Exhibit 99.1
| EEI Financial Conference November 12-13, 2012 |
| Contact Information & Safe Harbor Investor Relations Contact Information Chris Norman, Manager Daniel Mark, Senior Analyst (520) 884.3649 (520) 884.3621 cnorman@uns.com dmark@uns.com Investor Information http://ir.uns.com Safe Harbor and Non-GAAP Measures This document contains forward-looking information that involves risks and uncertainties, that include, but are not limited to: state and federal regulatory and legislative decisions and actions; regional economic and market conditions which could affect customer growth and energy usage; weather variations affecting energy usage; the cost of debt and equity capital and access to capital markets; the performance of the stock market and changing interest rate environment, which affect the value of the company's pension and other postretirement benefit plan assets and the related contribution requirements and expense; unexpected increases in O&M expense; resolution of pending litigation matters; changes in accounting standards; changes in critical accounting estimates; the ongoing restructuring of the electric industry; changes to long-term contracts; the cost of fuel and power supplies; performance of TEP's generating plants; and other factors listed in UNS Energy's Form 10-K and 10-Q filings with the Securities and Exchange Commission. The preceding factors may cause future results to differ materially from historical results or from outcomes currently expected by UNS Energy. The Company's press releases and other communications may include certain non-Generally Accepted Accounting Principles (GAAP) financial measures. A "non-GAAP financial measure" is defined as a numerical measure of a company's financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP in the Company's financial statements. Non-GAAP financial measures utilized by the Company include presentations of revenues, operating expenses, operating income and earnings (loss) per share. The Company uses these non-GAAP measures to evaluate the operations of the Company. Certain non-GAAP financial measures utilized by the Company exclude: the impact of non-recurring items; the effect of accounting changes or adjustments; expenses that are reimbursed by third parties; and other items. The Company's management believes that these non-GAAP financial measures provide useful information to investors by removing the effect of variances in GAAP reported results of operations that are not indicative of fundamental changes in the earnings or cash flow capacity of the Company's operations. Management also believes that the presentation of the non-GAAP financial measures is largely consistent with its past practice, as well as industry practice in general, and will enable investors and analysts to compare current non-GAAP measures with non-GAAP measures with respect to prior periods. 1 |
| Long-Term Value Proposition Fully Regulated Utility With Long-Term Growth Drivers Fully Regulated Utility With Long-Term Growth Drivers Fully Regulated Utility With Long-Term Growth Drivers 2 |
| TEP's 2012 Rate Filing Key Provisions Key Provisions Key Provisions 3 |
| Arizona Corporation Commission 4 * Term limited ** Re-elected in Nov. 2012 Elected in Nov. 2012; Terms End Jan. 2017 Bob Burns (R) Former state legislator and president of the state senate Susan Bitter Smith (R) Former Scottsdale city council member and vice mayor Terms End Jan. 2015 Terms End Jan. 2013 Term Ends Jan. 2017 |
| Attractive dividend yield Payout target provides flexibility 13 consecutive years of dividend increases 2000 2012 *Yield and payout for regulated utilities from EEI Q3 2012 Financial Update Note: UNS payout ratio based on net income associated with mid-point of 2012 earnings guidance and indicated annual dividend of $1.72 Generating Strong, Stable Cash Flow Attractive Dividend Yield and Opportunity for Growth 5 Q1 2012 dividend raised to $0.43 per share. Represents a 2.4% increase from 2011. |
