UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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| ý | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2013March 31, 2014
OR
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| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to .
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Commission File Number | | Registrant; State of Incorporation; Address; and Telephone Number | | IRS Employer Identification Number |
| 1-13739 | | UNS ENERGY CORPORATION (An Arizona Corporation) 88 East Broadway Boulevard Tucson, AZ 85701 (520) 571-4000 | | 86-0786732 |
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| 1-5924 | | TUCSON ELECTRIC POWER COMPANY (An Arizona Corporation) 88 East Broadway Boulevard Tucson, AZ 85701 (520) 571-4000 | | 86-0062700 |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
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| UNS Energy Corporation | Yes x | | No ¨ |
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| Tucson Electric Power Company | Yes x | | No ¨ |
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
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| UNS Energy Corporation | Yes x | | No ¨ |
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| Tucson Electric Power Company | Yes x | | No ¨ |
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
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| UNS Energy Corporation | Large Accelerated Filer | | x | | Accelerated Filer | | ¨ |
| | Non-accelerated Filer | | ¨ | | Smaller Reporting Company | | ¨ |
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| Tucson Electric Power Company | Large Accelerated Filer | | ¨ | | Accelerated Filer | | ¨ |
| | Non-accelerated Filer | | x | | Smaller Reporting Company | | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
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| UNS Energy Corporation | Yes ¨ | | No x | |
| Tucson Electric Power Company | Yes ¨ | | No x | |
As of October 25, 2013April 17, 2014, 41,537,58241,701,718 shares of UNS Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding. As of October 25, 2013April 17, 2014, Tucson Electric Power Company had 32,139,434 shares of common stock outstanding, no par value, all of which were held by UNS Energy Corporation.
This combined Form 10-Q is separately filed by UNS Energy Corporation and Tucson Electric Power Company. Information contained in this document relating to Tucson Electric Power Company is filed by UNS Energy Corporation and separately by Tucson Electric Power Company on its own behalf. Tucson Electric Power Company makes no representation as to information relating to UNS Energy Corporation or its subsidiaries, except as it may relate to Tucson Electric Power Company.
Table of Contents
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| PART I | |
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PART I – FINANCIAL INFORMATION | |
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PART II – OTHER INFORMATION | |
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DEFINITIONS
The abbreviations and acronyms used in the first quarter 2013third quarter2014 report on Form 10-Q are defined below:
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1992 Mortgage | | TEP’s Indenture of Mortgage and Deed of Trust, dated as of December 1, 1992, to the Bank of New York Mellon, successor trustee, as supplemented |
2010 TEP Reimbursement Agreement | | Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution |
2010 UNS Electric Rate Order | | A rate order issued by the ACC resulting in a new rate structure for UNS Electric, effective September 1, 2010 |
2013 TEP Rate Order | | A rate order issued by the ACC resulting in a new rate structure for TEP, effective July 1, 2013 |
2013 UNS Electric SettlementCovenants Agreement | | A rate settlement agreement entered into by UNS ElectricLender Rate Mode Covenants Agreements between TEP and various other partiesthe purchaser of $100 million of unsecured tax-exempt bonds that were issued behalf of TEP in November 2013 and sold in a private placement. |
| ACC | | Arizona Corporation Commission |
AOCI | | Accumulated Other Comprehensive Income |
| APS | | Arizona Public Service Company |
| BART | | Best Available Retrofit Technology |
| Base O&M | | A non-GAAP financial measure that represents the fundamental level of operating and maintenance expense related to our business |
| Base Rates | | The portion of TEP’s and UNS Electric’s Retail Rates attributed to generation, transmission, distribution costs, and customer charge; and UNS Gas’ delivery costs and customer charge. Base Rates exclude costs that are passed through to customers for fuel and purchased energy costs |
BLM | | Bureau of Land Management |
| Btu | | British thermal unit(s) |
CapacityCooling Degree Days | | The abilityAn index used to produce power;measure the most power a unit can produce orimpact of weather on energy usage calculated by subtracting 75 from the maximum that can be taken under a contract, measured in megawatts |
CC&N | | Certificateaverage of Conveniencethe high and Necessity |
Common Stock | | UNS Energy Corporation’s common stock, without par value |
Company | | UNS Energy Corporation and its subsidiaries |
Convertible Senior Notes | | UNS Energy Corporation’s 4.5% Convertible Senior Noteslow daily temperatures |
| DSM | | Demand Side Management |
| ECA | | Environmental Compliance Adjustor |
Electric EE Standards | | Electric Energy Efficiency Standards |
| Entegra | | a subsidiary of Entegra Power Group LLC |
EPA | | Environmental Protection Agency |
EPS | | Earnings Per Share |
ESP | | Electric Service Providers |
FAA | | Federal Arbitration Act |
FASB | | Financial Accounting Standards Board |
| FERC | | Federal Energy Regulatory Commission |
FIPFortis | | Federal Implementation PlanFortisUS, Inc., a Delaware corporation whose ultimate parent company is Fortis Parent |
FVRBFortis Parent | | Fair Value Rate BaseFortis, Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada |
| Four Corners | | Four Corners Generating Station |
GAAP | | Generally Accepted Accounting Principles |
Gas EE Standards | | Gas Energy Efficiency Standards |
| GBtu | | Billion British thermal units |
| GWh | | Gigawatt-hour(s) |
| Gila River Unit 3 | | Unit 3 of the Gila River Generating Station |
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| Heating Degree Days | | An index used to measure the impact of weather on energy usage calculated by subtracting the average of the high and low daily temperatures from 65 |
IRS | | Internal Revenue Service |
| kV | | Kilo-volt |
| kWh | | Kilowatt-hour(s) |
| LFCR | | Lost Fixed Cost Recovery Mechanism |
LOC | | Letter of Credit |
LIBOR | | London Interbank Offered Rate |
| Millennium | | Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UNS Energy Corporation |
| MMBtu | | Million British thermal units |
Mortgage Bonds | | Mortgage Bonds issued under the 1992 Mortgage |
| MW | | Megawatt(s) |
| MWh | | Megawatt-hour(s) |
| Navajo | | Navajo Generating Station |
Net Cash Flows after Capital Expenditures | | A non-GAAP financial measure that compares capital expenditures relative to cash flows from operating activities |
Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations | | A non-GAAP financial measure that compares capital expenditures and required payments on capital lease obligations relative to cash flows from operating activities |
NMED | | New Mexico Environmental Department |
NSP | | Negotiated Sales Program. A program in which UNS Gas sells natural gas to some of its large transportation customers. |
NTUA | | Navajo Tribal Utility Authority |
NOx | | Nitrogen Oxide |
O&M | | Operations and Maintenance |
| OATT | | Open Access Transmission Tariff |
OCRB | | Original Cost Rate Base |
PBI | | Performance-Based Incentives paid to retail customers with solar installations based on metered renewable energy production over periods of 9 to 20 years |
| PGA | | Purchased Gas Adjustor, a Retail Rate mechanism designed to recover the cost of gas purchased for retail gas customers |
| PNM | | Public Service Company of New Mexico |
PPA | | Power Purchase Agreement |
| PPFAC | | Purchased Power and Fuel Adjustment Clause |
PSD | | Prevention of Significant Deterioration |
| REC | | Renewable Energy Credit |
| RES | | Renewable Energy Standard |
Retail Margin Revenues | | A non-GAAP financial measure that demonstrates the underlying revenue trend and performance of our core utility businesses |
| Regional Haze Rules | | Rules promulgated by the EPA to improve visibility at national parks and wilderness areas |
| Retail Rates | | Rates designed to allow a regulated utility an opportunity to recover its reasonable operating and capital costs and earn a return on its utility plant in service |
Rules |
| | Retail Electric Competition Rules established by the ACC in 1999 |
| San Juan | | San Juan Generating Station |
| SCR | | Selective Catalytic Reduction |
SEC | | Securities and Exchange Commission |
SERP | | Supplemental Executive Retirement Plan |
| SJCC | | San Juan Coal Company |
| SNCR | | Selective Non-Catalytic Reduction |
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SO2
| | Sulfur Dioxide |
| Springerville | | Springerville Generating Station |
| Springerville Coal Handling Facilities | | Coal handling facilities at Springerville used by all four Springerville units |
| Springerville Coal Handling Facilities Leases | | Leases for coal handling facilities at Springerville used in common by all four Springerville units |
| Springerville Common Facilities | | Facilities at Springerville used in common by all four Springerville units |
| Springerville Common Facilities Leases | | Leveraged lease arrangements relating to an undivided one-half interest in certain Springerville Common Facilities |
| Springerville Unit 1 | | Unit 1 of the Springerville Generating Station |
| Springerville Unit 1 Leases | | Leveraged lease arrangement relating to Springerville Unit 1 and an undivided one-half interest in certain Springerville Common Facilities |
| Springerville Unit 2 | | Unit 2 of the Springerville Generating Station |
| Springerville Unit 3 | | Unit 3 of the Springerville Generating Station |
| Springerville Unit 4 | | Unit 4 of the Springerville Generating Station |
| SRP | | Salt River Project Agricultural Improvement and Power District |
Sulfur Credits | | Credits applied to the fuel invoice by the supplier when the sulfur content of delivered coal exceeds contractual levels |
| Sundt | | H. Wilson Sundt Generating Station |
| Sundt Unit 4 | | Unit 4 of the H. Wilson Sundt Generating Station |
| TCA | | Transmission Cost Adjustor |
Tenth Circuit | | The United States Court of Appeals for the Tenth Circuit |
| TEP | | Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation |
TEP Credit Agreement | | Second Amended and Restated Credit Agreement between TEP and a syndicate of banks, dated as of November 9, 2010 (as amended) |
TEP Revolving Credit Facility | | Revolving credit facility under the TEP Credit Agreement |
| Therm | | A unit of heating value equivalent to 100,000 Btus |
| Tri-State | | Tri-State Generation and Transmission Association, Inc. |
| UED | | UniSource Energy Development Company, a wholly-owned subsidiary of UNS Energy Corporation |
| UES | | UniSource Energy Services, Inc., a wholly-owned subsidiary of UNS Energy, and intermediate holding company established to own the operating companies UNS GasElectric and UNS Electric |
UNS Credit Agreement | | Second Amended and Restated Credit Agreement between UNS Energy Corporation and a syndicate of banks, dated as of November 9, 2010 (as amended)Gas |
| UNS Electric | | UNS Electric, Inc., a wholly-owned subsidiary of UES |
| UNS Energy | | UNS Energy Corporation (formerly known as UniSource Energy Corporation) |
| UNS Gas | | UNS Gas, Inc., a wholly-owned subsidiary of UES |
UNS Gas/UNS Electric Revolver | | Revolving credit facility under the Second Amended and Restated Credit Agreement among UNS Gas and UNS Electric as borrowers, UES as guarantor, and a syndicate of banks, dated as of November 9, 2010 (as amended) |
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
UNS Energy Corporation:
We have reviewed the accompanying condensed consolidated balance sheet of UNS Energy Corporation and its subsidiaries (the “Company”) as of September 30, 2013, and the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2013 and 2012, the condensed consolidated statements of comprehensive income for the three-month and nine-month periods ended September 30, 2013 and 2012, the condensed consolidated statement of changes in stockholders’ equity for the nine-month period ended September 30, 2013 and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2013 and 2012. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and statement of capitalization as of December 31, 2012, and the related consolidated statements of income, comprehensive income, cash flows, and changes in stockholders’ equity for the year then ended (not presented herein), and in our report dated February 26, 2013, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information and consolidated statement of changes in stockholders' equity information as of December 31, 2012, is fairly stated in all material respects in relation to the consolidated balance sheet and consolidated statement of changes in stockholders' equity from which it has been derived.
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/s/ PricewaterhouseCoopers LLP |
PricewaterhouseCoopers LLP |
November 6, 2013 |
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholder of
Tucson Electric Power Company:
We have reviewed the accompanying condensed consolidated balance sheet of Tucson Electric Power Company and its subsidiaries (the “Company”) as of September 30, 2013, and the related condensed consolidated statements of income for the three-month and nine-month periods ended September 30, 2013 and 2012, the condensed consolidated statements of comprehensive income for the three-month and nine-month periods ended September 30, 2013 and 2012, the condensed consolidated statement of changes in stockholder’s equity for the nine-month period ended September 30, 2013 and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2013 and 2012. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and statement of capitalization as of December 31, 2012, and the related consolidated statements of income, comprehensive income, cash flows, and changes in stockholder's equity for the year then ended (not presented herein), and in our report dated February 26, 2013, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information and consolidated statement of changes in stockholder's equity information as of December 31, 2012, is fairly stated in all material respects in relation to the consolidated balance sheet and consolidated statement of changes in stockholder's equity from which it has been derived.
