Exhibit 99.1
| March 20, 2013 West Coast Utility Conference |
| UNS Energy: Who We Are Fully Regulated Electric and Gas Utilities NYSE UNS Market cap $1.9 billion Customers ^500,000 electric ^150,000 gas Territory > 55,000 sq. miles Generation Capacity 2,420 MW Coal - 1,422 MW Gas - 823 MW Dual fuel - 156 MW Solar - 19 MW 2012 Peak Demand 2,727 MW Utility subsidiaries 1 Arizona |
| Building Shareholder Value Building Shareholder Value 2 |
| 2012 Achievements 2012 Achievements 3 |
| TEP Rate Freeze Period Through 2011 4 4 July 2012 TEP Rate Filing $128 million non-fuel base rate increase Original cost rate base of $1.5 billion |
| Constructive Regulatory Environment Proposed TEP Settlement Agreement 5 Proposed Settlement Terms $76 million non-fuel base rate increase Original cost rate base of $1.5 billion 10% ROE, 0.68% return on fair value increment of rate base Capital structure of 43.5% equity and 57.5% debt New cost recovery mechanisms and fuel clause modifications No stay out provision Retail rates will remain attractive for economic development |
| Constructive Regulatory Environment Mitigating Regulatory Lag TEP UNS Electric UNS Gas 100% pass-through of fuel and purchased energy costs Renewable Energy Standard and Tariff provides return on and of utility-owned solar between rate cases N/A Demand-side management surcharge provides funding to meet ACC's energy efficiency rules Partial decoupling for energy efficiency and distributed generation between rate cases Pending Approval Pending Approval Environmental compliance adjustor Pending Approval N/A N/A Post test year plant included in rate base Pending Approval N/A Stay-out provision No No No 6 TEP: 11-13 months* UNS Gas: 13 months APS: 11 months SW Gas: 13 months 12-Month Average * Company estimate |
| Constructive Regulatory Environment Arizona Corporation Commission 7 7 Terms End Jan. 2015 Term Ends Jan. 2017 |
| Outlook Long-term growth opportunities Economic recovery Diverse retail customer base Rosemont Mine Rate base investments Dividend growth and credit quality improvement 8 |
| Long-Term Growth Opportunities Economic Recovery 9 9 |
| Long-Term Growth Opportunities Current Rate Base and Capital Investment Forecast 10 As proposed in TEP's pending Settlement Agreement , based on a 12/31/11 test year Assumes purchase of Springerville Unit 1 and Coal Handling leases in 2015 1 Assumes installation of SNCR on San Juan Unit 1 of approximately $25 million. If SCR required, incremental capital expenditures would be ^$175 million Optional purchase of leased assets is not included in TEP's base capital expenditure forecast 2 Note: Capital expenditure forecast from 2012 Form 10-K 1 2 |
| Strong Cash Flows Provide Flexibility Dividend Growth and Balance Sheet Improvement 11 11 2000 2013 14% Compound Annual Growth 14% Compound Annual Growth Moody's Unsecured Ratings 2000 2012 TEP Ba3 Baa3 UNS Gas NR Baa2 UNS Electric NR Baa2 *2013 indicated annual dividend based on Q1 2013 dividend of $0.435 / share Board Dividend Policy Long-Term Payout Ratio of 60%-70% |
| Value Proposition 12 12 |
| TEP PROPOSED SETTLEMENT AGREEMENT 13 |
| TEP's 2013 Proposed Settlement Topic Summary Increase in non-fuel revenue requirement vs. adjusted test year revenues $76 million Avg. residential bill impact Less than $3 / month Original Cost Rate Base (OCRB) $1.5 billion Capital structure 43.5% Equity / 56.5% Debt Return on Equity 10.0% Cost of debt 5.18% Weighted average cost of capital 7.26% Fair value rate base $2.3 billion Return on fair value rate base 5.05% Lost fixed cost recovery mechanism Recovers lost fixed cost revenues resulting from energy efficiency and distributed generation Environmental compliance recovery mechanism Return on and of capital for qualified investments, as well as recovery of related expenses Administrative Law Judge Hearings Completed in March, 2013 Implementation of new rates Parties agreed to use best efforts to put new rates in effect by July 1, 2013 14 |