| *Capital expenditure estimate for 2012 from Q3 2012 10-Q Generating Strong, Stable Cash Flow 6 |
| Note: Capital expenditure estimates for 2013-2016 are from the 2011 Form 10- K (excludes optional purchase of leased assets in 2015). Estimate for 2012 from Q3 2012 Form 10-Q. Investing in Our Utility Businesses Nearly $2 Billion of Utility Investments Through 2016 7 |
| Strengthening Our Regulatory Foundation Constructive Outcomes and Progress in Recent Cases 8 |
| TEP 2012 Integrated Resource Plan Filed in April 2012 Filed in April 2012 Filed in April 2012 9 |
| San Juan Generating Station San Juan Generating Station 10 |
| Arizona's Economy In Recovery Phase Long-Term Growth, Diverse Customers and Competitive Retail Rates 11 Source: University of Arizona Business and Economic Research Center |
| TEP RATE CASE 12 |
| TEP's 2012 Rate Filing 13 Topic Summary Increase in non-fuel revenue requirement vs. adjusted test year revenues $127.8 million or 15.3% Adjusted 2011 Test Year Revenues $837 million Proposed Retail Revenues $965 million Avg. residential bill impact ~$11 / month Original Cost Rate Base (OCRB) $1.52 billion Pro forma capital structure 46% Equity / 54% Debt Return on Equity 10.75% Cost of debt 5.18% Weighted average cost of capital 7.74% Fair value rate base $2.3 billion Return on fair value rate base 5.68% Lost fixed cost recovery mechanism Recovers lost fixed cost revenues resulting from energy efficiency and distributed generation Environmental compliance recovery mechanism Return on and of capital for qualified investments, as well as recovery of related expenses |
| TEP Rate Case Procedural Schedule 14 14 |
| TEP Proposed Non-Fuel Revenue Increase 15 Sensitivities Change Pre-Tax Revenue Requirement Impact ROE 25 bps $3 million Equity ratio 100 bps $3 million Rate base $10 million $1.5 million Fair value increment 50 bps $6 million |
| TEP Proposed Rate Base 16 ($ millions) 12/31/2011 Total Unadjusted Original Cost Rate Base (OCRB) $2,070 Post test-year adjustments (1) 40 Regulatory assets (2) 11 FERC jurisdictional generation assets (72) FERC jurisdictional transmission assets (368) Accumulated deferred income taxes, working capital and other adjustments (162) ACC Jurisdictional OCRB $1,519 (1) Includes $17 million of renewable generation and $23 million of other plant (1) Includes $17 million of renewable generation and $23 million of other plant (2) Nogales transmission line to be amortized over a 3-year period (2) Nogales transmission line to be amortized over a 3-year period |
| TEP Proposed Capital Structure and Fair Value Rate Base 17 Capital ($ Million) Percent Cost Rate Weighted Cost Rate (FVROR) Long-Term Debt $820 35.97% 5.18% 1.86% Common Equity $699 30.65% 10.75% 3.29% Fair Value Increment (1) $761 33.38% 1.56% 0.52% Total FVRB (2) $2,280 100.00% 5.68% Fair Value Increment is the difference between Fair Value Rate Base ("FVRB") and Original Cost Rate Base ("OCRB"). FVRB is determined by averaging OCRB of $1,519 million and Replacement Cost New Depreciated ("RCND") of $3,041 million. Fair Value Rate Base and Rate of Return % of Pro Forma Capital Structure Component Cost Weighted Average Cost Common Equity 46.00% 10.75% 4.94% Long-Term Debt 54.00% 5.18% 2.80% Total 100.00% 7.74% Pro Forma Capital Structure |
| Proposed Recovery Mechanisms Designed to recover non-fuel costs that would otherwise go unrecovered due to lost kWh sales attributed to energy efficiency or distributed generation Not a full decoupling mechanism Does not include lost fixed cost revenues attributable to weather or economic conditions Per kWh charge updated annually Provision for residential customers to choose a fixed charge option 2% annual cap based on total revenues 18 Lost Fixed Cost Recovery Mechanism (LFCR) Designed to recover compliance costs associated with environmental regulations Costs to be recovered through ECA: Return on Qualified Investments based on TEP's authorized Weighted Average Cost of Capital (CWIP and in- service between rate cases) Recovery of additional costs associated with plant-in-service include depreciation expense, operations & maintenance expenses and taxes Environmental Compliance Adjustor (ECA) Solar Build Out Plan $30 million annual investments in company- owned solar projects from 2014 through 2017 Revenue requirement associated with these investments recovered through the REST surcharge until such plant is included in rate base |
