EX-99.2 3 a0930178kexhibit992.htm EXHIBIT 99.2
Third Quarter 2017 THIRD QUARTER 2017 RESULTS November 3, 2017

Third Quarter 20172 FORWARD LOOKING STATEMENTS AND NON-GAAP FINANCIAL MEASURES This presentation contains forward-looking statements based on current expectations, including statements regarding our earnings guidance and financial outlook and goals. These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume,” “project” and similar words. Because actual results may differ materially from expectations, we caution you not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS. These factors include, but are not limited to: our ability to manage capital expenditures and operations and maintenance costs while maintaining high reliability and customer service levels; variations in demand for electricity, including those due to weather seasonality, the general economy, customer and sales growth (or decline), and the effects of energy conservation measures and distributed generation; power plant and transmission system performance and outages; competition in retail and wholesale power markets; regulatory and judicial decisions, developments and proceedings; new legislation, ballet initiatives and regulation, including those relating to environmental requirements, regulatory policy, nuclear plant operations and potential deregulation of retail electric markets; fuel and water supply availability; our ability to achieve timely and adequate rate recovery of our costs, including returns on and of debt and equity capital investments; our ability to meet renewable energy and energy efficiency mandates and recover related costs; risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty; current and future economic conditions in Arizona, including in real estate markets; the development of new technologies which may affect electric sales or delivery; the cost of debt and equity capital and the ability to access capital markets when required; environmental, economic and other concerns surrounding coal-fired generation, including regulation of greenhouse gas emissions; volatile fuel and purchased power costs; the investment performance of the assets of our nuclear decommissioning trust, pension, and other postretirement benefit plans and the resulting impact on future funding requirements; the liquidity of wholesale power markets and the use of derivative contracts in our business; potential shortfalls in insurance coverage; new accounting requirements or new interpretations of existing requirements; generation, transmission and distribution facility and system conditions and operating costs; the ability to meet the anticipated future need for additional generation and associated transmission facilities in our region; the willingness or ability of our counterparties, power plant participants and power plant land owners to meet contractual or other obligations or extend the rights for continued power plant operations; and restrictions on dividends or other provisions in our credit agreements and ACC orders. These and other factors are discussed in Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2016 and in Part II, Item 1A of the Pinnacle West/APS Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, which you should review carefully before placing any reliance on our financial statements, disclosures or earnings outlook. Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law. In this presentation, references to net income and earnings per share (EPS) refer to amounts attributable to common shareholders. We present “electricity gross margin” per diluted share of common stock. Gross margin refers to operating revenues less fuel and purchased power expenses. Gross margin is a “non-GAAP financial measure,” as defined in accordance with SEC rules. The appendix contains a reconciliation of this non-GAAP financial measure to the referenced revenue and expense line items on our Consolidated Statements of Income, which are the most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles in the United States of America (GAAP). We view gross margin as an important performance measure of the core profitability of our operations. We refer to “on-going EPS” in this presentation, which is also a non-GAAP financial measure. 2017 and 2018 on-going EPS are currently projected to be the same as 2017 and 2018 GAAP EPS, respectively. We believe on-going earnings provides investors with a useful indicator of our results that is comparable among periods because it excludes the effects of unusual items that may occur on an irregular basis. Investors should note that these non-GAAP financial measures may involve judgments by management, including whether an item is classified as an unusual item. These measures are key components of our internal financial reporting and are used by our management in analyzing the operations of our business. We believe that investors benefit from having access to the same financial measures that management uses.

Third Quarter 20173 CONSOLIDATED EPS COMPARISON 2017 VS. 2016 $2.46 $2.35 2017 2016 3rd Quarter GAAP Net Income $2.46 $2.35 3rd Quarter On-Going Earnings $4.16 $3.47 2017 2016 Year-to-Date GAAP Net Income $4.16 $3.47 Year-to-Date On-Going Earnings

Third Quarter 20174 Gross Margin(1) $0.22 ON-GOING EPS VARIANCES 3RD QUARTER 2017 VS. 3RD QUARTER 2016 Other, net $(0.01) Interest, net of AFUDC $0.01 O&M(1) $(0.02) 3Q 2016 3Q 2017 $2.35 $2.46 D&A $(0.07) (1) Excludes costs and offsetting operating revenues associated with renewable energy and demand side management programs. See non-GAAP reconciliation in Appendix. Other Taxes $(0.02) Gross Margin Rate Increase $ 0.13 Sales $ 0.02 Weather $ 0.02 Transmission $ 0.04 LFCR $ (0.01) Other $ 0.02