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/s/ PricewaterhouseCoopers LLP |
PricewaterhouseCoopers LLP |
November 6, 2013 |
PART I—FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
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| Three Months Ended | | | Nine Months Ended |
| September 30, | | | September 30, |
| 2013 | | 2012 | | | 2013 | | 2012 |
| (Unaudited) | | | (Unaudited) |
| Thousands of Dollars | | | Thousands of Dollars |
| (Except Per Share Amounts) | | | (Except Per Share Amounts) |
| | | | | Operating Revenues | | | |
| $ | 362,244 |
| | $ | 353,473 |
| | Electric Retail Sales | $ | 868,523 |
| | $ | 850,975 |
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| 27,529 |
| | 29,341 |
| | Electric Wholesale Sales | 92,581 |
| | 88,469 |
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| 15,430 |
| | 15,407 |
| | Gas Retail Sales | 86,432 |
| | 85,621 |
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| 31,838 |
| | 35,887 |
| | Other Revenues | 86,863 |
| | 88,427 |
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| 437,041 |
| | 434,108 |
| | Total Operating Revenues | 1,134,399 |
| | 1,113,492 |
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| | | | | Operating Expenses | | | |
| 85,102 |
| | 92,873 |
| | Fuel | 253,249 |
| | 245,933 |
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| 67,429 |
| | 57,085 |
| | Purchased Energy | 189,384 |
| | 165,078 |
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| 8,061 |
| | 4,500 |
| | Transmission and Other PPFAC Recoverable Costs | 15,768 |
| | 10,738 |
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| (3,521 | ) | | 18,076 |
| | Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment | (6,814 | ) | | 29,730 |
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| 157,071 |
| | 172,534 |
| | Total Fuel and Purchased Energy | 451,587 |
| | 451,479 |
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| 93,202 |
| | 98,346 |
| | Operations and Maintenance | 278,245 |
| | 283,587 |
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| 38,204 |
| | 35,145 |
| | Depreciation | 111,175 |
| | 105,319 |
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| 5,193 |
| | 9,069 |
| | Amortization | 21,600 |
| | 26,845 |
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| 13,606 |
| | 12,605 |
| | Taxes Other Than Income Taxes | 41,329 |
| | 37,385 |
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| 307,276 |
| | 327,699 |
| | Total Operating Expenses | 903,936 |
| | 904,615 |
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| 129,765 |
| | 106,409 |
| | Operating Income | 230,463 |
| | 208,877 |
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| | | | | Other Income (Deductions) | | | |
| 2 |
| | 340 |
| | Interest Income | 31 |
| | 981 |
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| 2,044 |
| | 1,011 |
| | Other Income | 5,545 |
| | 3,855 |
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| (438 | ) | | (752 | ) | | Other Expense | (1,817 | ) | | (1,508 | ) |
| 731 |
| | 581 |
| | Appreciation (Depreciation) in Fair Value of Investments | 1,864 |
| | 1,621 |
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| 2,339 |
| | 1,180 |
| | Total Other Income (Deductions) | 5,623 |
| | 4,949 |
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| | | | | Interest Expense | | | |
| 17,580 |
| | 17,074 |
| | Long-Term Debt | 53,534 |
| | 53,811 |
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| 6,323 |
| | 8,507 |
| | Capital Leases | 18,821 |
| | 25,105 |
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| 230 |
| | 692 |
| | Other Interest Expense | 183 |
| | 1,712 |
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| (933 | ) | | (459 | ) | | Interest Capitalized | (2,352 | ) | | (1,646 | ) |
| 23,200 |
| | 25,814 |
| | Total Interest Expense | 70,186 |
| | 78,982 |
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| 108,904 |
| | 81,775 |
| | Income Before Income Taxes | 165,900 |
| | 134,844 |
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| 40,914 |
| | 31,111 |
| | Income Tax Expense | 51,947 |
| | 51,430 |
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| $ | 67,990 |
| | $ | 50,664 |
| | Net Income | $ | 113,953 |
| | $ | 83,414 |
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| | | | | Weighted-Average Shares of Common Stock Outstanding (000) | | | |
| 41,650 |
| | 41,446 |
| | Basic | 41,596 |
| | 39,983 |
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| 42,028 |
| | 41,863 |
| | Diluted | 41,941 |
| | 41,719 |
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| | | | | Earnings Per Share | | | |
| $ | 1.63 |
| | $ | 1.22 |
| | Basic | $ | 2.74 |
| | $ | 2.09 |
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| $ | 1.62 |
| | $ | 1.21 |
| | Diluted | $ | 2.72 |
| | $ | 2.03 |
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| $ | 0.435 |
| | $ | 0.43 |
| | Dividends Declared Per Share | $ | 1.305 |
| | $ | 1.29 |
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| | Three Months Ended |
| | March 31, |
| | 2014 | | 2013 |
| | (Unaudited) |
| | Thousands of Dollars |
| | (Except Per Share Amounts) |
| Operating Revenues | | | |
| Electric Retail Sales | $ | 224,570 |
| | $ | 220,860 |
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| Electric Wholesale Sales | 43,421 |
| | 34,398 |
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| Gas Retail Sales | 38,570 |
| | 50,988 |
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| Other Revenues | 26,831 |
| | 25,895 |
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| Total Operating Revenues | 333,392 |
| | 332,141 |
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| Operating Expenses | | | |
| Fuel | 67,835 |
| | 81,689 |
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| Purchased Energy | 69,783 |
| | 64,159 |
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| Transmission and Other PPFAC Recoverable Costs | 6,528 |
| | 3,186 |
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| Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment | (8,920 | ) | | (5,368 | ) |
| Total Fuel and Purchased Energy | 135,226 |
| | 143,666 |
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| Operations and Maintenance | 93,436 |
| | 89,901 |
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| Depreciation | 39,081 |
| | 36,300 |
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| Amortization | 6,176 |
| | 8,289 |
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| Taxes Other Than Income Taxes | 14,808 |
| | 14,090 |
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| Total Operating Expenses | 288,727 |
| | 292,246 |
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| Operating Income | 44,665 |
| | 39,895 |
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| Other Income (Deductions) | | | |
| Interest Income | 80 |
| | 10 |
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| Other Income | 2,142 |
| | 1,767 |
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| Other Expense | (730 | ) | | (572 | ) |
| Appreciation in Fair Value of Investments | 255 |
| | 1,038 |
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| Total Other Income (Deductions) | 1,747 |
| | 2,243 |
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| Interest Expense | | | |
| Long-Term Debt | 17,888 |
| | 18,254 |
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| Capital Leases | 3,921 |
| | 6,249 |
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| Other Interest Expense | 483 |
| | (393 | ) |
| Interest Capitalized | (1,023 | ) | | (675 | ) |
| Total Interest Expense | 21,269 |
| | 23,435 |
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| Income Before Income Taxes | 25,143 |
| | 18,703 |
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| Income Tax Expense | 9,668 |
| | 7,358 |
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| Net Income | $ | 15,475 |
| | $ | 11,345 |
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| Weighted-Average Shares of Common Stock Outstanding (000) | | | |
| Basic | 41,737 |
| | 41,540 |
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| Diluted | 42,084 |
| | 41,875 |
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| Earnings Per Share | | | |
| Basic | $ | 0.37 |
| | $ | 0.27 |
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| Diluted | $ | 0.37 |
| | $ | 0.27 |
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| Dividends Declared Per Share | $ | 0.48 |
| | $ | 0.435 |
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See Notes to Condensed Consolidated Financial Statements.
UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
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| | Three Months Ended |
| | March 31, |
| | 2014 | | 2013 |
| | (Unaudited) |
| | Thousands of Dollars |
| Comprehensive Income | | | |
| Net Income | $ | 15,475 |
| | $ | 11,345 |
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| Other Comprehensive Income | | | |
| Net Changes in Fair Value of Cash Flow Hedges, net of income tax (expense) benefit of $(356) and $(401) | 493 |
| | 612 |
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| SERP Benefit Amortization, net of income tax (expense) benefit of $(15) and $(42) | 24 |
| | 68 |
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| Total Other Comprehensive Income, Net of Tax | 517 |
| | 680 |
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| Total Comprehensive Income | $ | 15,992 |
| | $ | 12,025 |
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See Notes to Condensed Consolidated Financial Statements.
UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS |
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| | Three Months Ended |
| | March 31, |
| | 2014 | | 2013 |
| | (Unaudited) |
| | Thousands of Dollars |
| Cash Flows from Operating Activities | | | |
| Cash Receipts from Electric Retail Sales | $ | 258,538 |
| | $ | 253,747 |
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| Cash Receipts from Gas Retail Sales | 50,045 |
| | 59,849 |
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| Cash Receipts from Electric Wholesale Sales | 49,877 |
| | 43,538 |
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| Cash Receipts from Operating Springerville Units 3 & 4 | 20,295 |
| | 25,032 |
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| Cash Receipts from Gas Wholesale Sales | 2,222 |
| | 3,152 |
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| Interest Received | 4 |
| | 515 |
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| Other Cash Receipts | 12,605 |
| | 6,137 |
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| Purchased Energy Costs Paid | (75,688 | ) | | (73,761 | ) |
| Fuel Costs Paid | (72,335 | ) | | (76,321 | ) |
| Payment of Operations and Maintenance Costs | (68,337 | ) | | (57,173 | ) |
| Wages Paid, Net of Amounts Capitalized | (39,692 | ) | | (36,306 | ) |
| Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized | (29,864 | ) | | (32,237 | ) |
| Interest Paid, Net of Amounts Capitalized | (15,464 | ) | | (17,784 | ) |
| Capital Lease Interest Paid | (13,682 | ) | | (16,123 | ) |
| Other Cash Payments | (1,739 | ) | | (1,212 | ) |
| Net Cash Flows—Operating Activities | 76,785 |
| | 81,053 |
|
| Cash Flows from Investing Activities | | | |
| Capital Expenditures | (88,244 | ) | | (81,228 | ) |
| Return of Investments in Springerville Lease Debt | — |
| | 9,104 |
|
| Other, net | 1,726 |
| | (2,393 | ) |
| Net Cash Flows—Investing Activities | (86,518 | ) | | (74,517 | ) |
| Cash Flows from Financing Activities | | | |
| Proceeds from Borrowings Under Revolving Credit Facilities | 120,000 |
| | 66,000 |
|
| Repayments of Borrowings Under Revolving Credit Facilities | (114,000 | ) | | (35,000 | ) |
| Proceeds from Issuance of Long-Term Debt | 149,168 |
| | — |
|
| Payments of Capital Lease Obligations | (79,737 | ) | | (81,281 | ) |
| Common Stock Dividends Paid | (20,017 | ) | | (18,035 | ) |
| Other, net | (801 | ) | | 1,762 |
|
| Net Cash Flows—Financing Activities | 54,613 |
| | (66,554 | ) |
| Net Increase (Decrease) in Cash and Cash Equivalents | 44,880 |
| | (60,018 | ) |
| Cash and Cash Equivalents, Beginning of Year | 74,878 |
| | 123,918 |
|
| Cash and Cash Equivalents, End of Period | $ | 119,758 |
| | $ | 63,900 |
|
See Note 11 for supplemental cash flow information.
See Notes to Condensed Consolidated Financial Statements.
UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
|
| | | | | | | | | | | | | | | |
| Three Months Ended | | | Nine Months Ended |
| September 30, | | | September 30, |
| 2013 | | 2012 | | | 2013 | | 2012 |
| (Unaudited) | | | (Unaudited) |
| Thousands of Dollars | | | Thousands of Dollars |
| | | | | Comprehensive Income | | | |
| $ | 67,990 |
| | $ | 50,664 |
| | Net Income | $ | 113,953 |
| | $ | 83,414 |
|
| | | | | | | | |
| | | | | Other Comprehensive Income | | | |
| | | | | Net Changes in Fair Value of Cash Flow Hedges: | | | |
| 685 |
| | 370 |
| | net of income tax expense of $(448) and $(244) | | | |
| | | | | net of income tax expense of $(1,459) and $(421) | 2,229 |
| | 641 |
|
| | | | | | | | |
| | | | | Supplemental Executive Retirement Plan (SERP) Benefit Amortization: | | | |
| 68 |
| | 55 |
| | net of income tax expense of $(42) and $(34) | | | |
| | | | | net of income tax expense of $(127) and $(50) | 205 |
| | 219 |
|
| | | | | | | | |
| 753 |
| | 425 |
| | Total Other Comprehensive Income, Net of Income Tax Expense | 2,434 |
| | 860 |
|
| $ | 68,743 |
| | $ | 51,089 |
| | Total Comprehensive Income | $ | 116,387 |
| | $ | 84,274 |
|
See Notes to Condensed Consolidated Financial Statements.
UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | | | | | |
| | Nine Months Ended September 30, |
| | 2013 | | 2012 |
| | (Unaudited) |
| | Thousands of Dollars |
| Cash Flows from Operating Activities | | | |
| Cash Receipts from Electric Retail Sales | $ | 912,098 |
| | $ | 894,195 |
|
| Cash Receipts from Electric Wholesale Sales | 118,341 |
| | 107,854 |
|
| Cash Receipts from Gas Retail Sales | 109,994 |
| | 114,055 |
|
| Cash Receipts from Operating Springerville Units 3 & 4 | 75,552 |
| | 75,715 |
|
| Cash Receipts from Gas Wholesale Sales | 3,558 |
| | 565 |
|
| Interest Received | 516 |
| | 2,884 |
|
| Income Tax Refunds Received | — |
| | 307 |
|
| Other Cash Receipts | 23,514 |
| | 18,810 |
|
| Fuel Costs Paid | (218,712 | ) | | (239,397 | ) |
| Purchased Energy Costs Paid | (217,522 | ) | | (189,927 | ) |
| Payment of Operations and Maintenance Costs | (199,939 | ) | | (207,780 | ) |
| Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized | (124,782 | ) | | (128,513 | ) |
| Wages Paid, Net of Amounts Capitalized | (96,899 | ) | | (94,815 | ) |
| Interest Paid, Net of Amounts Capitalized | (50,108 | ) | | (52,593 | ) |
| Capital Lease Interest Paid | (21,698 | ) | | (27,895 | ) |
| Income Taxes Paid | (316 | ) | | — |
|
| Other Cash Payments | (8,563 | ) | | (5,327 | ) |
| Net Cash Flows—Operating Activities | 305,034 |
| | 268,138 |
|
| Cash Flows from Investing Activities | | | |
| Capital Expenditures | (238,463 | ) | | (232,036 | ) |
| Purchase of Intangibles—Renewable Energy Credits | (20,429 | ) | | (7,554 | ) |
| Deposit—San Juan Mine Reclamation Trust | — |
| | (1,107 | ) |
| Other Cash Payments | — |
| | (232 | ) |
| Return of Investments in Springerville Lease Debt | 9,104 |
| | 19,278 |
|
| Restricted Cash Released | 4,500 |
| | — |
|
| Proceeds from Note Receivable | — |
| | 12,500 |
|
| Insurance Proceeds for Replacement Assets | — |
| | 2,875 |
|
| Other Cash Receipts | 6,625 |
| | 14,484 |
|
| Net Cash Flows—Investing Activities | (238,663 | ) | | (191,792 | ) |
| Cash Flows from Financing Activities | | | |
| Proceeds from Borrowings Under Revolving Credit Facilities | 130,000 |
| | 342,000 |
|
| Repayments of Borrowings Under Revolving Credit Facilities | (100,000 | ) | | (346,000 | ) |
| Payments of Capital Lease Obligations | (99,621 | ) | | (89,452 | ) |
| Common Stock Dividends Paid | (54,146 | ) | | (51,852 | ) |
| Proceeds from Issuance of Long-Term Debt | — |
| | 149,513 |
|
| Repayments of Long-Term Debt | — |
| | (9,341 | ) |
| Payment of Debt Issue/Retirement Costs | (1,022 | ) | | (3,349 | ) |
| Proceeds from Stock Options Exercised | 2,724 |
| | 3,529 |
|
| Proceeds from Common Stock Issuance | 408 |
| | — |
|
| Other Cash Receipts | 4,721 |
| | 2,935 |
|
| Other Cash Payments | (962 | ) | | (718 | ) |
| Net Cash Flows—Financing Activities | (117,898 | ) | | (2,735 | ) |
| Net Increase (Decrease) in Cash and Cash Equivalents | (51,527 | ) | | 73,611 |
|
| Cash and Cash Equivalents, Beginning of Year | 123,918 |
| | 76,390 |
|
| Cash and Cash Equivalents, End of Period | $ | 72,391 |
| | $ | 150,001 |
|
See Note 10 for supplemental cash flow information.