| Energy Efficiency Resource Plan 3-year pilot program ACC approval of annual investment amounts and DSM surcharge for 2014, 2015 and 2016 Better aligns costs with benefits Moderate, stair-stepped year-over-year increases Provides more certainty to customers, contractors, and the utility TEP to invest in cost-effective energy efficiency programs Cost recovery, including a return, through existing DSM surcharge 4-year amortization period Return on investment based on Weighted Average Cost of Capital with a 200 basis point increase in ROE component Establishes definitions and methodology for calculating cost-effectiveness 19 |
| Rate Design Proposals Rates designed to: More accurately reflect cost of service Provide greater opportunity for TEP to recover its authorized revenue requirement Shift all fuel and purchased power costs to PPFAC (no fuel or purchased power costs included in base rates) Streamline customer rate options Provide customers with more accurate price signals 20 |
| FINANCIAL UPDATE AND OUTLOOK 21 |
| 3rd Quarter 2012 Highlights Current 2012 earnings guidance range of $2.15 - $2.30 per UNS diluted share Maintaining 2012 UNS Base O&M* estimate of $270 million Q3 results largely in line with forecast Q3 results negatively affected by a decrease in cooling-degree days and an increase in depreciation and amortization expense related to additions to plant-in- service Q3 2012 included after-tax loss of $0.03 per diluted share related to an unplanned outage at Springerville Unit 3 Q3 2011 includes after-tax gain of $0.11 per diluted share related to the settlement of a transmission dispute between TEP and El Paso 22 3Q 2011 Diluted EPS 3Q 2012 Diluted EPS TEP Base O&M* TEP Retail Margin* TEP LT Wholesale Margin* El Paso Settlement (2011) Springerville Unit 3 Outage TEP Depreciation & Amortization Expense UNS Q3 2012 Diluted EPS vs. Q3 2011 *Please refer to the end of this presentation for a reconciliation of non-GAAP measures. |
| Annual Earnings Sensitivities 23 Earnings Sensitivities Pre-Tax (millions) After-Tax (millions) Per Diluted Share 1% Change in Total Retail Sales (based on average margin rate across all customer classes) $6.0 $3.6 +/- $0.09 1% Change in UNS 2012E Consolidated Base O&M ($270 million) $2.7 $1.6 +/- $0.04 $5 / MWh Change in On-Peak Wholesale Power Prices (SRP Contract) $2.5 $1.5 +/- $0.04 1% Increase in TEP's Un-hedged Long-Term Variable Rate Debt ($215 million outstanding at 9/30/12 of which $50 million is hedged) $1.7 $1.0 ($0.02) |
| TEP Long-Term Wholesale Sales Salt River Project (SRP) Contract modified in Dec. 2011 SRP required to take 500,000 MWh annually (on-peak) Priced at a discount to on-peak Palo Verde prices Contract expires May 2016 Navajo Tribal Utility Authority (NTUA) No demand charge; energy priced in mid - $50 per MWh range No minimum purchase requirement Contract modifications effective 2010 Energy charge for 50% of sales (June-Sept) based on Palo Verde Index (~30 GWhs) Contract expires December 2015 24 * L-T Wholesale Margin Revenue is a non-GAAP measures. Please refer to the end of this presentation for a reconciliation of non-GAAP measures. |
