financing activities was $420 million in 2011, compared to $209 million in 2010, an increase of $211 million in net cash used. The increase in net cash used for financing activities is primarily due to $78 million of long-term debt repayments, net of issuances of long-term debt (see below), and proceeds of $253 million from the issuance of equity in April 2010 (which was infused into APS), partially offset by $121 million lower repayments of short-term borrowings at Pinnacle West.

APS's net cash used for financing activities was $374 million in 2011, compared to net cash provided of $31 million in 2010, an increase of $405 million in net cash used. APS's increase in net cash used for financing activities is primarily due to $107 million of long-term debt repayments, net of issuances of long-term debt (see below), and proceeds of $253 million from the infusion of equity from Pinnacle West in April 2010. In addition, APS increased its dividend payment to Pinnacle West by $47 million in 2011.

Significant Financing Activities During the year ended December 31, 2012, Pinnacle West's total dividends paid per share of common stock was $2.12 per share, which resulted in dividend payments of $225 million.

65 -------------------------------------------------------------------------------- Table of Contents On January 13, 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042. The net proceeds from the sale were used along with other funds to repay at maturity APS's $375 million aggregate principal amount of 6.50% senior notes on March 1, 2012.

On May 1, 2012, pursuant to the mandatory tender provision, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project), 2009 Series B, due 2029. On June 1, 2012 these bonds were remarketed. Currently, the interest rate on these bonds is reset daily by a remarketing agent. The daily rate at December 31, 2012 was 0.13% per annum.

Additionally, the bonds are supported by a letter of credit. These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2012 and were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2011.

On June 1, 2012, pursuant to the mandatory tender provision, APS changed the interest rate mode for the approximately $38 million of Navajo County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Cholla Project), 2009 Series A. The new term rate period for these bonds commenced on June 1, 2012, and ends, subject to a mandatory tender, on May 29, 2014. During this time, the bonds will bear interest at a rate of 1.25% per annum. These bonds are classified as long-term debt on our Consolidated Balance Sheets at December 31, 2012 and were classified as current maturities of long-term debt on our Consolidated Balance Sheets at December 31, 2011.

On November 1, 2012 APS redeemed at par all $90 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds (Arizona Public Service Company Palo Verde Project) 2002 Series A, due 2029.

On November 29, 2012, Pinnacle West entered into a $125 million term loan that matures November 27, 2015. Pinnacle West used the proceeds of the loan to repay its existing term loan of $125 million. Interest rates are based on Pinnacle West's senior unsecured debt credit ratings or, if unavailable, its long-term issuer ratings.

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, 2012, 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, 2012, Pinnacle West had no outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

At December 31, 2012, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in February 2015, and a $500 million 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 will use these facilities to refinance indebtedness and for other general corporate purposes.

Interest rates are based on APS's senior unsecured debt credit ratings.

66 -------------------------------------------------------------------------------- Table of Contents The APS 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, 2012, APS had no outstanding borrowings under its revolving credit facilities or letters of credit. In addition, APS had commercial paper borrowings of $92 million at December 31, 2012.

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 of at least $700 million by December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in 2010).

See Note 18 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, 2012, the ratio was approximately 46% 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 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, 2013 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 67 -------------------------------------------------------------------------------- Table of Contents 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 Baa2 BBB+ BBB Commercial paper P-3 A-2 F3 Outlook Stable Stable Stable APS Corporate credit rating Baa1 BBB+ BBB Senior unsecured Baa1 BBB+ BBB+ Secured lease obligation bonds Baa1 BBB+ BBB+ Commercial paper P-2 A-2 F3 Outlook Stable Stable Stable Off-Balance Sheet Arrangements See Note 20 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, 2012 (dollars in millions): 68 -------------------------------------------------------------------------------- Table of Contents 2014- 2016- 2013 2015 2017 Thereafter Total Long-term debt payments, including interest: (a) APS $ 307 $ 1,191 $ 604 $ 3,283 $ 5,385 Pinnacle West 2 4 125 - 131 Total long-term debt payments, including interest 309 1,195 729 3,283 5,516 Fuel and purchased power commitments (b) 489 1,116 955 6,329 8,889 Renewable energy credits (c) 51 81 80 491 703 Purchase obligations (d) 96 29 14 221 360 Coal reclamation 1 74 27 17 119 Nuclear decommissioning funding requirements 17 36 4 67 124 Noncontrolling interests (e) 17 56 - - 73 Operating lease payments 21 32 7 41 101 Total contractual commitments $ 1,001 $ 2,619 $ 1,816 $ 10,449 $ 15,885 -------------------------------------------------------------------------------- (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, 2012 (see Note 6).