Third Quarter 20175 ECONOMIC INDICATORS Arizona and Metro Phoenix remain attractive places to live and do business E 0% 5% 10% 15% 20% 25% '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 Nonresidential Building Vacancy – Metro Phoenix Vacancy Rate Office Retail Industrial Q3 Above-average job growth in tourism, health care, manufacturing, financial services, and construction Maricopa County ranked #1 in U.S. for population growth in 2016 - U.S. Census Bureau March 2017 Scottsdale ranked best place in the U.S. to find a new job in 2017; 4 other valley cities ranked in Top 20 - WalletHub January 2017 Housing construction on pace to have its best year since 2007 Vacancy rates in office and retail space have fallen to pre-recessionary levels 0 10,000 20,000 30,000 40,000 '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 Single Family Multifamily Single Family & Multifamily Housing Permits Maricopa County

Third Quarter 20176 ON-GOING EPS GUIDANCE AS OF NOVEMBER 3, 2017 2017 Guidance 2018 Guidance $4.15 – $4.30 + Rate increase* + Adjustment mechanisms, primarily Transmission Cost Adjustor (TCA) and Lost Fixed Cost Recovery (LFCR) + Selective Catalytic Reduction (SCR) and Ocotillo deferrals* + Modest sales growth – Higher D&A due to plant additions and rates* – Higher O&M, primarily planned fossil outages – Higher Taxes Other Than Income Taxes, primarily higher property taxes* – Higher Interest – Lower AFUDC Key Drivers 2017 - 2018 $4.25 – $4.45 See key factors and assumptions in appendix. * 2017 Rate Review Order specific items.

Third Quarter 2017 APPENDIX

Third Quarter 20178 2017 ON-GOING EPS GUIDANCE Key Factors & Assumptions as of November 3, 2017 2017 Electricity gross margin* (operating revenues, net of fuel and purchased power expenses) $2.45 – $2.50 billion • Retail customer growth about 1.5-2.5% • Weather-normalized retail electricity sales volume about 0-1.0% higher compared to prior year taking into account effects of customer conservation, energy efficiency and distributed renewable generation initiatives • Actual weather through September; normal weather patterns remainder of year Operating and maintenance (O&M)* $830 – $850 million Other operating expenses (depreciation and amortization, taxes other than income taxes, and other miscellaneous expenses) $725 – $745 million Interest expense, net of allowance for borrowed and equity funds used during construction (Total AFUDC $65 million) $150 – $160 million Net income attributable to noncontrolling interests $20 million Effective tax rate 33% Average diluted common shares outstanding 112.6 million On-going EPS Guidance $4.15 – $4.30 * Excludes O&M of $80 million, and offsetting revenues, associated with renewable energy and demand side management programs.

Third Quarter 20179 2018 ON-GOING EPS GUIDANCE Key Factors & Assumptions as of November 3, 2017 2018 Electricity gross margin* (operating revenues, net of fuel and purchased power expenses) $2.61 – $2.66 billion • Retail customer growth about 1.5-2.5% • Weather-normalized retail electricity sales volume about 0.5-1.5% higher compared to prior year taking into account effects of customer conservation, energy efficiency and distributed renewable generation initiatives • Assumes normal weather Operating and maintenance (O&M)* $860 – $880 million Other operating expenses (depreciation and amortization, Four Corners SCRs and Ocotillo deferrals, taxes other than income taxes, and other miscellaneous expenses) $790 – $810 million Interest expense, net of allowance for borrowed and equity funds used during construction (Total AFUDC $55 million) $190 – $200 million Net income attributable to noncontrolling interests $20 million Effective tax rate 34% Average diluted common shares outstanding 113.2 million On-going EPS Guidance $4.25 – $4.45 * Excludes O&M of $90 million, and offsetting revenues, associated with renewable energy and demand side management programs.