See Notes to Condensed Consolidated Financial Statements.
UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
| | | | September 30, | | December 31, | March 31, | | December 31, |
| | 2013 | | 2012 | 2014 | | 2013 |
| | (Unaudited) | (Unaudited) |
| | Thousands of Dollars | Thousands of Dollars |
| ASSETS | | |
| Utility Plant | | | | | | |
| Plant in Service | $ | 5,114,426 |
| | $ | 5,005,768 |
| $ | 5,235,954 |
| | $ | 5,192,122 |
|
| Utility Plant Under Capital Leases | 621,247 |
| | 582,669 |
| 637,957 |
| | 637,957 |
|
| Construction Work in Progress | 211,100 |
| | 128,621 |
| 211,357 |
| | 201,959 |
|
| Total Utility Plant | 5,946,773 |
| | 5,717,058 |
| 6,085,268 |
| | 6,032,038 |
|
| Less Accumulated Depreciation and Amortization | (1,966,801 | ) | | (1,921,733 | ) | (1,998,610 | ) | | (1,982,524 | ) |
| Less Accumulated Amortization of Capital Lease Assets | (509,712 | ) | | (494,962 | ) | (519,860 | ) | | (514,677 | ) |
| Total Utility Plant—Net | 3,470,260 |
| | 3,300,363 |
| 3,566,798 |
| | 3,534,837 |
|
| Investments and Other Property | | | | | | |
| Investments in Lease Equity | 36,230 |
| | 36,339 |
| 36,158 |
| | 36,194 |
|
| Other | 33,441 |
| | 36,537 |
| 34,960 |
| | 34,971 |
|
| Total Investments and Other Property | 69,671 |
| | 72,876 |
| 71,118 |
| | 71,165 |
|
| Current Assets | | | | | | |
| Cash and Cash Equivalents | 72,391 |
| | 123,918 |
| 119,758 |
| | 74,878 |
|
| Accounts Receivable—Customer | 127,316 |
| | 93,742 |
| 91,550 |
| | 104,596 |
|
| Unbilled Accounts Receivable | 55,730 |
| | 53,568 |
| 39,037 |
| | 52,403 |
|
| Allowance for Doubtful Accounts | (7,215 | ) | | (6,545 | ) | (6,867 | ) | | (6,833 | ) |
| Materials and Supplies | 89,302 |
| | 93,322 |
| 89,346 |
| | 88,085 |
|
| Fuel Inventory | 44,458 |
| | 62,019 |
| |
| Deferred Income Taxes—Current | 66,520 |
| | 34,260 |
| 62,826 |
| | 66,906 |
|
| Regulatory Assets—Current | 52,709 |
| | 51,619 |
| 56,368 |
| | 52,763 |
|
| Investments in Lease Debt | — |
| | 9,118 |
| |
| Fuel Inventory | | 46,113 |
| | 44,317 |
|
| Derivative Instruments | 1,620 |
| | 3,165 |
| 10,524 |
| | 5,629 |
|
| Other | 26,882 |
| | 33,567 |
| 16,044 |
| | 15,354 |
|
| Total Current Assets | 529,713 |
| | 551,753 |
| 524,699 |
| | 498,098 |
|
| Regulatory and Other Assets | | | | | | |
| Regulatory Assets—Noncurrent | 200,705 |
| | 191,077 |
| 156,468 |
| | 150,584 |
|
| Derivative Instruments | 752 |
| | 3,801 |
| 838 |
| | 1,180 |
|
| Other Assets | 22,704 |
| | 20,559 |
| 24,567 |
| | 24,430 |
|
| Total Regulatory and Other Assets | 224,161 |
| | 215,437 |
| 181,873 |
| | 176,194 |
|
| Total Assets | $ | 4,293,805 |
| | $ | 4,140,429 |
| $ | 4,344,488 |
| | $ | 4,280,294 |
|
See Notes to Condensed Consolidated Financial Statements.
(Continued)
UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
| | | | September 30, | | December 31, | March 31, | | December 31, |
| | 2013 | | 2012 | 2014 | | 2013 |
| | (Unaudited) | (Unaudited) |
| | Thousands of Dollars | Thousands of Dollars |
| CAPITALIZATION AND OTHER LIABILITIES | | |
| Capitalization | | | | | | |
| Common Stock Equity | $ | 1,132,286 |
| | $ | 1,065,465 |
| $ | 1,125,824 |
| | $ | 1,130,784 |
|
| Capital Lease Obligations | 130,088 |
| | 262,138 |
| 73,984 |
| | 131,370 |
|
| Long-Term Debt | 1,505,536 |
| | 1,498,442 |
| 1,659,278 |
| | 1,507,070 |
|
| Total Capitalization | 2,767,910 |
| | 2,826,045 |
| 2,859,086 |
| | 2,769,224 |
|
| Current Liabilities | | | | | | |
| Current Obligations Under Capital Leases | 169,060 |
| | 90,583 |
| 163,159 |
| | 186,056 |
|
| Borrowings Under Revolving Credit Facilities | 23,000 |
| | — |
| 25,000 |
| | 22,000 |
|
| Accounts Payable—Trade | 91,615 |
| | 107,740 |
| 100,507 |
| | 117,503 |
|
| Regulatory Liabilities—Current | | 54,285 |
| | 53,935 |
|
| Accrued Taxes Other than Income Taxes | 60,657 |
| | 41,939 |
| 55,577 |
| | 43,880 |
|
| Customer Deposits | | 28,943 |
| | 30,671 |
|
| Accrued Employee Expenses | 26,000 |
| | 24,094 |
| 22,806 |
| | 28,148 |
|
| Accrued Interest | 22,343 |
| | 31,950 |
| 21,906 |
| | 27,786 |
|
| Regulatory Liabilities—Current | 56,987 |
| | 43,516 |
| |
| Customer Deposits | 30,564 |
| | 34,048 |
| |
| Derivative Instruments | 12,988 |
| | 14,742 |
| 6,420 |
| | 7,534 |
|
| Other | 14,521 |
| | 10,517 |
| 20,394 |
| | 17,775 |
|
| Total Current Liabilities | 507,735 |
| | 399,129 |
| 498,997 |
| | 535,288 |
|
| Deferred Credits and Other Liabilities | | | | | | |
| Deferred Income Taxes—Noncurrent | 482,516 |
| | 364,756 |
| 491,212 |
| | 488,887 |
|
| Regulatory Liabilities—Noncurrent | 297,699 |
| | 279,111 |
| 308,873 |
| | 302,482 |
|
| Pension and Other Retiree Benefits | 141,997 |
| | 159,401 |
| 92,247 |
| | 90,923 |
|
| Derivative Instruments | 7,183 |
| | 12,709 |
| 7,355 |
| | 7,100 |
|
| Other | 88,765 |
| | 99,278 |
| 86,718 |
| | 86,390 |
|
| Total Deferred Credits and Other Liabilities | 1,018,160 |
| | 915,255 |
| 986,405 |
| | 975,782 |
|
| Commitments, Contingencies, and Environmental Matters (Note 4) |
| |
| |
| Commitments, Contingencies, and Environmental Matters (Note 6) | |
| |
|
| Total Capitalization and Other Liabilities | $ | 4,293,805 |
| | $ | 4,140,429 |
| $ | 4,344,488 |
| | $ | 4,280,294 |
|
See Notes to Condensed Consolidated Financial Statements.
(Concluded)
UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
|
| | | | | | | | | | | | | | | | | | |
| | Common Shares Outstanding* | | Common Stock | | Accumulated Earnings | | Accumulated Other Comprehensive Loss | | Total Stockholders’ Equity |
| | Thousands of Shares | | (Unaudited)
Thousands of Dollars |
| Balances at December 31, 2012 | 41,344 |
| | $ | 882,138 |
| | $ | 193,117 |
| | $ | (9,790 | ) | | $ | 1,065,465 |
|
| Comprehensive Income | | | | | | | | | |
| 2013 Year-to-Date Net Income | | | | | 113,953 |
| | | | 113,953 |
|
| Other Comprehensive Income, net of $(1,586) income taxes | | |
| |
| | 2,434 |
| | 2,434 |
|
| Total Comprehensive Income | | | | | | | | | 116,387 |
|
| Dividends, Including Non-Cash Dividend Equivalents |
| | | | (54,733 | ) | |
| | (54,733 | ) |
| Shares Issued Under Dividend Reinvestment Plan | 9 |
| | 408 |
| | | | | | 408 |
|
| Shares Issued for Stock Options | 85 |
| | 2,724 |
| |
| |
| | 2,724 |
|
| Shares Issued Under Performance Share Awards | 57 |
| | — |
| |
| |
| | — |
|
| Other | | | 2,035 |
| | | | | | 2,035 |
|
| Balances at September 30, 2013 | 41,495 |
| | $ | 887,305 |
| | $ | 252,337 |
| | $ | (7,356 | ) | | $ | 1,132,286 |
|
|
| | | | | | | | | | | | | | | | | | |
| | Common Shares Outstanding * | | Common Stock | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Total Stockholders’ Equity |
| | (Unaudited) |
| | Thousands of Shares | | Thousands of Dollars |
| Balances at December 31, 2013 | 41,538 |
| | $ | 889,301 |
| | $ | 247,532 |
| | $ | (6,049 | ) | | $ | 1,130,784 |
|
| Net Income | | | | | 15,475 |
| | | | 15,475 |
|
| Other Comprehensive Income, net of tax | | |
| |
| | 517 |
| | 517 |
|
| Dividends Declared |
| | | | (20,186 | ) | |
| | (20,186 | ) |
| Shares Issued for Stock Options | 20 |
| | 594 |
| |
| |
| | 594 |
|
| Shares Issued under Performance Share Awards | 101 |
| | — |
| |
| |
| | — |
|
| Share-based Compensation | | | (1,360 | ) | | | | | | (1,360 | ) |
| Balances at March 31, 2014 | 41,659 |
| | $ | 888,535 |
| | $ | 242,821 |
| | $ | (5,532 | ) | | $ | 1,125,824 |
|
* UNS Energy has 75 million authorized shares of Common Stock.
See Notes to Condensed Consolidated Financial Statements.
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
|
| | | | | | | | | | | | | | | |
| Three Months Ended | | | Nine Months Ended |
| September 30, | | | September 30, |
| 2013 | | 2012 | | | 2013 | | 2012 |
| (Unaudited) | | | (Unaudited) |
| Thousands of Dollars | | | Thousands of Dollars |
| | | | | Operating Revenues | | | |
| $ | 310,632 |
| | $ | 302,893 |
| | Electric Retail Sales | $ | 739,147 |
| | $ | 716,993 |
|
| 26,563 |
| | 25,448 |
| | Electric Wholesale Sales | 90,503 |
| | 77,488 |
|
| 34,044 |
| | 38,569 |
| | Other Revenues | 93,603 |
| | 95,826 |
|
| 371,239 |
| | 366,910 |
| | Total Operating Revenues | 923,253 |
| | 890,307 |
|
| | | | | Operating Expenses | | | |
| 82,065 |
| | 88,402 |
| | Fuel | 247,417 |
| | 237,930 |
|
| 42,477 |
| | 27,576 |
| | Purchased Power | 89,815 |
| | 62,064 |
|
| 4,940 |
| | 1,914 |
| | Transmission and Other PPFAC Recoverable Costs | 7,535 |
| | 4,277 |
|
| (7,992 | ) | | 20,025 |
| | Increase (Decrease) to Reflect PPFAC Recovery Treatment | (5,079 | ) | | 25,150 |
|
| 121,490 |
| | 137,917 |
| | Total Fuel and Purchased Energy | 339,688 |
| | 329,421 |
|
| 79,335 |
| | 86,942 |
| | Operations and Maintenance | 239,170 |
| | 248,092 |
|
| 30,311 |
| | 27,644 |
| | Depreciation | 87,729 |
| | 82,656 |
|
| 6,118 |
| | 10,001 |
| | Amortization | 24,393 |
| | 29,621 |
|
| 10,808 |
| | 10,327 |
| | Taxes Other Than Income Taxes | 32,916 |
| | 30,325 |
|
| 248,062 |
| | 272,831 |
| | Total Operating Expenses | 723,896 |
| | 720,115 |
|
| 123,177 |
| | 94,079 |
| | Operating Income | 199,357 |
| | 170,192 |
|
| | | | | Other Income (Deductions) | | | |
| 6 |
| | 28 |
| | Interest Income | 14 |
| | 97 |
|
| 1,466 |
| | 952 |
| | Other Income | 3,904 |
| | 3,041 |
|
| (2,776 | ) | | (1,945 | ) | | Other Expense | (7,493 | ) | | (4,886 | ) |
| 731 |
| | 581 |
| | Appreciation (Depreciation) in Fair Value of Investments | 1,864 |
| | 1,621 |
|
| (573 | ) | | (384 | ) | | Total Other Income (Deductions) | (1,711 | ) | | (127 | ) |
| | | | | Interest Expense | | | |
| 13,848 |
| | 13,268 |
| | Long-Term Debt | 42,412 |
| | 40,562 |
|
| 6,323 |
| | 8,507 |
| | Capital Leases | 18,821 |
| | 25,105 |
|
| 82 |
| | 562 |
| | Other Interest Expense | (86 | ) | | 1,338 |
|
| (644 | ) | | (361 | ) | | Interest Capitalized | (1,671 | ) | | (1,381 | ) |
| 19,609 |
| | 21,976 |
| | Total Interest Expense | 59,476 |
| | 65,624 |
|
| 102,995 |
| | 71,719 |
| | Income Before Income Taxes | 138,170 |
| | 104,441 |
|
| 38,828 |
| | 27,150 |
| | Income Tax Expense | 41,737 |
| | 39,423 |
|
| $ | 64,167 |
| | $ | 44,569 |
| | Net Income | $ | 96,433 |
| | $ | 65,018 |
|
|
| | | | | | | |
| | Three Months Ended |
| | March 31, |
| | 2014 | | 2013 |
| | (Unaudited) |
| | Thousands of Dollars |
| Operating Revenues | | | |
| Electric Retail Sales | $ | 186,015 |
| | $ | 184,881 |
|
| Electric Wholesale Sales | 42,084 |
| | 34,398 |
|
| Other Revenues | 27,414 |
| | 28,472 |
|
| Total Operating Revenues | 255,513 |
| | 247,751 |
|
| Operating Expenses | | | |
| Fuel | 67,630 |
| | 80,798 |
|
| Purchased Power | 22,615 |
| | 18,928 |
|
| Transmission and Other PPFAC Recoverable Costs | 3,909 |
| | 865 |
|
| Increase (Decrease) to Reflect PPFAC Recovery Treatment | (1,730 | ) | | (2,360 | ) |
| Total Fuel and Purchased Energy | 92,424 |
| | 98,231 |
|
| Operations and Maintenance | 81,345 |
| | 77,824 |
|
| Depreciation | 30,811 |
| | 28,558 |
|
| Amortization | 7,099 |
| | 9,222 |
|
| Taxes Other Than Income Taxes | 11,835 |
| | 11,169 |
|
| Total Operating Expenses | 223,514 |
| | 225,004 |
|
| Operating Income | 31,999 |
| | 22,747 |
|
| Other Income (Deductions) | | | |
| Interest Income | 9 |
| | (4 | ) |
| Other Income | 1,912 |
| | 1,168 |
|
| Other Expense | (2,115 | ) | | (2,245 | ) |
| Appreciation in Fair Value of Investments | 255 |
| | 1,038 |
|
| Total Other Income (Deductions) | 61 |
| | (43 | ) |
| Interest Expense | | | |
| Long-Term Debt | 14,240 |
| | 14,573 |
|
| Capital Leases | 3,921 |
| | 6,249 |
|
| Other Interest Expense | 313 |
| | (360 | ) |
| Interest Capitalized | (924 | ) | | (493 | ) |
| Total Interest Expense | 17,550 |
| | 19,969 |
|
| Income Before Income Taxes | 14,510 |
| | 2,735 |
|
| Income Tax Expense | 5,338 |
| | 1,257 |
|
| Net Income | $ | 9,172 |
| | $ | 1,478 |
|
See Notes to Condensed Consolidated Financial Statements.
