POWERING GROWTH DELIVERING VALUE First Quarter 2019 Results May 1, 2019

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, ballot 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 direct or indirect effect on our facilities or business from cybersecurity threats or intrusions, data security breaches, terrorist attack, physical attack, severe storms, droughts, or other catastrophic events, such as fires, explosions, pandemic health events or similar occurrences; 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, 2018, 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 “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, and is 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. We present “adjusted interest, net of AFUDC” and “adjusted other, net” that have been adjusted for the deferral impacts of the Four Corner’s Selective Catalytic Reduction equipment. We also present “adjusted gross margin” and “adjusted operations and maintenance” that have been adjusted to exclude costs and offsetting operating revenues associated with renewable energy and demand side management programs. We also present “adjusted income taxes" that shows the impact of tax reform. Adjusted interest, net of AFUDC, adjusted other, net, adjusted gross margin, adjusted operations and maintenance, and adjusted income taxes are “non-GAAP financial measures,” as defined in accordance with SEC rules. The appendix contains a reconciliation to show the deferral impacts of the Four Corners Selective Catalytic Reduction equipment, the exclusion of costs and offsetting operating revenues associated with renewable energy and demand side management programs, and the impact of tax reform. We believe the information provided in the reconciliation provides investors with useful indicators of our results that are comparable among periods because they exclude the effects of unusual items that may occur on an irregular basis, such as the installation of the SCR equipment and tax reform impacts, and exclude the effects of programs that overstate our gross margin. First Quarter 2019 | 2

EPS VARIANCES 1st Quarter 2019 vs. 1st Quarter 2018 1 D&A Adjusted Adjusted O&M Pension & $(0.03) Other Interest, $0.09 OPEB Taxes net of AFUDC2 Non-service $(0.01) $(0.01) Credits, net Adjusted $(0.05) Gross Adjusted Adjusted Margin1 Income Other, net2 $0.14 Taxes $(0.01) $0.01 $0.16 Gross Margin Weather $ 0.14 Rate Design/ $ 0.09 Seasonal Rates LFCR $ 0.02 Sales / Usage $ 0.01 $0.03 Transmission $ (0.06) Federal Tax Reform $ (0.02) 1Q 2018 Other $ (0.04) 1Q 2019 1 Excludes costs and offsetting operating revenues associated with renewable energy and demand side management programs. 2 Driver adjusted for the deferral impacts of the Four Corners Selective Catalytic Reduction (SCR) equipment. See non-GAAP reconciliation in Appendix. First Quarter 2019 | 3

ECONOMIC INDICATORS Arizona’s focus on economic development continues to support growth in the state Year over Year Employment Growth U.S. Phoenix Arizona is the 4th fastest-growing state in the U.S. 1 5% according to new Census data. 4% 3% 2018 – APS partnered with Greater Phoenix Economic Council and Arizona Commerce Authority to welcome 17 2% new companies to the state, adding an estimated: 1% • 43 MW 0% • 3,800 new jobs Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 • $1.3B in capital investment Single Family & Multifamily Housing Permits • Notable corporations include Anderson Windows, Maricopa County Nikola Motors and Seattle Box Company Single Family Multifamily Projected 40,000 Maricopa County ranked #1 in U.S. for 30,000 population growth for third straight year 2 20,000 10,000 1 U.S. Census Bureau, Population Division, Release date December 2018 0 2 U.S. Census Bureau April 2019 '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 '18 '19 First Quarter 2019 4