Third Quarter 201710 FINANCIAL OUTLOOK Key Factors & Assumptions as of November 3, 2017 Assumption Impact Retail customer growth • Expected to average about 2-3% annually • Modestly improving Arizona and U.S. economic conditions Weather-normalized retail electricity sales volume growth • About 0.5-1.5% after customer conservation and energy efficiency and distributed renewable generation initiatives Assumption Impact Lost Fixed Cost Recovery (LFCR) • Offsets 30-40% of revenues lost due to ACC-mandated energy efficiency and distributed renewable generation initiatives Environmental Improvement Surcharge (EIS) • Assumed to recover up to $14 million annually of carrying costs for government-mandated environmental capital expenditures (cumulative per kWh cap rate of $0.00050) Power Supply Adjustor (PSA) • 100% recovery • Includes certain environmental chemical costs and third-party battery storage Transmission Cost Adjustor (TCA) • TCA is filed each May and automatically goes into rates effective June 1 • Transmission revenue is accrued each month as it is earned. APS Solar Communities • Additions to flow through RES until next base rate case Four Corners Units 4 and 5 SCRs • 2019 step increase Property Tax Rate Deferral: APS is allowed to defer for future recovery (or credit to customers) the Arizona property tax expense above (or below) the 2015 test year caused by changes to the applicable composite property tax rate. Gross Margin – Customer Growth and Weather (2017-2019) Gross Margin – Related to 2017 Rate Review Order Outlook Through 2019: Goal of earning more than 9.5% Return on Equity (earned Return on Equity based on average Total Shareholder’s Equity for PNW consolidated, weather-normalized)

Third Quarter 201711 DIVIDEND GROWTH Pinnacle West’s indicated annual dividend is $2.78 per share; targeting ~6% annual dividend growth $2.10 $2.18 $2.27 $2.38 $2.50 $2.62 $2.78 2011 2012 2013 2014 2015 2016 2017 2018 2019 Dividend Growth Goal Indicated Annual Dividend Rate at Year-End Targeted Future dividends subject to declaration at Board of Directors’ discretion.

Third Quarter 201712 RATE BASE APS’s revenues come from a regulated retail rate base and meaningful transmission business $6.5 $6.8 $8.2 $1.4 $1.4 $1.8 2015 2016 2017 2018 2019 APS Rate Base Growth Year-End ACC FERC Total Approved Rate Base Projected ACC FERC Rate Effective Date 8/19/2017 6/1/2017 Test Year Ended 12/31/20151 12/31/2016 Rate Base $6.8B $1.4B Equity Layer 55.8% 55% Allowed ROE 10.0% 10.75% 1 Adjusted to include post test-year plant in service through 12/31/2016 83% 17% Generation & Distribution Transmission Rate base $ in billions, rounded

Third Quarter 201713 $221 $211 $273 $227 $79 $245 $121 $8 $220 $199 $90 $22 $102 $3 $16 $16 $127 $182 $178 $175 $388 $420 $421 $437 $87 $77 $82 $124 2016 2017 2018 2019 APS CAPITAL EXPENDITURES Capital expenditures are funded primarily through internally generated cash flow ($ Millions) $1,224 $1,337 Other Distribution Transmission Renewable Generation Environmental(1) Traditional Generation Projected $1,181 New Gas Generation(2) • The table does not include capital expenditures related to 4CA’s 7% interest in the Four Corners Power Plant Units 4 and 5 of $30 million in 2016, $27 million in 2017, $15 million in 2018 and $6 million in 2019. • 2017 – 2019 as disclosed in Third Quarter 2017 Form 10-Q. (1) Includes Selective Catalytic Reduction controls at Four Corners with in-service dates of Q4 2017 (Unit 5) and Q1 2018 (Unit 4) (2) Ocotillo Modernization Project: 2 units scheduled for completion in Q4 2018, 3 units scheduled for completion in Q1 2019 $1,009