(b) Our fuel and purchased power commitments include purchases of coal, electricity, natural gas, renewable energy, nuclear fuel, and natural gas transportation (see Notes 3 and 11).

(c) Contracts to purchase renewable energy credits in compliance with the RES (see Note 3).

(d) These contractual obligations include commitments for capital expenditures and other obligations. These amounts do not include the purchase of SCE's interest in Four Corners Units 4 and 5 due to additional approvals required. See discussion in "Overview." (e) Payments to the noncontrolling interests relate to the Palo Verde Sale Leaseback (see Note 20). We have committed to retain the assets relating to the noncontrolling interest 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, and such value is unknown at this time. 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 $135 million in unrecognized tax benefits because the timing of the future cash outflows is uncertain. This table also excludes approximately zero, $89 million and $112 million in estimated minimum pension contributions for 2013, 2014 and 2015, respectively (see Note 8).

69 -------------------------------------------------------------------------------- Table of Contents 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 the 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 the state and is subject to change in the future. If future recovery of costs ceases to be probable, the assets would be written off as a charge in current period earnings. We had $1.2 billion of regulatory assets and $847 million of regulatory liabilities on the Consolidated Balance Sheets at December 31, 2012.

Included in the balance of regulatory assets at December 31, 2012 is a regulatory asset of $780 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 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, 2012 reported pension liability on the Consolidated Balance Sheets and our 2012 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): 70 -------------------------------------------------------------------------------- Table of Contents Increase (Decrease) Impact on Impact on Pension Pension Actuarial Assumption (a) Liability Expense Discount rate: Increase 1% $ (330 ) $ (12 ) Decrease 1% 408 15 Expected long-term rate of return on plan assets: Increase 1% - (9 ) Decrease 1% - 9 -------------------------------------------------------------------------------- (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, 2012 reported other postretirement benefit obligation on the Consolidated Balance Sheets and our 2012 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% $ (149 ) $ (8 ) Decrease 1% 186 10 Health care cost trend rate (b): Increase 1% 172 14 Decrease 1% (136 ) (11 ) Expected long-term rate of return on plan assets - pretax: Increase 1% - (3 ) Decrease 1% - 3 -------------------------------------------------------------------------------- (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 health care cost trend rate.

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

Derivative Accounting Derivative accounting requires evaluation of rules that are complex and subject to varying interpretations. Our evaluation of these rules, as they apply to our contracts, determines whether we use 71 -------------------------------------------------------------------------------- Table of Contents accrual accounting (for derivative instruments designated as normal) or fair value (mark-to-market) accounting. Mark-to-market accounting requires that changes in the fair value of derivative instruments are recognized in current earnings unless certain hedge criteria are met. Effective June 1, 2012, APS discontinued cash flow hedging for the significant majority of derivative contracts. APS now defers 100% of changes in fair value on these contracts for future rate treatment in accordance with the PSA (see Note 3).

See "Market Risks - Commodity Price Risk" below for quantitative analysis. See "Fair Value Measurements" below for additional information on valuation. See Note 1 for discussion on accounting policies and Note 18 for a further discussion on derivative accounting.

Fair Value Measurements We account for derivative instruments, investments held in our nuclear decommissioning trust, 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 discussion on accounting policies and Note 14 for further fair value measurement discussion.

OTHER ACCOUNTING MATTERS See Note 2 for discussion regarding amended accounting guidance adopted during 2012 relating to fair value measurements and disclosures, and the presentation of comprehensive income.

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 22) and benefit plan assets. The nuclear decommissioning trust fund and benefit plan assets also have risks associated with the changing market value of its equity and other non-fixed income investments. Nuclear decommissioning and benefit plan costs are recovered in regulated electricity prices.