BALANCE SHEET STRENGTH Long-Term Debt Maturity Schedule $ in millions Credit Ratings2 $1,000 • APS Senior Unsecured: A- or equivalent ratings or better at S&P, Moody’s and Fitch $800 • PNW Senior Unsecured: BBB+ or equivalent ratings or better at S&P, Moody’s and Fitch $450 $600 2019 Major Financing Activities • $200 million 18-month APS unsecured term loan entered into in February 2019 $400 • $300 million 30-year 4.25% APS senior unsecured notes issued February 2019 $500 $200 $450 • Expect up to $450 million of long-term debt issuance at APS for the remainder of 2019 $- 20191 2020 APS PNW 2 1 APS debt matured on March 1, 2019 We are disclosing credit ratings to enhance understanding of our sources of liquidity and the effects of our ratings on our costs of funds. First Quarter 2019 5

2019 EPS GUIDANCE Key Factors & Assumptions as of May 1, 2019 2019 Adjusted gross margin1 (operating revenues, net of fuel and $2.50 – $2.56 billion purchased power expenses) • Retail customer growth about 1.5–2.5% • Weather-normalized retail electricity sales volume about 1-2% higher compared to prior year • Assumes normal weather Adjusted operating and maintenance (O&M)1 $865 – $885 million Other operating expenses (depreciation and amortization, deferrals, and taxes other than $850 – $870 million income taxes) Other income (pension and other post-retirement non-service credits, other income and $35 – $45 million other expense) Interest expense, net of allowance for borrowed and equity funds used during $195 – $205 million construction (Total AFUDC $40 million) Net income attributable to noncontrolling interests $20 million Effective tax rate 10% Average diluted common shares outstanding 113.6 million EPS Guidance $4.75 - $4.95 1 Excludes O&M of $80 million, and offsetting revenues, associated with renewable energy and demand side management programs. First Quarter 2019 6

FINANCIAL OUTLOOK Key Factors & Assumptions as of May 1, 2019 Gross Margin – Customer and Sales Growth (2019-2021) Assumption Impact Retail customer growth • Expected to average about 1.5-2.5% annually • Strength in Arizona and U.S. economic conditions Weather-normalized retail electricity sales volume growth • About 1.5–2.5% Gross Margin – Related to 2017 Rate Review Order 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) • Ability 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. Outlook Through 2021: 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) First Quarter 2019 | 7

RATE BASE APS’s revenues come from a regulated retail rate base and meaningful transmission business APS Rate Base Growth Total Approved Rate Base Year-End Generation & Distribution Transmission ACC FERC Long-term Rate Base Guidance: 17% 6-7% Average Annual Growth $2.0 83% $1.5 ACC FERC Rate Effective Date 8/19/2017 6/1/2018 $9.6 Test Year Ended 12/31/20151 12/31/2017 $7.1 Rate Base $6.8B $1.5B Equity Layer 55.8% 53.4% 2017 2018 2019 2020 2021 Allowed ROE 10.0% 10.75% Projected 1 Adjusted to include post test-year plant in service through 12/31/2016 Rate base $ in billions, rounded First Quarter 2019 8

OPERATIONS & MAINTENANCE Goal is to keep O&M per kwh flat, adjusted for planned outages $ in millions $933 $865 - $885 $848 $858 74 50 - 60 72 63 859 776 795 815 - 825 2016 2017 2018 2019E 1 PNW Consolidated ex RES/DSM Planned Fleet Outages 1 Excludes RES/DSM of $83 million in 2016, $91 million in 2017, $104 million in 2018, and $80 million in 2019E First Quarter 2019 | 9

2019 PLANNED OUTAGE SCHEDULE Coal, Nuclear, and Large Gas Planned Outages Q1 Q2 Q4 Estimated Estimated Estimated Plant Unit Duration Plant Unit Duration in Plant Unit Duration in Days Days in Days Four 4 21 Palo Verde 1 30 Palo Verde 3 44 Corners Four West 5 21 Cholla* 1 49 4 62 Corners Phoenix Cholla* 1 37 Redhawk* 2 28 Redhawk* 2 29 *Outage duration spans Q1-Q2. Number of days noted per quarter. First Quarter 2019 | 10