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
|
| | | | | | | | | | | | | | | |
| Three Months Ended | | | Nine Months Ended |
| September 30, | | | September 30, |
| 2013 | | 2012 | | | 2013 | | 2012 |
| (Unaudited) | | | (Unaudited) |
| Thousands of Dollars | | | Thousands of Dollars |
| | | | | Comprehensive Income | | | |
| $ | 64,167 |
| | $ | 44,569 |
| | Net Income | $ | 96,433 |
| | $ | 65,018 |
|
| | | | | | | | |
| | | | | Other Comprehensive Income | | | |
| | | | | Net Changes in Fair Value of Cash Flow Hedges: | | | |
| 700 |
| | 465 |
| | net of income tax expense of $(458) and $(304) | | | |
| | | | | net of income tax expense of $(1,412) and $(584) | 2,156 |
| | 891 |
|
| | | | | | | | |
| | | | | SERP Benefit Amortization: | | | |
| 68 |
| | 55 |
| | net of income tax expense of $(42) and $(34) | | | |
| | | | | net of income tax expense of $(127) and $(50) | 205 |
| | 219 |
|
| | | | | | | | |
| 768 |
| | 520 |
| | Total Other Comprehensive Income, Net of Income Tax Expense | 2,361 |
| | 1,110 |
|
| $ | 64,935 |
| | $ | 45,089 |
| | Total Comprehensive Income | $ | 98,794 |
| | $ | 66,128 |
|
|
| | | | | | | |
| | Three Months Ended |
| | March 31, |
| | 2014 | | 2013 |
| | (Unaudited) |
| | Thousands of Dollars |
| Comprehensive Income | | | |
| Net Income | $ | 9,172 |
| | $ | 1,478 |
|
| Other Comprehensive Income (Loss) | | | |
| Net Changes in Fair Value of Cash Flow Hedges, net of income tax (expense) benefit of $(346) and $(379) | 481 |
| | 580 |
|
| SERP Benefit Amortization, net of income tax (expense) benefit of $(15) and $(42) | 24 |
| | 68 |
|
| Total Other Comprehensive Income (Loss), Net of Tax | 505 |
| | 648 |
|
| Total Comprehensive Income | $ | 9,677 |
| | $ | 2,126 |
|
See Notes to Condensed Consolidated Financial Statements.
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | Three Months Ended |
| | Nine Months Ended September 30, | March 31, |
| | 2013 | | 2012 | 2014 | | 2013 |
| | (Unaudited) | (Unaudited) |
| | Thousands of Dollars | Thousands of Dollars |
| Cash Flows from Operating Activities | | | | | | |
| Cash Receipts from Electric Retail Sales | $ | 769,433 |
| | $ | 748,936 |
| $ | 215,089 |
| | $ | 211,011 |
|
| Cash Receipts from Electric Wholesale Sales | 107,997 |
| | 89,902 |
| 47,535 |
| | 40,061 |
|
| Cash Receipts from Operating Springerville Units 3 & 4 | 75,552 |
| | 75,715 |
| 20,295 |
| | 25,032 |
|
| Reimbursement of Affiliate Charges | 17,639 |
| | 16,783 |
| 7,831 |
| | 5,883 |
|
| Cash Receipts from Gas Wholesale Sales | 3,209 |
| | 153 |
| 46 |
| | 3,114 |
|
| Interest Received | 509 |
| | 2,014 |
| 2 |
| | 509 |
|
| Income Tax Refunds Received | 77 |
| | 200 |
| |
| Other Cash Receipts | 18,240 |
| | 14,528 |
| 10,595 |
| | 4,624 |
|
| Fuel Costs Paid | (214,722 | ) | | (233,457 | ) | (72,153 | ) | | (76,560 | ) |
| Payment of Operations and Maintenance Costs | (193,290 | ) | | (200,569 | ) | (66,154 | ) | | (54,791 | ) |
| Wages Paid, Net of Amounts Capitalized | | (33,124 | ) | | (30,542 | ) |
| Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized | (97,419 | ) | | (99,249 | ) | (21,973 | ) | | (23,303 | ) |
| Purchased Power Costs Paid | (87,110 | ) | | (60,684 | ) | (18,892 | ) | | (17,417 | ) |
| Wages Paid, Net of Amounts Capitalized | (80,964 | ) | | (77,820 | ) | |
| Capital Lease Interest Paid | | (13,682 | ) | | (16,123 | ) |
| Interest Paid, Net of Amounts Capitalized | (36,671 | ) | | (35,728 | ) | (9,128 | ) | | (11,239 | ) |
| Capital Lease Interest Paid | (21,698 | ) | | (27,893 | ) | |
| Income Taxes Paid | — |
| | (1,796 | ) | |
| Other Cash Payments | (6,603 | ) | | (3,884 | ) | (973 | ) | | (860 | ) |
| Net Cash Flows—Operating Activities | 254,179 |
| | 207,151 |
| 65,314 |
| | 59,399 |
|
| Cash Flows from Investing Activities | | | | | | |
| Capital Expenditures | (180,451 | ) | | (196,429 | ) | (72,570 | ) | | (61,668 | ) |
| Purchase of Intangibles—Renewable Energy Credits | (17,552 | ) | | (6,436 | ) | |
| Deposit—San Juan Mine Reclamation Trust | — |
| | (1,107 | ) | |
| Return of Investments in Springerville Lease Debt | 9,104 |
| | 19,278 |
| — |
| | 9,104 |
|
| Restricted Cash Released | 4,500 |
| | — |
| |
| Insurance Proceeds for Replacement Assets | — |
| | 2,875 |
| |
| Other Cash Receipts | 4,656 |
| | 9,207 |
| |
| Other, net | | 1,979 |
| | (2,911 | ) |
| Net Cash Flows—Investing Activities | (179,743 | ) | | (172,612 | ) | (70,591 | ) | | (55,475 | ) |
| Cash Flows from Financing Activities | | | | | | |
| Proceeds from Borrowings Under Revolving Credit Facility | 78,000 |
| | 189,000 |
| 105,000 |
| | 55,000 |
|
| Repayments of Borrowings Under Revolving Credit Facility | (78,000 | ) | | (199,000 | ) | (105,000 | ) | | (35,000 | ) |
| Proceeds from Issuance of Long-Term Debt | | 149,168 |
| | — |
|
| Payments of Capital Lease Obligations | (99,621 | ) | | (89,452 | ) | (79,737 | ) | | (81,281 | ) |
| Dividends Paid to UNS Energy | (20,000 | ) | | — |
| |
| Proceeds from Issuance of Long-Term Debt | — |
| | 149,513 |
| |
| Repayments of Long-Term Debt | — |
| | (6,535 | ) | |
| Payment of Debt Issue/Retirement Costs | (1,022 | ) | | (3,349 | ) | |
| Other Cash Receipts | 1,976 |
| | 1,292 |
| |
| Other Cash Payments | (726 | ) | | (530 | ) | |
| Other, net | | (1,468 | ) | | (382 | ) |
| Net Cash Flows—Financing Activities | (119,393 | ) | | 40,939 |
| 67,963 |
| | (61,663 | ) |
| Net Increase (Decrease) in Cash and Cash Equivalents | (44,957 | ) | | 75,478 |
| 62,686 |
| | (57,739 | ) |
| Cash and Cash Equivalents, Beginning of Year | 79,743 |
| | 27,718 |
| 25,335 |
| | 79,743 |
|
| Cash and Cash Equivalents, End of Period | $ | 34,786 |
| | $ | 103,196 |
| $ | 88,021 |
| | $ | 22,004 |
|
See Note 1011 for supplemental cash flow information.
See Notes to Condensed Consolidated Financial Statements.
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
| | | | September 30, | | December 31, | March 31, | | December 31, |
| | 2013 | | 2012 | 2014 | | 2013 |
| | (Unaudited) | (Unaudited) |
| | Thousands of Dollars | Thousands of Dollars |
| ASSETS | | | | | | |
| Utility Plant | | | | | | |
| Plant in Service | $ | 4,434,770 |
| | $ | 4,348,041 |
| $ | 4,493,282 |
| | $ | 4,467,667 |
|
| Utility Plant Under Capital Leases | 621,247 |
| | 582,669 |
| 637,957 |
| | 637,957 |
|
| Construction Work in Progress | 153,258 |
| | 98,460 |
| 196,643 |
| | 180,485 |
|
| Total Utility Plant | 5,209,275 |
| | 5,029,170 |
| 5,327,882 |
| | 5,286,109 |
|
| Less Accumulated Depreciation and Amortization | (1,811,806 | ) | | (1,783,787 | ) | (1,839,235 | ) | | (1,826,977 | ) |
| Less Accumulated Amortization of Capital Lease Assets | (509,712 | ) | | (494,962 | ) | (519,860 | ) | | (514,677 | ) |
| Total Utility Plant—Net | 2,887,757 |
| | 2,750,421 |
| 2,968,787 |
| | 2,944,455 |
|
| Investments and Other Property | | | | | | |
| Investments in Lease Equity | 36,230 |
| | 36,339 |
| 36,158 |
| | 36,194 |
|
| Other | 32,009 |
| | 35,091 |
| 33,648 |
| | 33,488 |
|
| Total Investments and Other Property | 68,239 |
| | 71,430 |
| 69,806 |
| | 69,682 |
|
| Current Assets | | | | | | |
| Cash and Cash Equivalents | 34,786 |
| | 79,743 |
| 88,021 |
| | 25,335 |
|
| Accounts Receivable—Customer | 105,646 |
| | 71,813 |
| 72,458 |
| | 80,211 |
|
| Unbilled Accounts Receivable | 46,240 |
| | 33,782 |
| 27,705 |
| | 34,369 |
|
| Allowance for Doubtful Accounts | (5,238 | ) | | (4,598 | ) | (4,791 | ) | | (4,825 | ) |
| Accounts Receivable—Due from Affiliates | 3,963 |
| | 5,720 |
| 4,003 |
| | 6,064 |
|
| Materials and Supplies | 76,255 |
| | 80,377 |
| 76,586 |
| | 75,200 |
|
| Deferred Income Taxes—Current | | 66,771 |
| | 70,722 |
|
| Fuel Inventory | 44,162 |
| | 61,737 |
| 45,823 |
| | 44,027 |
|
| Deferred Income Taxes—Current | 69,985 |
| | 37,212 |
| |
| Regulatory Assets—Current | 36,283 |
| | 34,345 |
| 45,962 |
| | 42,555 |
|
| Investments in Lease Debt | — |
| | 9,118 |
| |
| Derivative Instruments | 1,047 |
| | 2,230 |
| 3,906 |
| | 2,137 |
|
| Other | 20,605 |
| | 32,163 |
| 13,006 |
| | 12,923 |
|
| Total Current Assets | 433,734 |
| | 443,642 |
| 439,450 |
| | 388,718 |
|
| Regulatory and Other Assets | | | | | | |
| Regulatory Assets—Noncurrent | 186,626 |
| | 178,330 |
| 146,281 |
| | 141,030 |
|
| Derivative Instruments | 259 |
| | 1,354 |
| 167 |
| | 167 |
|
| Other Assets | 17,525 |
| | 15,869 |
| 19,364 |
| | 19,233 |
|
| Total Regulatory and Other Assets | 204,410 |
| | 195,553 |
| 165,812 |
| | 160,430 |
|
| Total Assets | $ | 3,594,140 |
| | $ | 3,461,046 |
| $ | 3,643,855 |
| | $ | 3,563,285 |
|
See Notes to Condensed Consolidated Financial Statements.