| TEP Proposed Rate Base ($ millions) 12/31/2011 Total Unadjusted Original Cost Rate Base (OCRB) $2,070 Post test-year adjustments (1) 36 FERC jurisdictional generation assets (72) FERC jurisdictional transmission assets (368) Accumulated deferred income taxes, working capital and other adjustments (159) ACC Jurisdictional OCRB $1,507 (1) Includes $16 million of renewable generation and $21 million of other plant (1) Includes $16 million of renewable generation and $21 million of other plant 15 |
| TEP Proposed Capital Structure and Fair Value Rate Base 16 Capital ($ Million) Percent Cost Rate Weighted Cost Rate (FVROR) Short-Term Debt $8 0.35% 1.42% 0.01% Long-Term Debt $843 37.19% 5.18% 1.93% Common Equity $656 28.90% 10.00% 2.89% Fair Value Increment (1) $761 33.55% 0.68% 0.23% Total FVRB (2) $2,268 100.00% 5.05% 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 $1,507 million and Replacement Cost New Depreciated ("RCND") of $3,029 million. Fair Value Rate Base and Rate of Return Capital Structure % of Total Capital Component Cost Weighted Cost Equity 43.50% 10.00% 4.35% LT Debt 55.97% 5.18% 2.90% ST Debt 0.53% 1.42% 0.01% Total 100.00% 7.26% |
| 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 5-year amortization period Establishes definitions and methodology for calculating cost-effectiveness 17 |
| 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 1% 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 Recovery of additional costs associated with plant-in-service include depreciation expense, operations & maintenance expenses and taxes Annual cap of 0.25% of total revenues Environmental Compliance Adjustor (ECA) Designed to recover fuel and purchased power costs PPFAC modification include recovery of following costs and/or credits: Broker fees; lime costs; sulfur credits; and 100% of proceeds from sale of SO2 allowances One-time credit of $3 million related to previous sulfur credits Deferral of $9.7 million of costs related to 2012 San Juan fire until insurance settlement complete Purchased Power and Fuel Adjustor Clause (PPFAC) |
| Proposed Cost Recovery Mechanisms 19 LFCR ECA Measurement Period January 1 - December 31, 2013 August 1 - December 31, 2013 (calendar year thereafter) TEP filing due date May 15, 2014 March 1, 2014 Surcharge effective date July 1, 2014 (upon ACC approval) May 1, 2014 (unless Commission or ACC Staff objects) Collection Cap 1% of Total Retail Revenues 0.25% of Total Retail Revenues, not to exceed $0.00025 / kWh |
| Rate Design Proposals Rates designed to: More accurately reflect cost of service Provide greater opportunity for TEP to recover its authorized revenue requirement Streamline customer rate options Provide customers with more accurate price signals 20 |
| FINANCIAL UPDATE AND OUTLOOK 21 |
| YTD Dec. 31, 2011 UNS Consolidated Diluted EPS TEP L-T Wholesale Margin UNS Retail Margin UNS D&A El Paso Settlement (2011) Other Springerville Unit 3 Outage UNS Base O&M Nogales Transmission Line Partial Write-off YTD Dec. 31, 2012 UNS Consolidated Diluted EPS 4th Quarter 2012 Highlights 2012 earnings of $2.20 per UNS diluted share within guidance range of $2.15 - $2.30 2012 UNS Base O&M* of $266 million below initial estimate of $270 million Year-over-year retail margins were lower due in part to milder summer weather as well as the effects of the ACC's energy efficiency and distributed generation requirements Long-term wholesale margins lower due primarily to the change in the price of energy sold under the SRP contract Depreciation and amortization expense increased due to higher net plant in services 22 UNS 2012 Diluted EPS vs. 2011 *Please refer to the end of this presentation for a reconciliation of non-GAAP measures. |
| Financial Outlook TEP rate case filed in July 2012 with new rates expected to be effective in July or August of 2013 2014 first full year of new TEP rates UNS Electric rate case filed in December 2012 Continued O&M cost containment Refinancing opportunities Potential increase in TEP's mining load At full production, approximately 90 MW from the proposed new Rosemont Copper mine Optional purchase of Springerville Unit 1 in Jan. 2015 and coal handling facilities in Apr. 2015 Potential environmental upgrades to coal-fired generating facilities San Juan Generating Station 23 |