72 -------------------------------------------------------------------------------- Table of Contents 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, 2012 and 2011. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2012 and 2011 (dollars in thousands): Pinnacle West - Consolidated 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 Variable-Rate Fixed-Rate Long-Term Debt Long-Term Debt Interest Interest 2011 Rates Amount Rates Amount 2012 - $ - 6.41 % $ 477,435 2013 - - 4.94 % 122,828 2014 - - 5.91 % 502,274 2015 1.79 % 125,000 4.79 % 313,420 2016 0.09 % 43,580 6.15 % 314,000 Years thereafter - - 6.49 % 1,605,150 Total $ 168,580 $ 3,335,107 Fair value $ 167,018 $ 3,758,811 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, 2012 and 2011. The interest rates presented in the tables below represent the weighted-average interest rates as of December 31, 2012 and 2011 (dollars in thousands): 73 -------------------------------------------------------------------------------- Table of Contents APS - Consolidated 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 Variable-Rate Fixed-Rate Long-Term Debt Long-Term Debt Interest Interest 2011 Rates Amount Rates Amount 2012 - $ - 6.41 % $ 477,435 2013 - - 4.94 % 122,828 2014 - - 5.91 % 502,274 2015 - - 4.79 % 313,420 2016 0.09 % 43,580 6.15 % 314,000 Years thereafter - - 6.49 % 1,605,150 Total $ 43,580 $ 3,335,107 Fair value $ 43,580 $ 3,758,811 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 2012 and 2011 (dollars in millions): 74 -------------------------------------------------------------------------------- Table of Contents 2012 2011Mark-to-market of net positions at beginning of year $ (222 ) $ (239 ) Recognized in earnings (a): Change in mark-to-market gains (losses) for future period deliveries 1 (4 ) (Increase) decrease in regulatory asset 37 (1 ) Recognized in OCI: Change in mark-to-market losses for future period deliveries (b) (37 ) (95 ) Mark-to-market losses realized during the period 99 117 Change in valuation techniques - - Mark-to-market of net positions at end of year $ (122 ) $ (222 ) --------------------------------------------------------------------------------(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, 2012 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 2013 2014 2015 2016 2017 thereafter value Observable prices provided by other external sources $ (53 ) $ (20 ) $ (1 ) $ - $ - $ - $ (74 ) Prices based on unobservable inputs (10 ) (9 ) (11 ) (8 ) (4 ) (6 ) (48 ) Total by maturity $ (63 ) $ (29 ) $ (12 ) $ (8 ) $ (4 ) $ (6 ) $ (122 ) 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, 2012 and 2011 (dollars in millions): 75 -------------------------------------------------------------------------------- Table of Contents December 31, 2012 December 31, 2011 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 $ - $ - $ 1 $ (1 ) Regulatory asset (liability) or OCI (b) Electricity 7 (7 ) 5 (5 ) Natural gas 25 (25 ) 27 (27 ) Total $ 32 $ (32 ) $ 33 $ (33 ) --------------------------------------------------------------------------------(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 18 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.

76 -------------------------------------------------------------------------------- Table of Contents

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Internet+ is an extended Internet access allowing high quality SIP (Session Initiation Protocol) based real-time person-to-person communication, everywhere and for any application. It applies to both fixed and mobile networks ...

Featured Blogs

Featured Webinars

Secure SIP Trunking:
What You Need to Know

Successfully Deploying Enterprise SIP Trunking:
Tools and Techniques for Overcoming Common Roadblocks

Featured Podcasts

Getting the Most Out of Your SIP Trunks:
Ingate's Steve Johnson and TMC's Erik Linask discuss how best practices forgetting the most out of SIP Trunking services and common pitfalls to avoid.

Featured Datasheets

Ingate SIParator E-SBCs
Adopting SIP is a simple process with the Ingate SIParator, the secure enterprise session border controller (E-SBC). The SIParator makes secure SIP communications - including VoIP,SIP trunking and more - possible while working seamlessly with your existing network firewall.

Ingate Firewalls
Everyone is talking about enterprise usage of VoIP, instant messaging and other types of realtime communications including presence and conferencing.

SIP Trunk Solutions for Service Providers
The award-winning Ingate Firewall and Ingate SIParator deliver a high quality, reliable SIP trunk connection between the customer's IP-PBX and the service provider network, and solve interoperability issues to simplify deployments and support for remote diagnosis of reported issues.