(Continued)
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
| | | | September 30, | | December 31, | March 31, | | December 31, |
| | 2013 | | 2012 | 2014 | | 2013 |
| | (Unaudited) | (Unaudited) |
| | Thousands of Dollars | Thousands of Dollars |
| CAPITALIZATION AND OTHER LIABILITIES | | | | | | |
| Capitalization | | | | | | |
| Common Stock Equity | $ | 939,721 |
| | $ | 860,927 |
| $ | 935,600 |
| | $ | 925,923 |
|
| Capital Lease Obligations | 130,088 |
| | 262,138 |
| 73,984 |
| | 131,370 |
|
| Long-Term Debt | 1,223,536 |
| | 1,223,442 |
| 1,372,278 |
| | 1,223,070 |
|
| Total Capitalization | 2,293,345 |
| | 2,346,507 |
| 2,381,862 |
| | 2,280,363 |
|
| Current Liabilities | | | | | | |
| Current Obligations Under Capital Leases | 169,060 |
| | 90,583 |
| 163,159 |
| | 186,056 |
|
| Accounts Payable—Trade | 75,834 |
| | 82,122 |
| 79,515 |
| | 88,556 |
|
| Accounts Payable—Due to Affiliates | 2,981 |
| | 3,134 |
| 5,172 |
| | 9,153 |
|
| Accrued Taxes Other than Income Taxes | 50,465 |
| | 33,060 |
| 44,433 |
| | 34,485 |
|
| Accrued Employee Expenses | 22,937 |
| | 20,715 |
| 19,941 |
| | 24,454 |
|
| Regulatory Liabilities—Current | | 26,756 |
| | 23,701 |
|
| Accrued Interest | 20,503 |
| | 26,965 |
| 20,071 |
| | 22,785 |
|
| Regulatory Liabilities—Current | 26,440 |
| | 20,822 |
| |
| Customer Deposits | 21,251 |
| | 24,846 |
| 21,542 |
| | 21,354 |
|
| Derivative Instruments | 7,060 |
| | 4,899 |
| 5,065 |
| | 5,531 |
|
| Other | 9,336 |
| | 7,085 |
| 12,032 |
| | 9,244 |
|
| Total Current Liabilities | 405,867 |
| | 314,231 |
| 397,686 |
| | 425,319 |
|
| Deferred Credits and Other Liabilities | | | | | | |
| Deferred Income Taxes—Noncurrent | 421,621 |
| | 319,216 |
| 426,801 |
| | 428,103 |
|
| Regulatory Liabilities—Noncurrent | 259,523 |
| | 241,189 |
| 268,826 |
| | 263,270 |
|
| Pension and Other Retiree Benefits | 132,491 |
| | 149,718 |
| 85,933 |
| | 84,936 |
|
| Derivative Instruments | 4,950 |
| | 10,565 |
| 5,468 |
| | 5,161 |
|
| Other | 76,343 |
| | 79,620 |
| 77,279 |
| | 76,133 |
|
| Total Deferred Credits and Other Liabilities | 894,928 |
| | 800,308 |
| 864,307 |
| | 857,603 |
|
| Commitments, Contingencies, and Environmental Matters (Note 4) |
| |
| |
| Commitments, Contingencies, and Environmental Matters (Note 6) | |
| |
|
| Total Capitalization and Other Liabilities | $ | 3,594,140 |
| | $ | 3,461,046 |
| $ | 3,643,855 |
| | $ | 3,563,285 |
|
See Notes to Condensed Consolidated Financial Statements.
(Concluded)
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY
|
| | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Capital Stock Expense | | Accumulated Earnings (Deficit) | | Accumulated Other Comprehensive Loss | | Total Stockholder’s Equity |
| | (Unaudited) Thousands of Dollars |
| Balances at December 31, 2012 | $ | 888,971 |
| | $ | (6,357 | ) | | $ | (12,157 | ) | | $ | (9,530 | ) | | $ | 860,927 |
|
| Comprehensive Income | | | | | | |
| | |
| 2013 Year-to-Date Net Income | | |
| | 96,433 |
| | | | 96,433 |
|
| Other Comprehensive Income, net of $(1,539) income taxes | | |
| |
| | 2,361 |
| | 2,361 |
|
| Total Comprehensive Income | | | | | | | | | 98,794 |
|
Dividends Paid | | | | | (20,000 | ) | | | | (20,000 | ) |
| Balances at September 30, 2013 | $ | 888,971 |
| | $ | (6,357 | ) | | $ | 64,276 |
| | $ | (7,169 | ) | | $ | 939,721 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Capital Stock Expense | | Accumulated Earnings | | Accumulated Other Comprehensive Loss | | Total Stockholder’s Equity |
| | (Unaudited) |
| | Thousands of Dollars |
| Balances at December 31, 2013 | $ | 888,971 |
| | $ | (6,357 | ) | | $ | 49,185 |
| | $ | (5,876 | ) | | $ | 925,923 |
|
| Net Income | | | | | 9,172 |
| | | | 9,172 |
|
| Other Comprehensive Income, net of tax | | | | | | | 505 |
| | 505 |
|
| Balances at March 31, 2014 | $ | 888,971 |
| | $ | (6,357 | ) | | $ | 58,357 |
| | $ | (5,371 | ) | | $ | 935,600 |
|
See Notes to Condensed Consolidated Financial Statements.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - Unaudited
NOTE 1. NATURE OF OPERATIONS AND FINANCIAL STATEMENT PRESENTATION
UNS Energy Corporation (UNS Energy) is a holding company that conducts its business through three regulated public utilities: Tucson Electric Power Company (TEP); UNS Electric, Inc. (UNS Electric); and UNS Gas, Inc. (UNS Gas); and UNS Electric, Inc. (UNS Electric). References to “we” and “our” are to UNS Energy and its subsidiaries, collectively.
We prepared our condensed consolidated financial statements according to generally accepted accounting principles in the United States of America (GAAP) and the Securities and Exchange Commission's (SEC) interim reporting requirements. These condensed consolidated financial statements exclude some information and footnotes required by GAAP and the SEC for annual financial statement reporting. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and footnotes in our 20122013 Annual Report on Form 10-K.
The condensed consolidated financial statements are unaudited, but, in management's opinion, include all recurring adjustments necessary for a fair presentation of the results for the interim periods presented. Because weather and other factors cause seasonal fluctuations in sales, our quarterly results are not indicative of annual operating results. UNS Energy and TEP reclassified certain amounts in the financial statements to conform to current year presentation.
REVISION OF PRIOR PERIOD BALANCE SHEETS
UNS ENERGY INCOME STATEMENT
During the first three quarters of 2012, we incorrectly reported UNS Electric's salesEnergy and purchase contracts which did not resultTEP revised their December 31, 2013 balance sheets to correct an error in the physical deliveryclassification of energy.capital lease obligations and related deferred income taxes. The transactions were reported on a gross basis rather than on a net basis. This error resulted in an equalcorrection increased current capital lease obligations and offsetting overstatement of Electric Wholesale Salesdecreased noncurrent capital lease obligations by $18 million and Purchased Energy inincreased current deferred tax assets and noncurrent deferred tax liabilities by $7 million. We do not believe the income statements of $3 million for the three months ended and $10 million for the nine months endedSeptember 30, 2012. This error had no impact on operating income, net income, accumulated earnings, or cash flows.
We assessed the impact of this error on prior period financial statements and concluded itmisclassification was not material to any period. However, this error was significant to individual income statement line items. As a result, in accordance with GAAP, we revised our prior period income statement as follows:
|
| | | | | | | | | | | | | | | |
| | UNS Energy |
| | Three Months Ended | | Nine Months Ended |
| | September 30, 2012 | | September 30, 2012 |
| | As Reported | | As Revised | | As Reported | | As Revised |
| | Thousands of Dollars | | Thousands of Dollars |
| Income Statement | | | | | | | |
Electric Wholesale Sales | $ | 32,494 |
| | $ | 29,341 |
| | $ | 98,282 |
| | $ | 88,469 |
|
| Purchased Energy | 60,238 |
| | 57,085 |
| | 174,891 |
| | 165,078 |
|
| Total Fuel and Purchased Energy | 175,687 |
| | 172,534 |
| | 461,292 |
| | 451,479 |
|
| Total Operating Expenses | 330,852 |
| | 327,699 |
| | 914,428 |
| | 904,615 |
|
RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
In 2013, wethe first quarter of 2014, UNS Energy adopted authoritativeaccounting guidance that:
Requires disclosure related to offsetting derivative assets and derivative liabilities in accordance with GAAP. See Note 11.
Requires additional disclosures for amounts reclassified out of Accumulated Other Comprehensive Income (AOCI) by component. See Note 12.
Allowsrequires an entity to performrecognize and disclose in the financial statements its obligation from a qualitative analysisjoint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay and any additional amount the entity expects to determine if additional testing for impairmentpay on behalf of indefinite-lived intangible assets is required. Basedits co-obligors. The adoption of this guidance did not have a material impact on our qualitative analysis, wedisclosures, financial condition, results of operations, or cash flows.
impacts the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. Although adoption and prospective application of this guidance impacted how such items are classified on our balance sheets, such change was not material. Additionally, there were no material changes in our results of operations or cash flows.
NOTE 2. PENDING MERGER WITH FORTIS
On December 11, 2013, UNS Energy announced that it had no impairment indicatorentered into an agreement and plan of merger, subject to shareholder and required regulatory approvals, to be acquired by FortisUS Inc., a Delaware corporation (Fortis) for $60.25 per share of Common Stock in cash. Following the merger, UNS Energy will continue as our only indefinite-lived intangible assets, Renewablea wholly owned subsidiary of Fortis. The Board of Directors of each of UNS Energy Credits (RECs), are currently recoverableand Fortis Parent have approved the merger. UNS Energy's shareholders approved the merger in March 2014. In April 2014, the Federal Energy Regulatory Commission (FERC) approved the merger.
The merger is subject to the remaining closing conditions:
the expiration or termination of the applicable waiting period under the Renewable Energy Standard (RES)Hart-Scott-Rodino Antitrust Improvements Act of 1976, as we useamended;
approval of the RECsArizona Corporation Commission (ACC);
confirmation of review, without unresolved concerns, by the Committee on Foreign Investment in the United States; and
the absence of any injunction, order or other law prohibiting the merger.
The merger, if approved, is expected to comply withclose by the standard’s renewable resources requirements.
end of 2014.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
NOTE 2.3. REGULATORY MATTERS
RATES AND REGULATION
The Arizona Corporation Commission (ACC)ACC and the Federal Energy Regulatory Commission (FERC)FERC each regulate portions of the utility accounting practices and rates of TEP, UNS Gas,Electric, and UNS Electric.Gas. The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, and transactions with affiliated parties. The FERC regulates terms and prices of transmission services and wholesale electricity sales. The pending merger with Fortis is subject to approval by the ACC. The FERC approved the merger in April 2014.
2013 TEP RATE ORDERPurchased Power and Fuel Adjustment Clause
In June 2013,April 2014, the ACC issued the 2013 TEP Rate Order that resolved the rate case filed by TEP in July 2012 which was based onapproved a test year ended December 31, 2011. The 2013 TEP Rate Order approved new rates effective July 1, 2013.
The provisions of the 2013 TEP Rate Order include, but are not limited to:
an increase in non-fuel retail Base Rates of approximately $76 million over adjusted test year revenues;
an Original Cost Rate Base (OCRB) of approximately $1.5 billion and a Fair Value Rate Base (FVRB) of approximately $2.3 billion;
a return on equity of 10.0%, a long-term cost of debt of 5.18%, and a short-term cost of debt of 1.42%, resulting in a weighted average cost of capital of 7.26%;
a capital structure of approximately 43.5% equity, 56.0% long-term debt, and 0.5% short-term debt;
a 0.68% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $800 million);
a revision in depreciation rates from an average rate of 3.32% to 3.0% for generation and distribution plant, primarily due to revised estimates of asset removal costs, which will have the effect of reducing depreciation expense by approximately $11 million annually; and
an agreement by TEP to seek recovery of costs related to the Nogales transmission line from the FERC before seeking rate recovery from the ACC.
The 2013 TEP Rate Order also includes the following cost recovery mechanisms:
a new Purchased Power and Fuel Adjustment Clause (PPFAC) rate for TEP of 0.1 cents per kWh for the period May through September 2014 and 0.5 cents per kWh for the period October 2014 through March 2015. TEP's PPFAC rate was a credit of $0.0013880.14 cents per kWh effectivefor the period July 1, 2013.2013 through April 2014.
San Juan Mine Fire Insurance Proceeds
In September 2011, a fire at the underground mine providing coal to San Juan Generating Station (San Juan) caused interruptions to mining operations and resulted in increased fuel costs. The credit reflects2013 TEP Rate Order required TEP to defer incremental fuel costs of $10 million from recovery under the following:
| |
◦ | a one-time reduction in the PPFAC bank balance, recorded in June 2013 as an increase to fuel expense, of $3 million related to prior Sulfur Credits; and
|
| |
◦ | a transfer of $10 million, recorded in June 2013, from the PPFAC bank balance to a new regulatory asset to defer coal costs related to the San Juan mine fire. These costs will be eligible for recovery through the PPFAC upon final insurance settlement.
|
a modificationPPFAC pending final resolution of an insurance claim by the San Juan Coal Company and distribution of insurance proceeds to San Juan participants. In March 2014, TEP received the first installment of its portion of the PPFAC mechanisminsurance settlement proceeds of $5 million. The proceeds offset the deferred costs and are reflected in our cash flow statements as an other operating cash receipt.
Energy Efficiency Standards
TEP, UNS Electric, and UNS Gas are required to include recoveryimplement cost-effective Demand Side Management (DSM) programs to comply with the ACC's Energy Efficiency (EE) Standards. The EE Standards provide for a DSM surcharge to recover, from retail customers, the costs to implement DSM programs as well as a performance incentive. In the first quarter of generation-related lime costs offset by Sulfur Credits.2014, TEP recorded a DSM performance incentive of $2 million that is included in Electric Retail Sales in the UNS Energy and TEP income statements.
a Lost Fixed Cost Recovery Mechanism
The Lost Fixed Cost Recovery (LFCR) mechanism (LFCR) to recoverprovides recovery of certain non-fuel costs relatedthat would go unrecovered due to lost retail kWh sales as a result of implementing ACC approved energy efficiency programs and distributed generation targets.
During separate rate case proceedings in 2013, the ACC authorized LFCR mechanisms for TEP and UNS Electric, subject to a year-over-year cap of 1% of each company’s respective total retail revenues.
TEP and UNS Electric expect to file their first LFCR reports with the ACC on or before May 15, 2014. We expect the new LFCR rates to become effective on July 1, 2014, upon review by the ACC of verified lost retail kWh sales due to energy efficiency programs and distributed generation subject to ACC approvalimplemented in 2013.