| Capital Structure Improvements 25 UNS Consolidated Capital Structure Recent Financing Activity Conversion of UNS $150 million convertible notes TEP long-term debt issuances $150 million of unsecured notes issued in Sept. 2012 to repay revolver borrowings and for general corporate purposes $193 million of unsecured tax-exempt bonds issued in first half of 2012 to redeem higher coupon bonds $250 million unsecured notes issued in Nov. 2011 to repurchase variable rate bonds and higher coupon fixed rate bonds Future capital market activity depends on various factors Improvement resulting from: Amortization of capital lease obligations Conversion of $150 million convertible notes to equity Retained earnings |
| TEP Capital Structure TEP Capital Structure - GAAP 12/31/11 TEP Capital Structure - ACC Method 12/31/11 26 |
| Financial Outlook TEP rate case filed in July 2012 with new rates expected to be effective within 13 months from filing date 2014 first full year of new TEP rates UNS Electric rate case expected to be filed in December 2012 Continued O&M cost containment Refinancing opportunities Potential increase in TEP's mining load Up to 100 MW in the next 3-5 years from expansion of existing mining operations and re-opening of dormant mines At full production, approximately 90 MW from the proposed new Rosemont Copper mine Optional purchase of Springerville Unit 1 in Jan. 2015 Potential environmental upgrades to coal-fired generating facilities San Juan Units 1 and 2 27 |
| Credit Ratings Adequate lines of credit TEP - $200 million; UES - $100 million; UNS - $ 125 million; mature in Nov. 2016 Credit ratings Moody's placed UNS and TEP on positive outlook in May 2012 Fitch upgraded TEP by one notch in September 2012 TEP Fitch Secured BBB+ Unsecured BBB Issuer BBB- Outlook S&P BBB+ BBB- BB+ Stable Moody's Baa1 Baa3 Baa3 Positive Stable UNS Energy Moody's Ba1 Positive Secured Credit Facility Outlook UNS Electric Moody's Baa2 Stable Sr. Unsecured Notes (guaranteed) Outlook UNS Gas Moody's Baa2 Stable Sr. Unsecured Notes (guaranteed) Outlook 28 |
| As of 9/30/2012 Debt Issue Interest Rate Balance (millions) Maturity First Call Date at Par Security As of 9/30/2012 Debt Issue Interest Rate Balance (millions) Date First Call Date at Par Security TEP Fixed-Rate Bonds 2012 Notes 3.85% $150.0 Mar-23 Dec-22 Unsecured 2011 Notes 5.15% 250.0 Nov-21 Aug-21 2012 Apache A 4.50% 177.0 Mar-30 Mar-22 2012 Pima A 4.50% 16.5 Jun-30 Jun-22 2010 Pima A 5.25% 100.0 Oct-40 Oct-20 2008 Pima A 6.38% 90.7 Sep-29 Mar-13 2008 Pima B 5.75% 130.0 Sep-29 Jan-15 2009 Pima A 4.95% 80.4 Oct-20 N/C 2009 Coconino A 5.13% 14.7 Oct-32 Oct-19 Subtotal $1,009.3 Variable Rate Bonds 2010 Coconino A 0.24% $36.7 Oct-32 Anytime Mortgage Bonds 1982 Pima A - Irvington 0.19% 38.7 Oct-22 1982 Pima A 0.17% 39.9 Dec-22 1983 Apache A 0.17% 100.0 Dec-18 Subtotal $215.3 TEP TOTAL $1,224.6 UES UNS Gas Unsecured Notes 5.39% $50.0 Aug-26 MW + 50 Unsecured UNS Gas Unsecured Notes 6.23% 50.0 Aug-15 MW + 50 UNS Electric Unsecured Notes 6.50% 50.0 Aug-15 MW + 50 UNS Electric Unsecured Notes 7.10% 50.0 Aug-23 MW + 50 UNS Electric Term-Loan 2.22% 30.0 Aug-15 Anytime UES Total $230.0 UNS Stand-Alone Revolving Credit Facility (as of 10/22) LIBOR + 1.75% $31.0 Nov-16 Anytime Secured Total UNS Consolidated $1,485.6 Long-Term Debt Summary 29 |
| SUPPLEMENTAL INFORMATION 30 |
| Regulated Electric and Gas Utility Businesses Largest Subsidiary of UNS Approx. 80% of Revenues and Assets Vertically Integrated Electric Utility 405,000 Electric Customers Gas Distribution Business Vertically Integrated Electric Utility 148,000 Gas Customers 91,000 Electric Customers NYSE: UNS 2011 Operating Revenues: $1.5B Market Cap: $1.7B 31 |
| Utility Service Areas Navajo Sundt Moenkopi Peacock Marketplace Kayenta Tucson Generating Station Coal Mine Interconnection With Other Utility Substation Solar Station TEP 405,000 customers UNS Gas 148,000 customers UNS Gas & Electric UNS Electric 91,000 customers High Voltage Transmission Lines San Juan Ship Rock Four Corners San Juan Mine Navajo McKinley McKinley Mine Coronado Springerville Luna Hidalgo Greenlee South Vail Valencia Nogales Davis Mead Black Mountain Kingman Kingman Black Mountain Griffith Griffith N. Havasu Lake Havasu City Parker Parker Saguaro West Wing Liberty Palo Verde Phoenix Pinal West Cholla Flagstaff Lee Ranch Yavapai Prescott MEXICO NEVADA UTAH COLORADO CALIFORNIA NEW MEXICO Lake Havasu City Pinnacle Peak 32 Service Areas / Customers |