Third Quarter 201714 OPERATIONS & MAINTENANCE Goal is to keep O&M per kWh flat, adjusted for planned outages 751 753 734 756 775 - 785 785 - 795 37 52 38 72 55 - 65 75 - 85$788 $805 $772 $828 $830 - $850 $860 - $880 2013 2014 2015 2016 2017E 2018E* PNW Consolidated ex RES/DSM** Planned Fleet Outages * 2018 excludes impacts related to the adoption of the new accounting standard regarding the presentation of pension and postretirement benefit costs. See Notes 4 and 12 in the Third Quarter 2017 Form 10-Q for additional information. ** Excludes RES/DSM of $137 million in 2013, $103 million in 2014, $96 million in 2015, $83 million in 2016, $80 million in 2017E and $90 million in 2018E. ($ Millions)

Third Quarter 201715 Palo Verde Generating Station − Palo Verde will continue to have two refueling outages each year (18 months cycles for each of the three units) − APS’s share of the annual planned outage expense at Palo Verde has been between $18 - $22 million per year since 2013 − Equipment testing, inspections, and plant modifications are performed during the outages that cannot be done while the unit is online − Outage duration and cost are driven by scope of planned work as well as emergent work identified during the outage Gas/Oil Plants − No planned cycles; major maintenance outages are based on run hours and/or the number of starts and overall plant condition − Increasing levels of solar generation, participation in Energy Imbalance Market, and low gas prices have resulted in increased starts Coal Plants − Major maintenance outage cycles are typically between 6 to 8 years PLANNED OUTAGE CYCLES The length of time between outages varies from plant to plant

Third Quarter 201716 Credit Ratings • A- or equivalent ratings or better at S&P, Moody’s and Fitch 2017 Major Financing Activities • $300 million 10-year 2.95% APS senior unsecured notes issued September 2017 • $250 million re-opening in March of APS’s outstanding 4.35% senior unsecured notes due November 2045 • Expect up to $350 million of long-term debt issuance at PNW (including refinancing of its $125 million term loan) 2018 Major Financing Activities • Currently expect up to $400 million of long-term debt issuance at APS We are disclosing credit ratings to enhance understanding of our sources of liquidity and the effects of our ratings on our costs of funds. BALANCE SHEET STRENGTH $50 $600 $250 $125 $- $100 $200 $300 $400 $500 $600 2017 2018 2019 2020 APS PNW ($Millions) Debt Maturity Schedule

Third Quarter 201717 2017 RATE REVIEW ORDER* EFFECTIVE AUGUST 19, 2017 Key Financial Proposals – Base Rate Changes Annualized Base Rate Revenue Changes ($ millions) Non-fuel, Non-depreciation Base Rate Increase $ 87.2 Decrease fuel and Purchased Power over Base Rates (53.6) Increase due to Changes in Depreciation Schedules 61.0 Total Base Rate Increase $ 94.6 Key Financial Assumptions Allowed Return on Equity 10.0% Capital Structure Long-term debt 44.2% Common equity 55.8% Base Fuel Rate (¢/kWh) 3.0168 Post-test year plant period 12 months *The ACC’s decision is subject to appeals.

Third Quarter 201718 Key Proposals – Revenue Requirement Four Corners • Cost deferral order from in-service dates to incorporation of SCRs in rates using a step-increase no later than January 1, 2019 Ocotillo Modernization Project • Cost deferral order from in-service dates to effective date in next rate case Power Supply Adjustor (PSA) • Modified to include certain environmental chemical costs and third-party battery storage Property Tax Deferral • Defer for future recovery the Arizona property tax expense above or below the test year rate Key Proposals – Rate Design Lost Fixed Cost Recovery (LFCR) • Modified to be applied as a capacity (demand) charge per kW for customer with a demand rate and as a kWh charge for customers with a two-part rate without demand Environmental Improvement Surcharge (EIS) • Increased cumulative per kWh cap rate from $0.00016 to a new rate of $0.00050 and include a balancing account Time-of-Use Rates (TOU) • Modified on-peak period for residential, and extra small through large general service to 3:00 pm – 8:00 pm weekdays • After September 1, 2018, a new TOU rate will be the standard rate for all new customers (except small use) Distributed Generation • New DG customers eligible for TOU rate with Grid Access Charge or Demand rates • Resource Comparison Proxy (RCP) for exported energy of $0.129/kWh in year one APS Solar Communities • New program for utility-owned solar distributed generation, recoverable through the Renewable Energy Adjustment Clause (RES), to be no less than $10 million per year, and not more than $15 million per year Other Considerations Rate Case Moratorium • No new general rate case application before June 1, 2019 (3-year stay-out) Self-Build Moratorium • APS will not pursue any new self-build generation (with exceptions) having an in-service date prior to January 1, 2022 (extended to December 31, 2027 for combined-cycle generating units) unless expressly authorized by the ACC 2017 RATE REVIEW ORDER* EFFECTIVE AUGUST 19, 2017 *The ACC’s decision is subject to appeals.