TEP and a year-over-year cap of 1% of TEP's total retail revenues. TEP expects the LFCR rate, recovering 2013 costs, to be effective on July 1, 2014, upon approval of verified lost kWh sales by the ACC.
an Environmental Compliance Adjustor (ECA) mechanism to recover certain capital carrying costs to comply with government-mandated environmental regulations between rate cases. The ECA rate is capped at $0.00025 per kWh, which approximates 0.25% of TEP's total retail revenues, and will be charged to customers beginning in May 2014 for any qualifying costs incurred between August 2013 and December 2013.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
an energy efficiency provision which includes a 2013 calendar year budget to fund programs that support the ACC's Electric Energy Efficiency Standards, as well as a performance incentive.
PENDING UNS ELECTRIC RATE CASE
In December 2012, UNS Electric filed a rate case application withrecorded LFCR revenues of $5 million and $1 million, respectively, in the ACC as required by the ACC in UNS Electric's 2010 Rate Order. UNS Electric's rate filing was based on a test year ended June 30, 2012.
In September 2013, UNS Electric, the stafffirst quarter of the ACC, and certain other parties to UNS Electric's pending rate case proceeding entered into a settlement agreement (2013 UNS Electric Settlement Agreement). The 2013 UNS Electric Settlement Agreement requires the approval of the ACC before new rates can become effective.
The terms of the 2013 UNS Electric Settlement Agreement include, but are not limited to:
an increase in non-fuel retail Base Rates of approximately $3 million;
an OCRB of approximately $213 million and a FVRB of approximately $283 million;
a return on equity of 9.50% and a long-term cost of debt of 5.97% resulting in a weighted average cost of capital of 7.83%;
a 0.50% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $70 million); and
a capital structure of 52.6% equity and 47.4% long-term debt.
The 2013 UNS Electric Settlement Agreement also includes the following cost recovery mechanisms:
an LFCR mechanism to recover certain non-fuel costs2014 related to reductions in retail kWh sales lost due to energy efficiency programs and distributed generation; andgeneration implemented in 2013.
a Transmission Cost Adjustor (TCA). The TCA would allow more timely recoveryWe recognize LFCR revenue when verifiable regardless of transmission costs associated with servingwhen the lost retail customers.
UNS GAS PURCHASED GAS ADJUSTOR
In October 2013, the ACC approved an increase to the existing Purchased Gas Adjustor (PGA) credit from 4.5 cents per therm to 10 cents per thermkWh sales occur. LFCR revenue is included in order to reduce the over-collected PGA bank balance. The new PGA credit will be effective for the period November 1, 2013 through April 30, 2014. At September 30, 2013, the PGA bank balance was over-collected by $17 million on a billed-to-customer basis.
REGULATORY ASSETS AND LIABILITIES
The following table summarizes changes in regulatory assets and liabilities since December 31, 2012:
|
| | | | | | | | | | | | | | | |
| | September 30, 2013 | | December 31, 2012 |
| | UNS Energy | | TEP | | UNS Energy | | TEP |
| | Millions of Dollars |
| Regulatory Assets – Current | $ | 53 |
| | $ | 36 |
| | $ | 52 |
| | $ | 34 |
|
Regulatory Assets – Noncurrent (1) | 201 |
| | 187 |
| | 191 |
| | 178 |
|
Regulatory Liabilities – Current (2) | (57 | ) | | (26 | ) | | (44 | ) | | (21 | ) |
Regulatory Liabilities – Noncurrent (3) | (298 | ) | | (260 | ) | | (279 | ) | | (241 | ) |
| Total Net Regulatory Assets (Liabilities) | $ | (101 | ) | | $ | (63 | ) | | $ | (80 | ) | | $ | (50 | ) |
| |
(1)
| Regulatory Assets – Noncurrent increased reflecting a newly created regulatory asset primarily for the investment tax credit basis adjustment. See Note 6. This regulatory asset does not earn a return and will be recovered through future
|
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
rates. The increase is also related to the addition of deferred rate case costs that do not earn a return and will be recovered over a four year period.
| |
(2)
| Regulatory Liabilities – Current increased because purchased energy costs are over recovered following deferral of coal costs related to the San Juan mine fire, as discussed above. The regulatory asset related to these deferred costs does not earn a return and will be recovered at the time of the final insurance settlement. |
| |
(3)
| Regulatory Liabilities – Noncurrent increased due to the collection of amounts in rates for future asset removal costs that have not yet been expended. |
FUTURE IMPLICATIONS OF DISCONTINUING APPLICATION OF REGULATORY ACCOUNTING
If our regulated operations no longer met the requirements to apply regulatory accounting we would remove our regulatory assets and liabilities by:
writing off the remaining regulatory assets as an expense and regulatory liabilities as incomeElectric Retail Sales in the income statements; and
reflecting regulatory pension assets as part of AOCI.
If we had stopped applying regulatory accounting at September 30, 2013:
TEP would have recorded an extraordinary after-tax gain of $113 million and an after-tax loss in AOCI of $75 million;
UNS Gas would have recorded an extraordinary after-tax gain of $26 million and an after-tax loss in AOCI of $2 million; and
UNS Electric would have recorded an extraordinary after-tax gain of $3 million and an after-tax loss in AOCI of $3 million.
While future regulatory orders and market conditions may affect cash flows, our cash flows would not be affected if we stopped applying regulatory accounting to our regulated operations.statements.
NOTE 3.4. BUSINESS SEGMENTS
We have three reportable segments regularly reviewed by our chief operating decision makers to evaluate performance and make operating decisions.
| |
| (1) | TEP, a regulated electric utility and our largest subsidiary |
| |
| (2) | UNS Gas, a regulated gas distribution utility |
| |
(3) | UNS Electric, a regulated electric utility |
We disclose selected financial data for our reportable segments in the following table:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Reportable Segments | | | | | | |
| | TEP | | UNS Gas | | UNS Electric | | Non-Reportable Segments | | Reconciling Adjustments | | UNS Energy Consolidated |
| | Millions of Dollars |
| Income Statement | |
| Three Months Ended September 30, 2013 | |
| Operating Revenues – External | $ | 367 |
| | $ | 16 |
| | $ | 54 |
| | $ | — |
| | $ | — |
| | $ | 437 |
|
Operating Revenues – Intersegment(1) | 4 |
| | 2 |
| | — |
| | 4 |
| | (10 | ) | | — |
|
| Net Income | 64 |
| | (1 | ) | | 5 |
| | — |
| | — |
| | 68 |
|
| | | | | | | | | | | | |
| Three Months Ended September 30, 2012 | | | | | | | | | | | |
| Operating Revenues – External | $ | 362 |
| | $ | 16 |
| | $ | 56 |
| | $ | — |
| | $ | — |
| | $ | 434 |
|
Operating Revenues – Intersegment(1) | 5 |
| | 2 |
| | — |
| | 5 |
| | (12 | ) | | — |
|
| Net Income | 45 |
| | — |
| | 6 |
| | — |
| | — |
| | 51 |
|
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
| |
| (3) | UNS Gas, a regulated gas distribution utility |
We disclose selected financial data for our reportable segments in the following tables:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Reportable Segments | | | | | | |
| | TEP | | UNS
Gas | | UNS
Electric | | Non-Reportable Segments | | Reconciling
Adjustments | | UNS
Energy
Consolidated |
| | Millions of Dollars |
| Income Statement | |
| Nine Months Ended September 30, 2013 | |
| Operating Revenues – External | $ | 910 |
| | $ | 90 |
| | $ | 134 |
| | $ | — |
| | $ | — |
| | $ | 1,134 |
|
Operating Revenues – Intersegment(1) | 13 |
| | 3 |
| | 1 |
| | 12 |
| | (29 | ) | | — |
|
| Net Income | 96 |
| | 6 |
| | 11 |
| | 1 |
| | — |
| | 114 |
|
| | | | | | | | | | | | |
| Nine Months Ended September 30, 2012 | | | | | | | | | | | |
| Operating Revenues – External | $ | 877 |
| | $ | 89 |
| | $ | 147 |
| | $ | — |
| | $ | — |
| | $ | 1,113 |
|
Operating Revenues – Intersegment(1) | 13 |
| | 4 |
| | 1 |
| | 14 |
| | (32 | ) | | — |
|
| Net Income | 65 |
| | 5 |
| | 14 |
| | (1 | ) | | — |
| | 83 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Reportable Segments | | | | | | |
| | TEP | | UNS Electric | | UNS Gas | | Other (2) | | Reconciling Adjustments | | UNS Energy |
| | Millions of Dollars |
| Three Months Ended March 31, 2014: | | | | | | | | | | | |
| Operating Revenues-External | $ | 252 |
| | $ | 40 |
| | $ | 41 |
| | $ | — |
| | $ | — |
| | $ | 333 |
|
Operating Revenues-Intersegment (1) | 4 |
| | 1 |
| | — |
| | 4 |
| | (9 | ) | | — |
|
| Income Before Income Taxes | 15 |
| | 3 |
| | 8 |
| | (1 | ) | | — |
| | 25 |
|
| Net Income | 9 |
| | 2 |
| | 5 |
| | (1 | ) | | — |
| | 15 |
|
| | | | | | | | | | | | |
| Three Months Ended March 31, 2013: | | | | | | | | | | | |
| Operating Revenues-External | $ | 244 |
| | $ | 36 |
| | $ | 52 |
| | $ | — |
| | $ | — |
| | $ | 332 |
|
Operating Revenues-Intersegment (1) | 4 |
| | 1 |
| | — |
| | 4 |
| | (9 | ) | | — |
|
| Income Before Income Taxes | 3 |
| | 4 |
| | 12 |
| | — |
| | — |
| | 19 |
|
| Net Income | 1 |
| | 2 |
| | 8 |
| | — |
| | — |
| | 11 |
|
| |
(1) | Operating Revenues – Intersegment: TEPRevenues-Intersegment includes control area services provided to UNS Electric based on a FERC-approved tariff; common costs (systems,(system, facilities, etc.) allocated to affiliates on a cost-causative basis;basis and recorded as revenue by TEP, sales of power tobetween TEP and UNS Electric at third-party market prices. Other primarily includes meter readingprices, control area services provided by TEP to UNS Electric based on a FERC-approved tariff, sales of gas by UNS Gas at third-party market prices for use in UNS Electric's generating facilities, and supplemental workforce charges (primarily meter reading services) provided to the utilities by an unregulated affiliate toaffiliate. |
| |
(2) | Other includes the utilities.UNS Energy and UES holding companies, Millennium, and UED. |
NOTE 5. DEBT AND CAPITAL LEASE OBLIGATIONS
We summarize below the significant changes to our debt and capital lease obligations from those reported in our 2013 Annual Report on Form 10-K.
2014 TEP UNSECURED NOTES ISSUED
In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. TEP may call the debt prior to September 15, 2043, with a make-whole premium plus accrued interest. After September 15, 2043, TEP may call the debt at par plus accrued interest. TEP used the net proceeds to repay approximately $90 million on the revolving credit facility, with the remaining proceeds to be applied to general corporate purposes. The unsecured notes contain a limitation on the amount of secured debt that TEP may have outstanding.
COVENANT COMPLIANCE
At March 31, 2014, we were in compliance with the terms of our loan and credit agreements.
TEP SPRINGERVILLE COAL HANDLING FACILITIES CAPITAL LEASE PURCHASE COMMITMENT
In April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase their undivided ownership interests in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million upon the expiration of the lease term in April 2015. Due to TEP’s purchase commitment, TEP will record, in the second quarter of 2014, an increase to both Utility Plant Under Capital Leases and Capital Lease Obligations on its balance sheet in the amount of $109 million.
TEP previously agreed with Tri-State Generation and Transmission Association, Inc. (Tri-State), the lessee of Springerville Unit 3, and Salt River Project Agricultural Improvement and Power District (SRP), the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities Leases were not renewed, TEP would exercise the purchase option under those contracts. Upon TEP's purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State is obligated to either 1) buy a portion of the facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
NOTE 4.6. COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL MATTERS
COMMITMENTS
UNS Energy's commitments represent the obligations of TEP, UNS Electric, and UNS Gas. In addition to those reported in our 20122013 Annual Report on Form 10-K, weUNS Energy entered into the following new long-term commitments through September 30, 2013:March 31, 2014: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | UNS Energy Purchase Commitments |
| | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | Thereafter | | Total |
| | Millions of Dollars |
| Fuel, including Transportation | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Purchased Power | — |
| | 15 |
| | — |
| | — |
| | — |
| | — |
| | 15 |
|
| Total Purchase Commitments | $ | — |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 16 |
|
TEP entered into the following long-term commitments: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | TEP Purchase Commitments |
| | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | Thereafter | | Total |
| | Millions of Dollars |
| Purchased Power | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 5.
TEP COMMITMENTSCONTINGENCIES
Planned Purchase of Gas-Fired Generation Facility |
| | | | | | | | | | | | | | | | | | | | | |
| | Purchase Commitments |
| | 2013 | 2014 | 2015 | 2016 | 2017 | Thereafter | Total |
| | Millions of Dollars |
Purchased Power, Including Renewable PPA(1) | $ | 2 |
| $ | 18 |
| $ | 6 |
| $ | 4 |
| $ | 4 |
| $ | 58 |
| $ | 92 |
|
Capital Lease Obligations(2) | — |
| — |
| 46 |
| — |
| — |
| — |
| 46 |
|
RES Performance-Based Incentives(3) | 1 |
| 1 |
| 1 |
| 1 |
| 1 |
| 7 |
| 12 |
|
Fuel Transportation(4) | 4 |
| 5 |
| 5 |
| 5 |
| 5 |
| 1 |
| 25 |
|
| Total Purchase Commitments | $ | 7 |
| $ | 24 |
| $ | 58 |
| $ | 10 |
| $ | 10 |
| $ | 66 |
| $ | 175 |
|
| |
(1)
| Purchased Power costs are recoverable from customers through the PPFAC. A portion of the Renewable Power Purchase Agreement (PPA) is recoverable through the PPFAC, with the balance recoverable through the RES tariff. |
| |
(2)
| In the thirdIn 2013, TEP and fourth quarters of 2013, TEP entered into agreements to purchase certain Springerville Unit 1 leased interests. See Note 5.
|
| |
(3)
| The RES Performance-Based Incentive (PBI) costs are recoverable through the RES tariff. |
| |
(4)
| Fuel Transportation costs are recoverable from customers through the PPFAC. |
UNS GAS COMMITMENTS
Forward Energy Contracts
UNS Gas entered into new forward energy commitments that settle through 2016 at fixed prices per million British thermal units (MMBtu). UNS Gas’ minimum payment obligations for these purchases are $2 million in 2014, $3 million in 2015, and $2 million in 2016.