| TEP - Retail Customers TEP customer base continues to grow at a modest pace Long-term outlook positive with expected customer growth rate to reach 1% by 2014 Retail Customer Growth Possible addition of Rosemont Copper Mine in 2015 Support from local business organizations; opposition from local government and environmental groups Requires a U.S. Forest Service Record of Decision 33 |
| TEP's Energy Resources Provide Optionality Leased and dual fuel plants provide optionality Springerville Unit 1 lease (expires Jan. 2015) contains fair market value purchase option No near-term new base load generation requirements Substation and transmission line additions are expanding access to the Palo Verde wholesale power market Current base load resources and access to Palo Verde hub should be adequate to serve potential increase in mining load over the next 3 to 5 years 34 |
| Springerville Leases Springerville Facility Expiration Purchase / Renewal Option TEP Equity Interest Unit 1 January 2015 Fair market value purchase or renewal Fair market value appraisal of $159 million for 86% of the equity interest TEP must provide notice of intent to purchase by Sept. 2013 14% Coal Handling Facilities April 2015 Fixed-price purchase or renewal Fixed-price purchase option (TEP's share would be approximately $73 million) 13% Common Facilities 2017 and 2021 Fixed-price purchase or renewal Fixed-price purchase option of $38 million in 2017 and $68 million in 2021 (TEP's share would be approximately $76 million in total) 0% 35 |
| Springerville Unit 1 Lease 36 Note: Springerville Unit 1 scheduled cash lease payments exclude purchase option on Jan 1, 2015 of $159 million. Actual lease and non-fuel cash payments Provision from 2008 Settlement Agreement III. Ratemaking treatment of generation assets 3.2 Recovery of SGS Unit 1 non-fuel costs shall reflect a cost of $25.67 per KW per month which approximates the levelized cost of SGS Unit 1 through the remainder of the primary lease term for this generating facility. In addition, SGS Unit 1 leasehold improvements shall be included in TEP's original cost rate base at net book value as of December 31, 2006. |
| TEP Forecasted Capital Investments 37 Total $287 $346 $379 $331 $418 Note: Capital expenditure estimates for 2013-2016 are from the 2011 Form 10-K (excludes optional purchase of leased assets in 2015). Estimate for 2012 from Q3 2012 Form 10-Q. |
| TEP Forecasted Capital Investments 38 $Millions Base Capital Expenditures Renewable Investments Recovered through REST Environmental Expenditures San Juan SCRs Proposed Recovery Through ECA Note: Capital expenditure estimates for 2013-2016 are from the 2011 Form 10-K (excludes optional purchase of leased assets in 2015). Estimate for 2012 from Q3 2012 Form 10-Q. |
| TEP Potential Rate Base Growth 39 12/31/15E based on current capital investment forecast and could change depending whether TEP exercises the purchase option on Springerville Unit 1, the outcome of pending environmental upgrades at San Juan, and various other factors. Non-fuel revenue requirement for each $100 million of incremental rate base growth is approximately $15 million Approved in 2008 Settlement Agreement Proposed in 2012 Rate Application |