APS CAPITAL EXPENDITURES Capital expenditures will support our growing customer base and utilization of advanced technology $ in millions $1,600 PROJECTED $1,472 $1,400 $105 $1,266 $71 $1,202 $1,237 $1,200 $119 $117 $16 $41 $187 $31 $425 Traditional Generation $1,000 New Gas Generation 1 $112 $247 $332 $65 Environmental $800 $147 $197 Clean Generation $199 $171 $600 $116 Transmission Distribution $400 $500 $455 $546 Other $481 $200 $94 $125 $150 $128 $- 2018 2019 2020 2021 • The chart does not include capital expenditures related to 4CA’s 7% interest in the Four Corners Power Plant Units 4 and 5 of $10 million in 2018. • 2019 – 2021 as disclosed in the First Quarter 2019 Form 10-Q. 1 Ocotillo Modernization Project: Units scheduled for completion by mid-2019. First Quarter 2019 | 11

DISTRIBUTION GRID INVESTMENTS Grid Operations and Investment Projected to be $1.5 billion from 2019-2021 Customer Growth Grid Modernization Run and Maintain Approximately 50% of distribution capex Approximately 9% of distribution capex Approximately 41% of distribution capex Line Extensions for new residential and Cap Bank Controllers, Substation Regulators, Overhead Lines & Wood Pole Replacements commercial customers Voltage Management Algorithms Average annual spend ~ $8M Average annual spend ~ $68M Average annual spend ~ $11Mpend ~ $11M • Replace equipment or components due • Extend, relocate, and upgrade APS • Controls regulators and capacitor banks to damage, degradation or failure facilities in response to customer to manage power quality such as power • Ensure the integrity of the structure and request factor and voltage enhance system reliability R T New Distribution Substations & Reclosers – Supervisory Controlled Underground Cable Replacements Upgrades Switches, Trip Savers Average annual spend ~ $22.5M Average annual spend ~ $38M Average annual spend ~ $14M • Replace all remaining direct buried Construction over the next 3 years: • Leveraging AMI for distribution primary distribution cable • automation 21 New Substations • Direct buried cable has become a major • 3 Upgrades • Strategically deploying Fiber for cause of power outages communications backhaul First Quarter 2019| 12

• . CLEAN ENERGY INVESTMENTS Plans to Invest in 950 MW of New Clean Technology by 2025 2018 Battery Storage RFP • 141 MW located on six APS solar plant sites • Utility owned • Anticipated in-service by mid-2020 2018 Peaking Capacity RFP • 150 MW of battery storage • 20 year PPA contracts beginning June 2021 2019 RFPs • Advanced • 60 MW located on two APS solar plant sites Distribution • 100 MW of solar plus 100 MW of battery storage Management System • Utility owned (ADMS) • Distributed Energy • Anticipated in-service 2021 Resource Future Investments Management System (DERMS) • At least 400 MW of solar plus battery storage and stand-alone battery storage by mid-2025 • Utility owned First Quarter 2019 | 13

APPENDIX POWERING GROWTH - DELIVERING VALUE | 14

TAX REFORM Customer Rate Reductions ACC – TAX EXPENSE ADJUSTOR MECHANISM: • PHASE I: The ACC approved $119 million annual rate reduction reflecting the lower federal tax rate. Effective for the March 2018 billing cycle • PHASE II: The ACC approved an additional $86.5 million rate reduction to return the unprotected “excess” deferred taxes to ACC customers over a 12-month period. Effective for the April 2019 billing cycle • PHASE III: Filed in April 2019 – will address the refund of protected “excess” deferred taxes which are required to be returned over the regulatory life of plant property. The Company has proposed that Phase III begin July 1, 2019 and annually refund $34.5 million to customers over the first 36 months. The ACC has not yet approved this request Cash Taxes Net Regulatory Liability for Excess Deferred Taxes At March 31, 2019 • Due to loss of bonus depreciation, cash tax payments normalize in 2019 as ($ in millions) the Company utilizes its remaining tax credit carryforwards Total Net Regulatory Liability for Regulated Excess • Future investment tax credits from renewable efforts will likely reduce cash $1,520 tax payments in 2020 and 2021 Deferred Taxes Effective Tax Rate Net Regulatory Liability for Depreciation Related Excess $1,400 • Amortization of TEAM Phase II excess deferred taxes will benefit the Deferred Taxes (to be returned over the life of property) Company’s 2019 and 2020 ETR • Amortization of TEAM Phase III excess deferred taxes are anticipated to Net Regulatory Liability for Non-Depreciation Related benefit the ETR over a 28.5 year period $120 Excess Deferred Taxes First Quarter 2019 15