| 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. |
| 2013 Earnings Sensitivities 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) +/- $0.09 - $0.10 1% Change in UNS 2013E Consolidated Base O&M ($273 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 12/31/12 of which $50 million is hedged) $1.7 $1.0 ($0.02) 25 |
| Capital Structure Improvements 2012-2013 Financing Activity Conversion of UNS $150 million convertible notes completed in first half of 2012 TEP long-term debt issuances $91 million of unsecured tax-exempt bonds issued in March 2013 to redeem higher coupon bonds $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 in 2012 Retained earnings 26 UNS Consolidated Capital Structure |
| TEP Capital Structure TEP Capital Structure - GAAP 12/31/12 TEP Capital Structure - ACC Method 12/31/12 27 $861M $344M $1,223M $861M $1,223M |
| As of 3/14/2013 Interest Rate Balance (millions) Maturity First Call Date at Par Security Debt Issue Interest Rate Balance (millions) Date First Call Date at Par Security TEP Fixed-Rate Bonds 2013 Pima A 4.00% $90.7 Sep-29 Mar-23 Unsecured 2012 Notes 3.85% $150.0 Mar-23 Dec-22 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 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 (rates as of 2/13) 2010 Coconino A 0.18% $36.7 Oct-32 Anytime Mortgage Bonds 1982 Pima A - Irvington 0.11% $38.7 Oct-22 1982 Pima A 0.09% $39.9 Dec-22 1983 Apache A 0.11% $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 2/13) LIBOR + 1.75% $45.0 Nov-16 Anytime Secured Total UNS Consolidated $1,499.6 Long-Term Debt Summary 28 |
| Long-Term Debt Maturities 29 Note: Long-Term Debt Maturities shown above exclude lease purchase options at TEP. Credit Agreements at UNS Energy, TEP and UES expire |
| Cash & Liquidity Revolving credit facilities provide backstop for seasonal effects of utility cash flows Credit facilities expire November 2016 Short-Term Borrowing Rates UNS Holding Company: LIBOR + 1.75% TEP: LIBOR + 1.125% UES: LIBOR + 1.50% 30 (1) Either UNS Gas or UNS Electric may borrow up to a maximum of $70 million; the total combined amount borrowed by both companies cannot exceed $100 million. UNS Short-Term Borrowing Capacity $425 million Ratings Moody's S&P Fitch Secured UNS Hold Co. Ba1 - - TEP Baa1 BBB+ BBB+ Unsecured TEP Baa3 BBB- BBB UNS Gas Baa2 - - UNS Electric Baa2 - - Outlook UNS Hold Co. Positive - - TEP Positive Stable Stable UNS Gas Stable - - UNS Electric Stable - - |
| TEP Forecasted Capital Investments 31 Total $323 $296 $331 $287 $278 Note: Capital expenditure estimates for 2013-2017 are from the 2012 Form 10-K (excludes optional purchase of leased assets). $253 |
| Rate Case Summary 32 Pending 2013 Settlement Agreement 2008 Settlement Agreement UNS Electric Pending 2012 Rate Application UNS Electric 2010 Rate Order UNS Gas 2012 Rate Order Original Cost Rate Base $1.5 billion $1.0 billion $217 million $169 million $183 million Test Year 12/31/11 12/31/06 6/30/12 12/31/2008 12/31/10 Equity / Capitalization 43.50% 42.50% 47.40% 45.76% 50.82% Debt / Capitalization 56.50% 57.50% 52.60% 54.24% 49.18% ROE 10.00% 10.25% 10.50% 9.75% 9.75% Return on Fair Value Increment 0.68% N/A 1.61% 1.33% 1.00% Stay out provision No Yes - No No |
| UniSource Energy Services UNS Gas T&D retail gas business 149,000 retail customers 2012 retail sales - 104 million therms UNS Electric Vertically integrated electric utility 92,000 retail customers 2012 retail sales - 1,756 GWh 33 |
| SUPPLEMENTAL INFORMATION 34 |
| Utility Service Areas 35 Navajo Sundt Moenkopi Peacock Marketplace Kayenta Tucson Generating Station Coal Mine Interconnection With Other Utility Substation Solar Station TEP 406,000 customers UNS Gas 149,000 customers UNS Gas & Electric UNS Electric 92,000 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 Service Areas / Customers |
| TEP Retail Sales and Margin Mix 36 Residential Commercial Industrial Mining Other 2012 Retail Sales of 9,265 GWh Retail Margin Revenues totaled $544 million in 2012* *Retail Margin Revenues is a non-GAAP financial measure. Please refer to the end of this presentation for a reconciliation of non-GAAP measures |