| Strong Coal Plant Operating Performance Average Equivalent Availability Factor Baghouse - Low NOx Existing Environmental Equipment Operator TEP's Share (MW) Coal Delivery In Service Dates TEP's Share (%) TEP 156 MW rail 1967 100% TEP 804 MW rail Unit 1 - 1985 Unit 2 - 1990 100% Arizona Public Service 110 MW mine mouth Unit 4 - 1969 Unit 5 - 1970 7% Salt River Project 168 MW mine mouth Unit 1 - 1974 Unit 2 - 1975 Unit 3 - 1976 7.5% Public Service of New Mexico 340 MW mine mouth Unit 1 - 1976 Unit 2 - 1973 50% Coal Supplier Contract Term Peabody 2020 BHP Billiton 2016 Peabody 2019 San Juan Coal 2017 Peabody 2012 Annual Expected Coal Usage 350 k tons 3.2 mil. tons 400k tons 500k tons 1.3 mil. tons Baghouse Scrubbers Low NOx Baghouse Scrubbers - Precipitators Scrubbers Low NOx Baghouse Scrubbers Low NOx Mercury removal Sundt Unit 4 coal/gas Navajo Units 1,2&3 coal Industry Avg. coal Four Corners Units 4&5 coal San Juan Units 1&2 coal Springerville Units 1&2 coal 93% 87% 93.8% 88.7% 80.3% 85.9% 79.0% 85.0% 07 08 09 10 11 40 07 08 09 10 11 07 08 09 10 11 07 08 09 10 11 07 08 09 10 11 |
| TEP Environmental Overview Coal Plant TEP's Anticipated Environmental Capital Costs for 2011 - 2018 Pending Regulations Upgrades Springerville Units 1 & 2 $5M MATs (2015) Mercury controls San Juan Units 1 & 2 $180M-$200M Regional Haze / BART (2016) SCR Navajo Units 1 - 3 $86M MATs (2015), Regional Haze / BART (2017) Mercury controls SCR, Baghouses Four Corners Units 4 & 5 $36M MATs (2015) Regional Haze / BART (2018) Mercury controls SCR 41 |
| TEP Generation Portfolio Fuel/ Plant Fuel/ Plant Unit No. Location Date In Service Operator TEP's Share % TEP Share Net Capacity MW Coal Coal Springerville Station 1 Springerville, AZ 1985 TEP 100 401 Springerville Station 2 Springerville, AZ 1990 TEP 100 403 San Juan Station 1 Farmington, NM 1976 PNM 50 170 San Juan Station 2 Farmington, NM 1973 PNM 50 170 Navajo Station 1 Page, AZ 1974 SRP 7.5 56 Navajo Station 2 Page, AZ 1975 SRP 7.5 56 Navajo Station 3 Page, AZ 1976 SRP 7.5 56 Four Corners Station 4 Farmington, NM 1969 APS 7 55 Four Corners Station 5 Farmington, NM 1970 APS 7 55 Gas Gas Luna Energy Facility 1 Deming, NM 2006 PNM 33.3 185 North Loop Tucson, AZ 2001 TEP 100 95 Gas/Oil Gas/Oil Sundt Station 1 Tucson, AZ 1958 TEP 100 81 Sundt Station 2 Tucson, AZ 1960 TEP 100 81 Sundt Station 3 Tucson, AZ 1962 TEP 100 104 Sundt ICTs Tucson, AZ 1972 TEP 100 50 DeMoss Petrie Tucson, AZ 1972 TEP 100 75 Coal/Gas Coal/Gas Sundt Station 4 Tucson, AZ 1967 TEP 100 156 Springerville Solar Station Springerville Solar Station Springerville, AZ 2002 TEP 100 6 Community Solar Projects Community Solar Projects Tucson, AZ 2010 TEP 100 7 Total 2,262 42 |
| Investments in Renewable Energy Arizona Renewable Energy Standard and Tariff 15% of all retail energy needs from renewable resources by 2025 Cost recovery, including ROI, through RES surcharge on owned resources 43 |
| Resource/ Counterparty Resource/ Counterparty Technology Location Operator Completion Date Term (Years) Purchase Option Capacity MW Solar Solar Amonix Concentrating PV Tucson, AZ Amonix Mar 2011 20 On or after yr. 6 at FMV 2 Swan Solar Concentrating PV Tucson, AZ Amonix Oct 2012 20 12 NRG Solar Fixed PV Tucson, AZ NRG Solar Oct 2012 20 34 AstroSol Fixed PV Tucson, AZ Astronergy Oct 2012 20 6 Emcore Solar Concentrating PV Tucson, AZ Emcore Feb 2012 20 2 Solon SAT PV Kingman, AZ Solon Nov 2012 20 10 FRV Tucson Solar SAT PV Tucson, AZ Renewable Ventures Nov 2012 20 25 FSP Solar One SAT PV Tucson, AZ Foresight Solar April 2013 20 5 FSP Solar Two SAT PV Tucson, AZ Foresight Solar Jan 2013 20 14 Avalon Solar Fixed PV Marana, AZ Avalon June 2013 20 35 Wind Wind Western Wind Energy US Corp Wind Kingman, AZ Western Wind Sept 2011 20 None 11 Macho Springs Wind Deming, NM Element Power Sept 2011 20 None 50 Landfill Gas Landfill Gas Sexton Energy Landfill Gas Tucson, AZ Sexton Energy Dec 2013 15 None 2.2 Total 195.2 TEP & UNS Electric Renewable Contracts 44 |
| Fuel/ Plant Fuel/ Plant Technology Status Completion Date Net Capacity MW Solar Solar Springerville Solar Station Fixed PV Complete 2002 4.6 Springerville Solar Expansion Fixed PV Complete 2010 1.8 Univ. of Arizona Tech Park SAT PV Complete 2010 1.6 Univ. of Arizona Tech Park II Fixed PV Complete 2011 5 Black Mountain Solar Facility SAT PV Complete 2011 1.2 DM Air Corridor (Pima County) Fixed PV Scheduled 2012 5 Sundt Steam Augmentation CSP Scheduled 2013 5 Tohono O'odham Project Fixed PV Scheduled 2013 9 Rio Rico Project Fixed PV Scheduled 2013 4.5 Tohono O'odham Project Fixed PV/LCPV Scheduled 2013 4.5 Total 42.2 TEP & UNS Electric Renewable Projects Owned / In Development 45 |