Fuel Transportation
UNS Gas entered into revised gas transportation agreements in August 2013. UNS Gas anticipates that its commitments will increase by $3 million in 2013, $9 million each year in 2014 through 2016, $10 million in 2017, and $56 million thereafter.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
UNS ELECTRIC COMMITMENTS
Purchased Power Contracts
UNS Electric entered into new forward purchased power commitments that will settle through 2015 at fixed prices per MWh. UNS Electric’s minimum payment obligations for these purchases are $1 million in 2014 and $4 million in 2015.
TEP CONTINGENCIESan agreement to purchase a gas-fired generation facility. See Note 7.
Claim Related to San Juan Generating Station
San Juan Coal Company (SJCC) operates an underground coal mine in an area where certain gas producers have oil and gas leases with the federal government, the State of New Mexico, and private parties. These gas producers allege that SJCC’s underground coal mine interferes with their operations, reducing the amount of natural gas they can recover. SJCC compensated certain gas producers for any remaining production from wells deemed close enough to the mine to warrant plugging and abandoning them. These settlements, however, do not resolve all potential claims by gas producers in the area. TEP owns 50% of Units 1 and 2 at San Juan Generating Station (San Juan), which represents approximately 20% of the total generation capacity at San Juan, and is responsible for its share of any settlements. TEP cannot estimate the impact of any future claims by these gas producers on the cost of coal at San Juan.
In August 2013, the Bureau of Land Management (BLM) proposed regulations that, among other things, redefine the term “underground mine” to exclude high-wall mining operations and impose a higher surface mine coal royalty on high-wall mining. SJCC utilized high-wall mining techniques at its surface mines prior to beginning underground mining operations in January 2003. If the proposed regulations become effective, SJCC may be subject to additional royalties on coal delivered to San Juan between August 2000 and January 2003 totaling approximately $5 million of which TEP’s proportionate share would approximate $1 million. TEP cannot predict the final outcome of the BLM’s proposed regulations.
Claims Related to Four Corners Generating Station
In October 2011, EarthJustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against Arizona Public Service Company (APS) and the other Four Corners Generating Station (Four Corners) participants alleging violations of the Prevention of Significant Deterioration (PSD) provisions of the Clean Air Act at Four Corners. In January 2012, EarthJustice amended their complaint alleging violations of New Source Performance Standards resulting from equipment replacements at Four Corners. Among other things, the plaintiffs seek to have the court issue an order to cease operations at Four Corners until any required PSD permits are issued and order the payment of civil penalties, including a beneficial mitigation project. In April 2012, APS filed motions to dismiss with the court for all
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
claims asserted by EarthJustice in the amended complaint. All parties filed aThe joint motionparticipants have agreed to stayhave the matter stayed until December 1, 2013.May 15, 2014 in furtherance of settlement talks.
TEP owns 7% of Four Corners Units 4 and 5 and is liable for its share of any resulting liabilities. TEP cannot predict the final outcome of the claims relating to Four Corners, and, due to the general and non-specific nature of the claims and the indeterminate scope and nature of the injunctive relief sought for this claim, TEP cannot determine estimates of the range of loss at this time. TEP accrued estimated losses of less than $1 million in 2011 for this claim based on its share of a settlement offer to resolve the claim.
In May 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance tax, penalties, and interest totaling $30 million to the coal supplier at Four Corners. TheIn December 2013, the coal supplier and Four Corners’ operating agent intend to contestfiled a claim contesting the validity of the assessment on behalf of the participants in Four Corners, who will be liable for their share of any resulting liabilities. TEP’s share of the assessment based on its ownership of Four Corners is approximately $1 million. TEP cannot predict the outcome or timing of resolution of this claim.
Mine Closure Reclamation at Generating Stations Not Operated by TEP
TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which TEP has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of the mines servicing Navajo, San Juan, and Four Corners. TEP’s share of reclamation costs at all three mines is expected to be $27$44 million upon expiration of the coal supply agreements, which expire between 20162017 and 2019.2031. The reclamation liability (present value of future liability) recorded was $19 million at March 31, 2014 and $18 million at September 30, 2013 and $16 million at December 31, 20122013.
Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the credit-adjusted risk-free interest rate to be used to discount future liabilities. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements’ terms. TEP does not believe that recognition of its final reclamation obligations will be material to TEP in any single year because recognition will occur over the remaining terms of its coal supply agreements.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
TEP’s PPFAC allows us to pass through most fuel costs, including final reclamation costs, to customers. Therefore, TEP classifies these costs as a regulatory asset by increasing the regulatory asset and the reclamation liability over the remaining life of the coal supply agreements on an accrual basis and recoveringrecovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.
Tucson to NogalesDiscontinued Transmission LineProject
TEP and UNS Electric are parties tohad initiated a project development agreement for the joint construction ofto jointly construct a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona. This project was initiatedArizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. TEP and UNS Electric expect to abandonwill not proceed with the project based on the cost of the proposed 345-kV line, the difficulty in reaching agreement with the United States Forest Service on a path for the line, and concurrence by the ACC of recent transmission plans filed by TEP and UNS Electric supporting elimination of this project. As part of the 2013 TEP Rate Order, TEP agreed to seek recovery of the project costs from FERC before seeking rate recovery from the ACC. See Note 2. In 2012, TEP wrote off $5 million of the capitalized costs believed not probable of recovery and recorded a regulatory asset of $5 million and UNS Electric recorded a regulatory asset of $0.2 millionfor the balance deemed probable of recovery.
RESOLUTION OFPerformance Guarantees
The participants in each of the remote generating stations in which TEP participates, including TEP, have guaranteed certain performance obligations of the other participants. Specifically, in the event of payment default of a participant, the non-defaulting participants have agreed to bear a proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generating capacity of the defaulting participants. TEP's joint participation agreements expire in 2016 through 2046.
UNS ELECTRIC CONTINGENCIES
Springerville Generating Station Unit 3 OutagePlanned Purchase of Gas-Fired Generation Facility
In 2013, TEP paid Tri-State Generating and Transmission Association, Inc. (Tri-State) $2 million in March 2013 asUNS Electric entered into an agreement to purchase a resultgas-fired generation facility. See Note 7.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
ENVIRONMENTAL MATTERS
Environmental Regulation
The Environmental Protection Agency (EPA) limits the amount of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter, mercury and other emissions released into the atmosphere by power plants. TEP may incur added costs to comply with future changes in federal and state environmental laws, regulations, and permit requirements at its power plants. Complying with these changes may reduce operating efficiency. TEP expects to recover the cost of environmental compliance from its ratepayers.
Hazardous Air Pollutant Requirements
The Clean Air Act requires the EPA to develop emission limit standards for hazardous air pollutants that reflect the maximum achievable control technology. In February 2012, the EPA issued final rules to set the standards for the control of mercury emissions and other hazardous air pollutants from power plants.
Navajo
Based on the EPA’s standards, Navajo may require mercuryEPA's final Mercury and particulate matterAir Toxics (MATS) rules, additional emission control equipment will be required by April 2015. TEP’sThe operator of Navajo has received an extension until April 2016 to comply with the MATS rules. TEP's share of the estimated capital cost of this equipment is less than $1 million for mercury control and about $43 million ifcosts to comply with the installation of baghouses to control particulates is necessary. The operator of Navajo is currently analyzingMATS rules include the need for baghouses under various regulatory scenarios, which will be affected by final Best Available Retrofit Technology (BART) rules when issued. TEP expects its share of the annual operating costs for mercury control and baghouses to be less than $1 million each.following:
|
| | | | | | | | | | | |
| Estimated Mercury Emissions Control Costs: | Navajo | | Four Corners | | Springerville |
| | Millions of Dollars |
| Capital Expenditures | $ | 1 |
| | $ | 1 |
| | $ | 5 |
|
| Annual O&M Expenses | 1 |
| | 1 |
| | 3 |
|
TEP expects Sundt and San Juan’sJuan's current emission controls to be adequate to comply with the EPA’s final standards.
Four Corners
Based on the EPA’s final standards, Four Corners may require mercury emission control equipment by 2015. TEP's share of the estimated capital cost of this equipment is less than $1 million. TEP expects its share of the annual operating cost of the mercury emission control equipment to be less than $1 million.
Springerville Generating Station
Based on the EPA’s final standards, Springerville Generating Station (Springerville) may require mercury emission control equipment by 2015. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5 million. TEP expects the annual operating cost of the mercury emission control equipment to be about $3 million.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
Sundt Generating Station
TEP expects the final EPA standards will have little effect on capital expenditures at Sundt Generating Station (Sundt).EPA's MATS rules.
Regional Haze Rules
The EPA's Regional Haze Rules require emission controls known as BARTBest Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility.visibility in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas.visibility. States must submit these goals and strategies to the EPA for approval. Because Navajo and Four Corners are located on the Navajo Indian Reservation, they are not subject to state oversight. Theoversight; the EPA oversees regional haze planning for these power plants.
In the western U.S., Regional Haze BART determinations have focused on controls for NOx, often resulting in a requirement to install selective catalytic reduction (SCR). Complying with the EPA’s BART findings,rules, and with other future environmental rules, may make it economically impractical to continue operating the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. TEP cannot predict the ultimate outcome of these matters.
NavajoTEP's estimated costs involved in meeting these rules are:In January 2013, the EPA proposed a BART determination that would require the installation of Selective Catalytic Reduction (SCR) technology on all three units at Navajo by 2023. In July 2013, SRP, along with other stakeholders including impacted government agencies, environmental organizations, and tribal representatives, submitted an agreement to the EPA that would achieve greater NOx emission reductions than the EPA's proposed BART rule. In September 2013, EPA issued a supplemental proposal incorporating the provisions of the agreement as a better-than-BART alternative. |
| | | | | | | | | | | | | | | |
| Estimated NOx Emissions Control Costs: | Navajo (1) | | San Juan (2) | | Four Corners (3) | | Sundt (4) |
| | Millions of Dollars |
| Capital Expenditures | $ | 42 |
| | $ | 35 |
| | $ | 35 |
| | $ | 12 |
|
| Annual O&M Expenses | 1 |
| | 1 |
| | 2 |
| | 5-6 |
|
Among other things, the agreement calls for the shut down of one unit or an equivalent reduction in emissions by | |
(1)2020. The shutdown of one unit will not impact the total amount of energy delivered to TEP from Navajo. Additionally, the remaining Navajo participants would be required to install SCR or an equivalent technology on the remaining two units by 2030. As part of the agreement, the current owners have committed to cease their operation of conventional coal-fired generation at Navajo no later than December 2044. The Navajo Nation can continue operation after 2044 at its election. If SCR technology is ultimately implemented at Navajo, TEP estimates its share of the capital cost will be $42 million. Also, the installation of SCR technology at Navajo could increase the power plant's particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be about $43 million. TEP's share of annual operating costs for SCR and baghouses is estimated at less than $1 million each. San Juan
In August 2011, the EPA issued a Federal Implementation Plan (FIP) establishing new emission limits for air pollutants at San Juan. These requirements are more stringent than those proposed by the State of New Mexico. The FIP requires the installation of SCR technology with sorbent injection on all four units to reduce NOx and control sulfuric acid emissions by September 2016. TEP estimates its share of the cost to install SCR technology with sorbent injection to be between $180 million and $200 million. TEP expects its share of the annual operating costs for SCR technology to be approximately $6 million.
In 2011, Public Service Company of New Mexico (PNM) filed a petition for review of, and a motion to stay, the FIP with the United States Court of Appeals for the Tenth Circuit (Tenth Circuit). In addition, the operator filed a request for reconsideration of the rule with the EPA and a request to stay the effectiveness of the rule pending the EPA's reconsideration and review by the Tenth Circuit. The State of New Mexico filed similar motions with the Tenth Circuit and the EPA. Several environmental groups were granted permission to join in opposition to PNM's petition to review in the Tenth Circuit. In addition, WildEarth Guardians filed a separate appeal against the EPA challenging the FIP's five-year implementation schedule. PNM was granted permission to join in opposition to that appeal. In March 2012, the Tenth Circuit denied PNM's and the State of New Mexico's motion for stay. Oral argument on the appeal was heard in October 2012 and the parties are currently awaiting the court's decision. In February 2013, the Tenth Circuit referred the litigation to the Tenth Circuit Mediation Office, which has authority to require the parties to attend mediation conferences to informally resolve issues in the pending appeals.
In February 2013, the State of New Mexico, the EPA, and PNM signed a non-binding agreement that outlines an alternative to the FIP. The terms of the agreement include: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement by PNM of those units with non-coal generation sources; and the installation of Selective Non-Catalytic Reduction technology (SNCR) on San Juan Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. The New Mexico Environmental Department (NMED) prepared a revision to the regional haze SIP incorporating the provisions of the agreement, and in September 2013, the New Mexico Environmental Improvement Board approved the SIP revision. The SIP revision now awaits final EPA approval.
| The EPA is considering a better-than-BART plan wherein: one unit at Navajo will be shut down by 2020; SCR (or the equivalent) will be installed on the remaining two units by 2030; and conventional coal-fired generation will cease by December 2044. TEP expects the EPA to reach a decision in 2014. In addition, the installation of SCR technology could increase particulates which may require that baghouses be installed. TEP owns 7.5% of Navajo. TEP's share of the capital cost of baghouses in addition to the SCR costs reflected in the table above is approximately $43 million with O&M on the baghouses expected to be less than $1 million per year. |
| |
(2) | The Federal Implementation Plan (FIP) for San Juan requires SCRs for which TEP estimates its share of capital costs will be $180-$200 million with annual O&M of $6 million. As part of a proposal for an alternative, Public Service Company of New Mexico (PNM), the State of New Mexico, and the EPA signed a non-binding agreement in which PNM agreed to close Units 2 and 3 by December 31, 2017 and install selective non-catalytic reduction (SNCR) on Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. These estimated costs are reflected in the table above. The State of New Mexico has submitted this plan to the EPA for approval. TEP expects the EPA will reach a decision in 2014. TEP owns 50% of San Juan Unit 2. At March 31, 2014, the net book value of TEP's share in San Juan Unit 2 was $112 million. If Unit 2 is retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit. |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
| |
(3) | In December 2013, APS, on behalf of the co-owners of Four Corners, notified the EPA that they have chosen an alternative BART compliance strategy; as a result, APS closed Units 1, 2, and 3 in December 2013 and has agreed to the installation of SCR on Units 4 & 5 by July 31, 2018. TEP owns 7% of Four Corners Units 4 and 5. |
(4) In January 2014, the EPA issued a proposal that would require TEP estimates its share of the cost to either (i) install SNCR and dry sorbent injection technology on San Juan Unit 14 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. Under the proposal, TEP would be approximately $35 million. TEP's sharerequired to notify the EPA of incremental annual operating costs for SNCRits decision by July 31, 2015. The EPA is estimated at $1 million. TEP owns 340 MW, or 50%, of San Juan Units 1 and 2.expected to issue a final BART determination by July 2014. At September 30, 2013,March 31, 2014, the net book value of TEP's share of San Juan Unit 2the Sundt coal handling facilities was $114 million.$27 million. If Unit 2 isthe coal handling facilities are retired early, we expectTEP expects to request ACC approval to recover, over a reasonable time period, all costs associated with the early closureremaining costs of the unit. We are evaluating various replacement resources. Any decision regarding early closure and replacement resources will require various actions by third parties as well as UNS Energy board and regulatory approvals. TEP cannot predict the ultimate outcome of this matter.coal handling facilities.