| TEP Generation Capacity and Resource Mix 37 2012 Generation Capacity - 2,267 MW 2012 Resource Mix Coal Natural Gas Dual Fuel Solar Purchased Power |
| Long-Term Growth Opportunities Springerville Leases 38 Springerville Unit 1 Capacity (coal-fired): 401 MW TEP ownership: 14% (remainder leased) Purchase Option: $159 million or $478 / kW Springerville Unit 1 Timeline |
| 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% 39 |
| Springerville Unit 1 Lease Provision from 2013 Proposed TEP Settlement Agreement X. Springerville Unit 1 10.1 TEP shall file a report with the Commission no later than July 31, 2014, addressing the status of the Springerville Generating Station lease agreements and the estimated change in TEP's non-fuel revenue requirement at the conclusion of each primary lease term. 10.2 Based on the information in the above reporting, the Commission, on its own motion or a recommendation of a Signatory in this case, may require TEP to explain why the Commission should not conduct a proceeding to have TEP's rates reduced accordingly. 40 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 |
| San Juan Generating Station 41 41 Alternative Plan Federal Plan |
| TEP Generation Portfolio 42 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 12 Total 2,267 |
| Strong Coal Plant Operating Performance 43 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 - Annual Expected Coal Usage - 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% 93.9% 89.1% 80.6% 89.4% 77.9% 83.5% 08 09 10 11 12 08 09 10 11 12 08 09 10 11 12 08 09 10 11 12 08 09 10 11 12 |
| TEP Environmental Overview 44 Generating Station Estimated Annual O&M Expense ($ millions) Estimated Capital Expenditures ($ millions) Regulation (Compliance Date) Upgrades San Juan Units 1 & 2 $6 $180 - $200 Regional Haze/BART (2016) SCRs(1) Navajo Units 1-3 $3 $86 MATS (2015) Regional Haze/BART (2023) Mercury Controls; SCRs; Baghouses Four Corners Units 4 & 5 $3 $36 MATS (2015) Regional Haze/BART (2018) Mercury Controls; SCRs Springerville Units 1 & 2 $3 $5 MATS (2015) Mercury Controls (1) If SNCR technology is installed on San Juan Unit 1, TEP estimates its share of the cost would be approximately $25 million. |
| Arizona's Renewable Energy and Energy Efficiency Standards Renewable Energy Standard (RES) 15% of retail kWh sales met by renewable resources by 2025 (30% of total requirement must be from distributed generation) TEP and UNS Electric on track to meet the 4% target for 2013 Energy Efficiency (EE) Standards Cumulative energy savings of 22% of retail kWh sales by 2020 3% by 2012, 9.5% by 2015 Pending energy efficiency plans in TEP and UNSE rate cases 45 |
| Renewable Energy Standard Solar Initiatives TEP Named 2012 Investor Owned Utility of the Year by Solar Electric Power Association Innovative community solar programs 18 MW of installed utility-scale solar capacity 23 MW of utility-scale solar capacity in development company-wide 46 |
| 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 NRG Solar Fixed PV Tucson, AZ NRG Solar Dec 2012 20 34 AstroSol Fixed PV Tucson, AZ Duke Energy Dec 2012 20 6 Black Mtn Solar SAT PV Kingman, AZ Duke Energy Dec 2012 20 10 FRV Tucson Solar SAT PV Tucson, AZ SunEdison Dec 2012 20 25 FSP Solar One SAT PV Tucson, AZ E.On Jul2013 20 5 FSP Solar Two SAT PV Tucson, AZ E.On Dec 2012 20 14 Avalon Solar Fixed PV Marana, AZ Avalon Mar 2014 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 Tucson Energy Partners Landfill Gas Tucson, AZ Tucson Energy Partners Aug 1999 18 None 5 Total 197.0 TEP & UNS Electric Renewable Contracts 47 |
| 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 Prairie Fire (Pima County) Fixed PV Complete 2012 5 Sundt Steam Augmentation CSP Scheduled 2013 5 Tohono O'odham Project Fixed PV/LCPV Scheduled 2013 11 Rio Rico Project Fixed PV Scheduled 2013 7.2 Total 42.4 TEP & UNS Electric Renewable Projects 48 Owned / In Development |
| RECONCILIATION OF NON-GAAP MEASURES 49 |