| UniSource Energy Services UNS Gas T&D retail gas business 148,000 retail customers 2011 retail sales - 114 million therms Rate Case Activity 2012 Rate Order $2.7 million base rate increase Lost fixed cost recovery mechanism 9.75% ROE UNS Electric Vertically integrated electric utility 91,000 retail customers 2011 retail sales - 1,853 GWh Rate Case Activity Notice of Intent to File sent on October 31, 2012 Base rate increase of $7.4 million effective October 2010 Black Mountain Generating Station transfer completed 7/1/11 Investments of $5 million annually in company-owned solar projects from 2012-2014 46 |
| RECONCILIATION OF NON-GAAP MEASURES 47 |
| Reconciliation of Non-GAAP Measures Q3 and YTD September 30 Base O&M 48 Base O&M, a non-GAAP financial measure, should not be considered as an alternative to Other O&M, which is determined in accordance with GAAP. We believe Base O&M provides useful information to investors because it represents the fundamental level of operating and maintenance expense related to our core utility business. Base O&M excludes expenses that are directly offset by revenues collected from customers and other third parties. UNS Energy 3rd Quarter 3rd Quarter YTD September 30, YTD September 30, O&M Components 2012 2011 2012 2011 -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- UNS Energy Base O&M (Non-GAAP) $61.0 $62.6 $198.2 $199.0 Reimbursed O&M Related to Springerville Units 3 and 4 26.0 16.2 52.6 48.5 O&M Related to Customer-funded Renewable Energy and DSM Programs 11.3 12.0 32.8 34.4 UNS Energy O&M (GAAP) $98.3 $90.8 $283.6 $281.9 TEP 3rd Quarter 3rd Quarter YTD September 30, YTD September 30, O&M Components 2012 2011 2012 2011 -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- TEP Base O&M (Non-GAAP) $53.5 $54.7 $173.5 $173.6 O&M Included in Other Expense (1.3) (1.4) (3.4) (5.2) Reimbursed O&M Related to Springerville Units 3 and 4 26.0 16.2 52.6 48.5 O&M Related to Customer-funded Renewable Energy and DSM Programs 8.7 10.3 25.4 29.5 TEP O&M (GAAP) $86.9 $79.8 $248.1 $246.4 |
| Reconciliation of Non-GAAP Measures 2009 - 2011 Base O&M 49 Base O&M, a non-GAAP financial measure, should not be considered as an alternative to Other O&M, which is determined in accordance with GAAP. We believe Base O&M provides useful information to investors because it represents the fundamental level of operating and maintenance expense related to our core utility business. Base O&M excludes expenses that are directly offset by revenues collected from customers and other third parties. UNS Energy O&M Components 2011 2010 2009 -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- UNS Energy Base O&M (Non-GAAP) $270 $265 $270 Reimbursed O&M Related to Springerville Units 3 and 4 63 65 41 O&M Related to Customer-funded Renewable Energy and DSM Programs 46 40 23 UNS Energy O&M (GAAP) $379 $370 $334 TEP O&M Components 2011 2010 2009 -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- TEP Base O&M (Non-GAAP) $237 $228 $231 O&M Included in Other Expense (8) (7) (7) Reimbursed O&M Related to Springerville Units 3 and 4 63 65 41 O&M Related to Customer-funded Renewable Energy and DSM Programs 39 31 18 TEP O&M (GAAP) $331 $317 $283 |