Third Quarter 201719 OCOTILLO MODERNIZATION PROJECT AND FOUR CORNERS SCRs Ocotillo Modernization Project Four Corners SCRs In-Service Dates Units 6, 7 – Fall 2018 Units 3, 4 and 5 – Spring 2019 Unit 5 – Late 2017 Unit 4 – Spring 2018 Total Cost (APS) $500 million $400 million Estimated Cost Deferral $45 million (through 2019) $30 million (through 2018) Accounting Deferral − Cost deferral from date of commercial operation to the effective date of rates in next rate case − Includes depreciation, O&M, property taxes, and capital carrying charge1 − Cost deferral from time of installation to incorporation of the SCR costs in rates using a step increase beginning in 2019 − Includes depreciation, O&M, property taxes, and capital carrying charge1 • Included in the 2017 Rate Review Order*, APS has been granted Accounting Deferral Orders for two large generation-related capital investments – Ocotillo Modernization Project: Retiring two aging, steam-based, natural gas units, and replacing with 5 new, fast-ramping, combustion turbine units – Four Corners Power Plant: Installing Selective Catalytic Reduction (SCR) equipment to comply with Federal environmental standards 1 APS will calculate the capital carrying charge using the 5.13% embedded cost of debt established in the 2017 Rate Review Order. *The ACC’s decision is subject to appeals.

Third Quarter 201720 (4) 10 (13) 4 2 12 (10) $(15) $(10) $(5) $0 $5 $10 $15 Q1 Q2 Q3 Q4 Q1 Q2 Q3 GROSS MARGIN EFFECTS OF WEATHER VARIANCES VS. NORMAL Pretax Millions All periods recalculated to current 10-year rolling average (2005-2014) 2016 $(3) Million 2017 $4 Million

Third Quarter 201721 8 4 7 6 5 2 12 12 15 18 13 12 15 16 $0 $10 $20 $30 $40 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Renewable Energy Demand Side Management RENEWABLE ENERGY AND DEMAND SIDE MANAGEMENT EXPENSES* * Renewable energy and demand side management expenses are offset by adjustment mechanisms. Pretax Millions 2016 $83 Million 2017 $62 Million

Third Quarter 201722 NON-GAAP MEASURE RECONCILIATION $ millions pretax, except per share amounts 2017 2016 Operating revenues* 1,183$ 1,167$ Fuel and purchased power expenses* (310) (336) Gross margin 873 831 0.23$ Adjustments: Renewable energy and demand side management programs (32) (30) (0.01) Adjusted gross margin 841$ 801$ 0.22$ Operations and maintenance* (224)$ (217)$ (0.04)$ Adjustments: Renewable energy and demand side management programs (28) (25) 0.02 Adjusted operations and maintenance (196)$ (192)$ (0.02)$ * Line items from Consolidated Statements of Income Three Months Ended September 30, EPS Impact

Third Quarter 201723 NON-GAAP MEASURE RECONCILIATION $ millions pretax Operating revenues* 3,540$ - 3,600$ Fuel and purchased power expenses* (1,010) - (1,020) Gross margin 2,530 - 2,580 Adjustments: Renewable energy and demand side management programs (80) - (80) Adjusted gross margin 2,450$ - 2,500$ Operations and maintenance* 910$ - 930$ Adjustments: Renewable energy and demand side management programs (80) - (80) Adjusted operations and maintenance 830$ - 850$ * Line items from Consolidated Statements of Income 2017 Guidance

Third Quarter 201724 NON-GAAP MEASURE RECONCILIATION $ millions pretax Operating revenues* 3,790$ - 3,850$ Fuel and purchased power expenses* (1,090) - (1,100) Gross margin 2,700 - 2,750 Adjustments: Renewable energy and demand side management programs (90) - (90) Adjusted gross margin 2,610$ - 2,660$ Operations and maintenance* 950$ - 970$ Adjustments: Renewable energy and demand side management programs (90) - (90) Adjusted operations and maintenance 860$ - 880$ * Line items from Consolidated Statements of Income 2018 Guidance