OCOTILLO MODERNIZATION PROJECT & FOUR CORNERS SCRs • Included in the 2017 Rate Review Order1, 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: Installed Selective Catalytic Reduction (SCR) equipment to comply with Federal environmental standards Ocotillo Modernization Project Four Corners SCRs Unit 5 – Late 2017 In-Service Dates Units 3 – 7 – Mid-2019 Unit 4 – Spring 2018 Total Cost (APS) $500 million $400 million Estimated Cost Deferral $45 million (through 2019) $30 million (through 2018) • Cost deferral from date of commercial • Cost deferral from time of installation to operation to the effective date of rates in next incorporation of the SCR costs in rates using a Accounting Deferral rate case step increase beginning in 2019 • Includes depreciation, O&M, property taxes, • Includes depreciation, O&M, property taxes, and capital carrying charge2 and capital carrying charge2 1 The ACC’s decision is subject to appeals 2 APS will calculate the capital carrying charge using the 5.13% embedded cost of debt established in the 2017 Rate Review Order First Quarter 2019 16

FOUR CORNERS SCR STEP INCREASE The Administrative Law Judge issued a Recommended Opinion and Order on November 27, 20181 Key Components of APS’s Filed Request Financial Cost of Capital Bill Impact • Consistent with prior • 7.85% Return on Rate Base2 • Rate rider applied as a disclosed estimates – Weighted Average Cost of percentage of base rates for Capital (WACC) all applicable customers • $390 million direct costs vs. • 5.13% Return on Deferral2 • $67.5 million revenue $400 million1 contemplated – Embedded Cost of Debt requirement2 in APS’s recent rate case • $40 million in indirect costs • 5% Depreciation Rate • ~2% bill impact (overhead, AFUDC) – 20-year useful life (2038-depreciation study) • 5-year Deferral Amortization 1 Arizona Corporation Commission Staff recommended a $58.5 million revenue increase and the Administrative Law Judge issued a Recommended Opinion and Order consistent with Commission Staff’s recommendation 2 Based on 2017 Rate Review Order First Quarter 2019 17

Residential DG (MWdc) Annual Additions 1 151 RESIDENTIAL PV APPLICATIONS 133 133 57 74 30 2014 2015 2016 2017 2018 2019 YTD 4,000 3718 3432 3,500 3,000 2464 2,500 2143 1944 2033 2,000 1818 1561 1930 1602 1426 1413 1442 1434 1,500 1359 1291 1364 1283 1153 1123 1001 1131 1267 1252 1,000 769 1148 838 850 745 939 999 897 911 744 759 500 629 614 538 321 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2016 Applications 2017 Applications 2018 Applications 2019 Applications 1 Monthly data equals applications received minus cancelled applications. As of March 31, 2019, approximately 92,200 residential grid-tied solar photovoltaic (PV) systems have been installed in APS’s service territory, totaling approximately 740 MWdc of installed capacity. Excludes APS Solar Partner Program residential PV systems. Note: www.arizonagoessolar.org logs total residential application volume, including cancellations. Solar water heaters can also be found on the site, but are not included in the chart above. First Quarter 2019 18