| Reconciliation of Non-GAAP Measures Q3 and YTD September 30 TEP Retail Margin Revenues 50 Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Net Electric Retail Sales, which is determined in accordance with GAAP. Retail Margin Revenues excludes: (i) revenues collected from retail customers that are directly offset by expenses recorded in other line items; and (ii) revenues collected from third parties that are unrelated to kWh sales to retail customers. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the operating expenses of our core utility business. Three Months Ended September 30, Three Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, 2012 2011 2012 2011 RETAIL REVENUES - $ MILLIONS Margin Revenues (Non-GAAP): Residential $88.8 $94.3 $201.5 $202.6 Commercial 49.3 50.0 124.2 123.5 Industrial 27.3 28.7 70.8 73.2 Mining 8.6 8.3 23.1 23.9 Other 3.4 3.4 9.3 9.3 Total $177.4 $184.7 $428.9 $432.5 DSM / REST 10.5 12.0 31.9 36.1 Fuel and Purchased Power Revenues: Recovered from Customers 115.1 112.2 256.2 245.7 Total Retail Revenues (GAAP) $303.0 $308.9 $717.0 $714.3 |
| Reconciliation of Non-GAAP Measures 2009-2011 TEP Retail Margin Revenues 51 Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Net Electric Retail Sales, which is determined in accordance with GAAP. Retail Margin Revenues excludes: (i) revenues collected from retail customers that are directly offset by expenses recorded in other line items; and (ii) revenues collected from third parties that are unrelated to kWh sales to retail customers. We believe the change in Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Retail Margin Revenues represents the portion of retail operating revenues available to cover the operating expenses of our core utility business. 2011 2010 2009 -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- Retail Margin Revenues: Residential $ 252 $252 $ 254 Commercial 160 159 160 Industrial 95 97 100 Mining 32 31 30 Public Authorities 12 12 12 Total Retail Margin Revenues (Non-GAAP)** $ 551 $551 $ 556 Fuel Purchased Power Recovered from Customers 307 279 287 REST / DSM 46 38 25 Total Retail Revenues (GAAP) $ 904 $868 $ 868 |
| Reconciliation of Non-GAAP Measures Q3 and YTD September 30 TEP Long-Term Wholesale Margin Revenues 52 Long-Term Wholesale Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Electric Wholesale Sales, which is determined in accordance with GAAP. We believe the change in Long-Term Wholesale Margin Revenues between periods provides useful information to investors because it demonstrates the underlying profitability of TEP's long-term wholesale sales contracts. Long-Term Wholesale Margin Revenues represents the portion of long-term wholesale revenues available to cover the operating expenses of our core utility business. Three Months Ended September 30, Three Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, 2012 2011 2012 2011 -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- Long-Term Wholesale Margin Revenues (Non-GAAP) 1.1 0.6 3.0 11.7 Fuel and Purchased Power Expense Allocated to Long-Term Wholesale Revenues 5.6 8.3 15.3 21.1 Long-Term Wholesale Revenues $6.7 $8.9 $18.3 $32.8 Wholesale Transmission Revenues 3.9 4.0 11.6 12.3 Short-term Wholesale Revenues 14.8 16.7 47.6 51.5 Electric Wholesale Sales (GAAP) 25.4 29.6 77.5 96.6 |
| Reconciliation of Non-GAAP Measures 2009-2011 TEP Long-Term Wholesale Margin Revenues 53 Long-Term Wholesale Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Electric Wholesale Sales, which is determined in accordance with GAAP. We believe the change in Long-Term Wholesale Margin Revenues between periods provides useful information to investors because it demonstrates the underlying profitability of TEP's long-term wholesale sales contracts. Long-Term Wholesale Margin Revenues represents the portion of long-term wholesale revenues available to cover the operating expenses of our core utility business. 2011 2010 2009 Long-Term Wholesale Revenues: -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- Long-Term Wholesale Margin Revenues (Non-GAAP)* $ 13 $ 28 $ 25 Fuel and Purchased Power Expense Allocated to Long- Term Wholesale Revenues 28 28 23 Total Long-Term Wholesale Revenues $ 41 $ 56 $ 48 Wholesale Transmission Revenues 16 21 19 Short-Term Wholesale Revenues 73 64 86 Electric Wholesale Sales (GAAP) $130 $141 $153 |