| Reconciliation of Non-GAAP Measures Q4 and YTD December 31, 2012 Base O&M 50 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 4th Quarter 4th Quarter YTD December 31, YTD December 31, 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) $68.0 $72.1 $266.2 $271.1 Reimbursed O&M Related to Springerville Units 3 and 4 19.4 14.4 71.9 62.9 O&M Related to Customer-funded Renewable Energy and DSM Programs 12.7 10.8 45.6 45.2 UNS Energy O&M (GAAP) $100.1 $97.3 $383.7 $379.2 TEP 4th Quarter 4th Quarter YTD December 31, YTD December 31, 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) $64.5 $64.1 $233.7 $237.7 O&M Included in Other Expense (7.3) (2.8) (6.2) (8.0) Reimbursed O&M Related to Springerville Units 3 and 4 19.4 14.4 71.9 62.9 O&M Related to Customer-funded Renewable Energy and DSM Programs 9.9 8.7 35.2 38.2 TEP O&M (GAAP) $86.5 $84.4 $334.6 $330.8 |
| Reconciliation of Non-GAAP Measures 2009 - 2012 Base O&M 51 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 2012 2011 2010 2009 -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- UNS Energy Base O&M (Non-GAAP) $266 $271 $265 $270 Reimbursed O&M Related to Springerville Units 3 and 4 72 63 65 41 O&M Related to Customer-funded Renewable Energy and DSM Programs 46 45 40 23 UNS Energy O&M (GAAP) $384 $379 $370 $334 TEP O&M Components 2012 2011 2010 2009 -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- TEP Base O&M (Non-GAAP) $234 $238 $228 $231 O&M Included in Other Expense (6) (8) (7) (7) Reimbursed O&M Related to Springerville Units 3 and 4 72 63 65 41 O&M Related to Customer-funded Renewable Energy and DSM Programs 35 38 31 18 TEP O&M (GAAP) $335 $331 $317 $283 |
| Reconciliation of Non-GAAP Measures Q4 and YTD December 31, 2012 TEP Retail Margin Revenues 52 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 December 31, Three Months Ended December 31, Year Ended December 31, Year Ended December 31, 2012 2011 2012 2011 RETAIL REVENUES - $ MILLIONS Margin Revenues: Residential $46.8 $49.3 $248.4 $251.9 Commercial 36.1 36.4 160.2 160.0 Industrial 21.6 21.6 92.4 94.8 Mining 7.3 7.7 30.4 31.6 Other 3.3 3.1 12.6 12.3 Total $115.1 $118.1 $544.0 $550.6 DSM / REST 13.5 10.5 45.4 46.6 Fuel and Purchased Power Revenues: Recovered from Customers 70.3 61.1 326.5 306.7 Total Retail Revenues $198.9 $189.7 $915.9 $903.9 |
| Reconciliation of Non-GAAP Measures 2009-2012 TEP Retail Margin Revenues 53 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. 2012 2011 2010 2009 -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- Retail Margin Revenues: Residential $ 248 $ 252 $252 $ 254 Commercial 160 160 159 160 Industrial 92 95 97 100 Mining 30 32 31 30 Public Authorities 13 12 12 12 Total Retail Margin Revenues (Non-GAAP)** $ 544 $ 551 $551 $ 556 Fuel Purchased Power Recovered from Customers 327 307 279 287 REST / DSM 45 46 38 25 Total Retail Revenues (GAAP) $ 916 $ 904 $868 $ 868 |
| Reconciliation of Non-GAAP Measures Q4 and YTD December 31, 2012 TEP Long-Term Wholesale Margin Revenues 54 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 December 31, Three Months Ended December 31, Year Ended December 31, Year Ended December 31, LONG-TERM WHOLESALE MARGIN (Non-GAAP) - $ MILLIONS 2012 2011 2012 2011 Long-Term Wholesale Margin Revenues (Non-GAAP) $1.7 $1.4 $4.7 $13.1 Fuel and Purchased Power Expense Allocated to Long-Term Wholesale Revenues 4.9 6.8 20.2 28.0 Long-Term Wholesale Revenues $6.6 $8.2 $24.9 $41.1 Wholesale Transmission Revenues 4.2 4.1 15.8 16.4 Short-term Wholesale Revenues 22.9 20.9 70.5 72.4 Electric Wholesale Sales (GAAP) $33.7 $33.2 $111.2 $129.9 |
| Reconciliation of Non-GAAP Measures 2009-2012 TEP Long-Term Wholesale Margin Revenues 55 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. 2012 2011 2010 2009 Long-Term Wholesale Revenues: -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- -Millions of Dollars- Long-Term Wholesale Margin Revenues (Non-GAAP)* $ 5 $ 13 $ 28 $ 25 Fuel and Purchased Power Expense Allocated to Long- Term Wholesale Revenues 20 28 28 23 Total Long-Term Wholesale Revenues $ 25 $ 41 $ 56 $ 48 Wholesale Transmission Revenues 16 16 21 19 Short-Term Wholesale Revenues 70 73 64 86 Electric Wholesale Sales (GAAP) $111 $130 $141 $153 |
| 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. 56 |