GROSS MARGIN EFFECTS OF WEATHER Variances vs. Normal $ in millions pretax $25 $20 $15 $10 14 $5 8 9 $0 $(5) $(10) (12) $(15) $(20) (23) $(25) $(30) Q1 Q2 Q3 Q4 Q1 2018 2019 $(13) Million $9 Million All periods recalculated to current 10-year rolling average (2007 – 2016) First Quarter 2019 | 19

RENEWABLE ENERGY AND DEMAND SIDE MANAGEMENT EXPENSES1 $ in millions pretax Renewable Energy Demand Side Management $40 $30 $10 $12 $20 $14 $11 $9 $10 $21 $17 $12 $13 $9 $0 Q1 Q2 Q3 Q4 Q1 2018 2019 $104 Million $24 Million 1 Renewable energy and demand side management expenses are offset by adjustment mechanisms First Quarter 2019 20

2019 KEY DATES ACC Key Dates / Docket # Q1 Q2 Q3 Q4 Power Supply Adjustor (PSA) Implemented: Feb 1 E-01345A-16-0036 Lost Fixed Cost Recovery 2018 LFCR approved 2019 LFCR Filed: E-01345A-16-0036 Feb 15 Transmission Cost Adjustor To be filed: May 15 E-01345A-16-0036 Implementation: Jun 1 2020 DSM/EE Implementation Plan 2020 To be filed: Jun 1 New Docket to be Assigned 2020 RES Implementation Plan To be Filed: Jul 1 New Docket to be Assigned Four Corners SCR Step Increase No scheduled events E-01345A-16-0036 Resource Planning and Procurement File preliminary IRP Aug 1 E-00000V-19-0034 Tax Expense Adjustor (TEAM) TEAM II approved TEAM III filed: Apr 10 E-01345A-18-0003 Mar 13 Resource Comparison Proxy (RCP) Year 3 To be filed: Year 3 Implementation Expected: New Docket to be Assigned May 1 Sept 1 QF/PURPA Contracts (EPR-2) APS testimony due Hearing begins Workshop Mar 29 E-01345A-16-0272 Jul 26 Nov 13 Possible Modification to Commission’s Energy Rules Workshops Feb 25, Workshops Apr 17, 29, 30 RU-00000A-18-0284 Mar 14, Mar 26 Modification to Retail Competition Rules Workshop proposed Jul RE-00000A-18-0405 Customer Complaint – Stacey Champion Commission Discussion Apr 23 E-01345A-18-0002 APS Rate Review Rate Review Began Staff report due May 3 E-01345A-19-0003 First Quarter 2019 21

NON-GAAP MEASURE RECONCILIATION Three Months Ended March 31, Four Four Income Corners Income tax Corners tax Debt expense at Debt expense at RES/ Return statutory 2019 RES/ Return statutory 2018 EPS 1 2 1 2 $ in millions pretax, except per share amounts 2019 DSM Deferral rate Adjusted 2018 DSM Deferral rate Adjusted Impact Operating revenues $ 741 $ (31) $ - $ - $ 710 $ 693 $ (37) $ - $ - $ 656 Fuel and purchased power expenses (231) 8 - - (223) (197) 7 - - (190) Gross margin 510 (23) - - 487 496 (30) - - 466 $ 0.14 Operations and maintenance 246 (24) - - 222 266 (31) - - 235 $ 0.09 Allowance for equity funds used during construction (11) - - - (11) (14) - - - (14) Interest charges 61 - (5) - 56 59 - (2) - 57 Allowance for borrowed funds used during construction (7) - - - (7) (7) - - - (7) Interest expense, net of AFUDC 43 - (5) - 38 38 - (2) - 36 $ (0.01) Other expenses (operating) - - - - - - - - - - Other income (7) - 5 - (2) (4) - 2 - (2) Other expense 4 - - - 4 3 - - - 3 Renewable energy and demand side management and similar regulatory programs, net - 1 - - 1 - 1 - - 1 Other (3) 1 5 - 3 (1) 1 2 - 2 $ (0.01) Income taxes 2 - - (6) (4) (1) - - (2) (3) $ 0.01 1 Line items from Consolidated Statements of Income. 2 See Note 4, Regulatory Matters, in Form 10-Q for the period ended March 31, 2019, for total Four Corners deferral impacts. First Quarter 2019 22 Numbers may not foot due to rounding.