Third Quarter 201725 CONSOLIDATED STATISTICS 2017 2016 Incr (Decr) 2017 2016 Incr (Decr) ELECTRIC OPERATING REVENUES (Dollars in Millions) Retail Residential 662$ 647$ 15 1,439$ 1,398$ 41$ Business 474 480 (6) 1,245 1,244 1 Total Retail 1,136 1,127 9 2,684 2,642 42 Sales for Resale (Wholesale) 22 24 (2) 63 64 (1) Transmission for Others 14 8 6 35 21 14 Other Miscellaneous Services 6 7 (1) 16 26 (10) Total Electric Operating Revenues 1,178$ 1,166$ 12 2,798$ 2,753$ 45$ ELECTRIC SALES (GWH) Retail Residential 4,753 4,703 50 10,655 10,524 131 Business 4,310 4,298 12 11,421 11,367 54 Total Retail 9,063 9,001 62 22,076 21,891 185 Sales for Resale (Wholesale) 655 784 (129) 2,278 2,722 (444) Total Electric Sales 9,718 9,785 (67) 24,354 24,613 (259) RETAIL SALES (GWH) - WEATHER NORMALIZED Residential 4,834 4,820 14 10,647 10,668 (21) Business 4,332 4,332 - 11,374 11,332 42 Total Retail Sales 9,166 9,152 14 22,021 22,000 21 Retail sales (GWH) (% over prior year) 0.2% 0.1% AVERAGE ELECTRIC CUSTOMERS Retail Customers Residential 1,079,344 1,059,173 20,171 1,078,672 1,060,181 18,491 Business 134,830 131,877 2,953 133,667 131,537 2,130 Total Retail 1,214,174 1,191,050 23,124 1,212,339 1,191,718 20,621 Wholesale Customers 40 49 (9) 42 46 (4) Total Customers 1,214,214 1,191,099 23,115 1,212,381 1,191,764 20,617 Total Customer Growth (% over prior year) 1.9% 1.7% RETAIL USAGE - WEATHER NORMALIZED (KWh/Average Customer) Residential 4,479 4,551 (72) 9,871 10,062 (191) Business 32,130 32,851 (721) 85,089 86,150 (1,061) 3 Months Ended September 30, 9 Months Ended September 30,

Third Quarter 201726 CONSOLIDATED STATISTICS 2017 2016 Incr (Decr) 2017 2016 Incr (Decr) WEATHER INDICATORS - RESIDENTIAL Actual Cooling Degree-Days 1,153 1,160 (7) 1,724 1,663 61 Heating Degree-Days - - - 439 397 42 Average Humidity 32% 31% 1% 26% 27% (1)% 10-Year Averages (2005 - 2014) Cooling Degree-Days 1,218 1,218 - 1,722 1,722 - Heating Degree-Days - - - 492 492 - Average Humidity 31% 31% - 25% 25% - ENERGY SOURCES (GWH) Generation Production Nuclear 2,514 2,417 97 7,147 7,108 39 Coal 2,093 1,680 413 5,635 4,311 1,324 Gas, Oil and Other 2,666 2,732 (66) 5,682 6,762 (1,080) Renewables 174 138 36 445 409 36 Total Generation Production 7,447 6,967 480 18,909 18,590 319 Purchased Power - - Conventional 2,223 2,644 (421) 4,644 4,984 (340) Resales 238 254 (16) 633 839 (207) Renewables 389 429 (40) 1,462 1,395 67 Total Purchased Power 2,850 3,327 (477) 6,738 7,218 (480) Total Energy Sources 10,297 10,294 3 25,647 25,808 (161) POWER PLANT PERFORMANCE Capacity Factors - Owned Nuclear 99% 96% 3% 95% 94% 1% Coal 57% 45% 12% 51% 39% 12% Gas, Oil and Other 40% 39% 1% 29% 32% (3)% Solar 35% 33% 2% 34% 33% 1% System Average 54% 51% 3% 46% 46% - 3 Months Ended September 30, 9 Months Ended September 30,