NON-GAAP MEASURE RECONCILIATION 2019 Guidance $ in millions pretax Operating revenues1 $ 3,625 - $ 3,695 Fuel and purchased power expenses1 (1,045) - (1,055) Gross margin 2,580 - 2,640 Adjustments: Renewable energy and demand side management programs (80) - (80) Adjusted gross margin $ 2,500 - $ 2,560 Operations and maintenance1 $ 945 - $ 965 Adjustments: Renewable energy and demand side management programs (80) - (80) Adjusted operations and maintenance $ 865 - $ 885 1 Line items from Consolidated Statements of Income. First Quarter 2019 23

CONSOLIDATED STATISTICS 3 Months Ended March 31, 2019 2018 Incr (Decr) ELECTRIC OPERATING REVENUES (Dollars in Millions) Retail Residential $ 352 $ 317 35 Business 333 343 (11) Total Retail 684 660 24 Sales for Resale (Wholesale) 36 12 24 Transmission for Others 15 15 0 Other Miscellaneous Services 4 4 (1) Total Electric Operating Revenues $ 740 $ 691 48 ELECTRIC SALES (GWH) Retail Residential 2,577 2,347 230 Business 3,200 3,148 52 Total Retail 5,778 5,496 282 Sales for Resale (Wholesale) 846 291 556 Total Electric Sales 6,624 5,786 838 RETAIL SALES (GWH) - WEATHER NORMALIZED Residential 2,494 2,453 41 Business 3,198 3,185 13 Total Retail Sales 5,692 5,638 54 Retail sales (GWH) (% over prior year) 1.0% (0.4)% 1.4% AVERAGE ELECTRIC CUSTOMERS Retail Customers Residential 1,120,307 1,097,992 22,315 Business 134,943 134,247 696 Total Retail 1,255,250 1,232,239 23,011 Wholesale Customers 53 29 23 Total Customers 1,255,303 1,232,269 23,034 Total Customer Growth (% over prior year) 1.9% 1.7% 0.2% RETAIL USAGE - WEATHER NORMALIZED (KWh/Average Customer) Residential 2,226 2,234 (8) Business 23,696 23,721 (25) First Quarter 2019 24 Numbers may not foot due to rounding.

CONSOLIDATED STATISTICS 3 Months Ended March 31, 2019 2018 Incr (Decr) ENERGY SOURCES (GWH) Generation Production Nuclear 2,512 2,479 33 Coal 1,773 1,099 674 Gas, Oil and Other 1,848 1,646 202 Renewables 118 131 (13) Total Generation Production 6,252 5,355 897 Purchased Power - Conventional 224 250 (26) Resales 24 23 1 Renewables 460 438 22 Total Purchased Power 708 711 (3) Total Energy Sources 6,960 6,066 894 POWER PLANT PERFORMANCE Capacity Factors - Owned Nuclear 101% 100% 1% Coal 49% 30% 19% Gas, Oil and Other 27% 24% 3% Solar 24% 27% (3)% System Average 46% 40% 6% 3 Months Ended March 31, 2019 2018 Incr (Decr) WEATHER INDICATORS - RESIDENTIAL Actual Cooling Degree-Days - - - Heating Degree-Days 605 323 282 Average Humidity - - - 10-Year Averages (2007 - 2016) Cooling Degree-Days - - - Heating Degree-Days 441 441 Average Humidity 0% 0% - First Quarter 2019 25 Numbers may not foot due to rounding.