Four Corners
In August 2012, the EPA finalized the regional haze FIP for Four Corners. The final FIP requires SCR technology to be installed on all five units by 2017. However, the FIP also includes an alternative plan that allows APS to close their wholly-owned Units 1, 2, and 3 and install SCR technology on Units 4 and 5. This option allows the installation of SCR technology to be delayed until July 2018. APS must select which FIP alternative to implement by December 31, 2013. In either case, TEP's estimated share of the capital costs to install SCR technology on Units 4 and 5 is approximately $35 million. TEP's share of incremental annual operating costs for SCR is estimated at $2 million.
Springerville
The BART provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville. Other provisionsSpringerville because the plant was built after the BART-applicable dates.
NOTE 7. PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY
On December 23, 2013, TEP and UNS Electric entered into a purchase agreement with a subsidiary of the Regional Haze Rule requiring further emission reduction are not likelyEntegra to impact Springerville operations until after 2018.
Sundt
In July 2013, the EPA rejected the Arizona state implementation plan determination that Sundtpurchase Gila River Generating Station Unit 4 is not3 for $219 million, subject to the BART provisions of the Regional Haze Rule. Under the Regional Haze Rule, Sundtcertain closing adjustments. Gila River Unit 4 will be required to reduce certain emissions within five years of the final EPA BART determination. The EPA postponed its expected release of3, a proposed BART requirement for Sundt Unit 4 until December 2013,gas-fired combined cycle unit with a final determination expected in May 2014. While TEP does not agree that Sundt Unit 4 is BART eligible, in anticipation of EPA's proposed BART requirements, TEP has submitted a plan for EPA approval proposing to eliminate coal as a fuel after December 2017.
Greenhouse Gas Regulation
In June 2013, President Obama directed the EPA to move forward with carbon emission regulations for both new and existing fossil-fueled power plants.
In September 2013, the EPA issued a re-proposed rule for new power plants. UNS Energy does not anticipate that a final rule related to new fossil-fueled power plant sources will have a significant impact on operations.
For existing power plants, the President ordered the EPA to:
propose carbon emission standards by June 1, 2014;
finalize those standards by June 1, 2015; and
require states to submit their implementation plans to meet the standards by June 30, 2016.
UNS Energy will continue to work with federal and state regulatory agencies to promote compliance flexibility in the rules impacting existing fossil-fuel fired power plants. We cannot predict the ultimate outcome of these matters.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
NOTE 5. DEBT, CREDIT FACILITIES, AND CAPITAL LEASE OBLIGATIONS
We summarize below the significant changes to our debt and capital lease obligations from those reported in our 2012 Annual Report on Form 10-K.
TEP SPRINGERVILLE UNIT 1 CAPITAL LEASE PURCHASE COMMITMENTS
In 2011, TEP and the owner participants of Springerville Unit 1 completed a formal appraisal procedure to determine the fair market value purchase price of Springerville Unit 1 in accordance with the Springerville Unit 1 Leases. The purchase price was determined to be $478 per kW of capacity based on a continuousnominal capacity rating of 387 MW. The appraisal price was challenged, and550 MW, is located in Gila Bend, Arizona. TEP initiated a proceeding in 2012 seeking judicial confirmation of the results of the appraisal process.
In August 2013, TEP electedexpects to purchase leased interests comprising 24.8% of Springervillea 75% undivided interest in Gila River Unit 1, representing 96 MW of continuous operating capability,3 (413 MW) for an aggregate purchase price of $46approximately $164 million,, the appraised value, upon the expiration of the lease term in January 2015.
In October 2013, TEP elected and UNS Electric expects to purchase an additional 10.6% leasedthe remaining 25% undivided interest in Springerville Unit 1, representing 41 MW of continuous operating capability,(137 MW) for $20 million, the appraised value, with the purchase scheduled to occur in December 2014.
Upon close of these lease option purchases, TEP will own 49.5% of Springerville Unit 1, or 192 MW of continuous operating capability. Due to TEP's purchase commitment,approximately $55 million. TEP and UNS EnergyElectric expect the transaction to recordclose in December 2014, subject to regulatory approvals and other closing conditions. In December 2013, UNS Electric filed an increaseapplication for an accounting order with the ACC requesting authorization for UNS Electric to defer for future recovery specific non-fuel operating costs associated with Gila River Unit 3.
TEP expects to provide, in the second quarter of approximately $552014, a letter of credit (LOC) for $15 million to both Utility Plant Under Capital Leases and Capital Lease Obligations on their balance sheets, of which $39 million is reflected as of September 30, 2013.
Because the owner participants whose leased interests TEP elected to purchase have agreed to sell their interests for amounts equal to the appraised value, TEP dismissed the legal action associated with the appraisal.
TEP TAX-EXEMPT BONDS ISSUED
In March 2013, the Industrial Development Authorityseller of Pima County, Arizona issued approximately $91 million aggregate principal amount of unsecured tax-exempt industrial development bonds on behalf of TEP. The bonds bear interest atGila River Unit 3 to satisfy a fixed rate of 4.0%, mature in September 2029, and may be redeemed at par on or after March 1, 2023. The proceeds from the salecondition of the bonds, together with $0.5 million accrued interest provided by TEP, were deposited with a trusteepurchase agreement. The seller would be entitled to retire approximately $91 million of 6.375% unsecured tax-exempt bonds in April 2013. TEP’s payment of accrued interest wasdraw upon the only cash flow activity since proceeds fromLOC and apply such amount as liquidated damages if it has validly terminated the newly-issued bonds were not received nor disbursed by TEP. TEP capitalized approximately $1 million in costs related to the issuance of the bonds and will amortize the costs to Interest Expense – Long-Term Debt in the income statement through September 2029, the term of the bonds.
UNS ENERGY'S AND TEP'S CREDIT RATING UPGRADES
In June 2013, the pricing under certain debt agreements improvedpurchase agreement as a result of an upgrade inmisrepresentations by TEP and UNS Electric or the credit ratingsfailure of TEP and UNS Energy and TEP.
UnderElectric to close the UNS Energy Credit Agreement,transaction when the interest rate decreased from London Interbank Offered Rate (LIBOR) plus 1.75% to LIBOR plus 1.5%;
Underclosing conditions have been satisfied. Upon the TEP Credit Agreement, the interest rate decreased from LIBOR plus 1.125% to LIBOR plus 1.0% ; and the margin rate on the $186 million letter of credit facility decreased from 1.125% to 1.0% ; and
Under the 2010 TEP Reimbursement Agreement, fees payable on outstanding letters of credit decreased from 1.5% to 1.25% per annum.
TEP MORTGAGE INDENTURE
Prior to November 2013, the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement were secured by $423 million in mortgage bonds issued under the 1992 Mortgage. As a result of TEP's credit rating upgrade, in October 2013, TEP (i) requested $423 million in mortgage bonds be returned to TEP for cancellation, and (ii) discharged the 1992 Mortgage, which had created a lien on and security interest in substantially all of TEP’s utility plant assets. TEP’s obligations under the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement are now unsecured, which changed the pricingclose of the following agreements, with pricing tied to credit ratings for short-term borrowings:
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
Undertransaction, the TEP Credit Agreement, the interest rate increased from LIBOR plus 1.0% to LIBOR plus 1.25%; and the margin rate on the $186 million letter of credit facility increased from 1.0% to 1.25%; and
Under the 2010 TEP Reimbursement Agreement, fees payable on outstanding letters of credit increased from 1.25% to 1.75% per annum.
COVENANT COMPLIANCE
At September 30, 2013, we were in compliance with the terms of our credit agreements, the 2010 TEP Reimbursement Agreement, and UNS Electric's term loan.LOC would be canceled.
NOTE 6. INCOME TAXES
Income tax expense differs from the amount of income tax determined by applying the United States statutory federal income tax rate of 35% to pre-tax income due to the following:
|
| | | | | | | | | | | | | | | |
| | UNS Energy | | TEP |
| | Three Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | Millions of Dollars |
| Federal Income Tax Expense at Statutory Rate | $ | 38 |
| | $ | 29 |
| | $ | 36 |
| | $ | 25 |
|
| State Income Tax Expense, Net of Federal Deduction | 5 |
| | 3 |
| | 5 |
| | 3 |
|
| Federal/State Tax Credits | (1 | ) | | (1 | ) | | (1 | ) | | (1 | ) |
| Other | (1 | ) | | — |
| | (1 | ) | | — |
|
| Total Federal and State Income Tax Expense | 41 |
| | $ | 31 |
| | $ | 39 |
| | $ | 27 |
|
|
| | | | | | | | | | | | | | | |
| | UNS Energy | | TEP |
| | Nine Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | Millions of Dollars |
| Federal Income Tax Expense at Statutory Rate | $ | 58 |
| | $ | 47 |
| | $ | 48 |
| | $ | 37 |
|
| State Income Tax Expense, Net of Federal Deduction | 8 |
| | 6 |
| | 6 |
| | 4 |
|
| Federal/State Tax Credits | (2 | ) | | (1 | ) | | (2 | ) | | (1 | ) |
| Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset | (11 | ) | | — |
| | (11 | ) | | — |
|
| Other | (1 | ) | | (1 | ) | | 1 |
| | (1 | ) |
| Total Federal and State Income Tax Expense | $ | 52 |
| | $ | 51 |
| | $ | 42 |
| | $ | 39 |
|
Investment Tax Credit Basis Difference Adjustment
Renewable energy assets are eligible for investment tax credits. We reduce the income tax basis of those qualifying assets by half of the related investment tax credit. Historically, the difference between the income tax basis of the asset and the book basis under GAAP was recorded as a deferred tax liability with an offsetting charge to income tax expense in the year the qualifying asset was placed in service. In June 2013, we recorded a regulatory asset and corresponding reduction of income tax expense of $11 million to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. The regulatory asset will be amortized as income tax expense as the qualifying assets are depreciated.
Uncertain Tax Positions
We recognize tax benefits from uncertain tax positions if it is more likely than not that the tax position will be sustained on examination by the taxing authorities. Each uncertain tax position is recognized up to the amount most likely to be sustained on examination and adjusted with changes in facts and circumstances. A reconciliation of the beginning and ending balances of unrecognized tax benefits follows:
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
|
| | | | | | | |
| | UNS Energy | | TEP |
| | Millions of Dollars |
| Unrecognized Tax Benefits at December 31, 2012 | $ | 30 |
| | $ | 23 |
|
| Additions Based on Tax Positions Taken in the Current Year | 1 |
| | 1 |
|
| Reduction of Positions from Prior Year Based on Tax Authority Ruling | (27 | ) | | (22 | ) |
| Unrecognized Tax Benefits at September 30, 2013 | $ | 4 |
| | $ | 2 |
|
In February 2013, we received a favorable ruling from the Internal Revenue Service (IRS) allowing us to deduct up-front incentive payments to customers who install renewable energy resources. These customers transfer environmental attributes or RECs associated with their renewable installations to us over the expected life of the contract for an up-front incentive payment based on the generating capacity of their installation. As a result of the IRS ruling in the first quarter of 2013, UNS Energy reduced unrecognized tax benefits by $28 million, and TEP reduced unrecognized tax benefits by $22 million. The changes in tax benefits primarily affected the balance sheets.
The IRS completed its audit of the 2009 and 2010 tax returns in March 2013 resulting in no change to the financial statements.
In April 2013, the IRS provided notice of intent to audit the 2011 tax returns.
Tangible Repairs Regulation
In September 2013, the U.S. Treasury Department released final income tax regulations on the deduction and capitalization of expenditures related to tangible property. These final regulations apply to tax years beginning on or after January 1, 2014. Several of the provisions within the regulations will require a tax accounting method change to be filed with the IRS resulting in a cumulative effect adjustment. Management believes that adoption of these regulations will not result in a material change to plant-related deferred tax liabilities.
NOTE 7.8. EMPLOYEE BENEFIT PLANS
UNS Energy’s net periodic benefit plan cost, comprised primarily of TEP's cost, includes the following components:
|
| | | | | | | | | | | | | | | |
| | Pension Benefits | | Other Retiree Benefits |
| | Three Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | Millions of Dollars |
| | | | | | | | |
| Service Cost | $ | 4 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
|
| Interest Cost | 4 |
| | 4 |
| | — |
| | 1 |
|
| Expected Return on Plan Assets | (5 | ) | | (4 | ) | | — |
| | — |
|
| Actuarial Loss Amortization | 2 |
| | 2 |
| | — |
| | — |
|
| Net Periodic Benefit Cost | $ | 5 |
| | $ | 4 |
| | $ | 1 |
| | $ | 2 |
|
| | | | Pension Benefits | | Other Retiree Benefits | | | | | | | | | |
| | Nine Months Ended September 30, | Pension Benefits | | Other Retiree Benefits |
| | 2013 | | 2012 | | 2013 | | 2012 | Three Months Ended March 31, |
| | Millions of Dollars | 2014 | | 2013 | | 2014 | | 2013 |
| | | | | | | | | Millions of Dollars |
| Service Cost | $ | 10 |
| | $ | 8 |
| | $ | 3 |
| | $ | 2 |
| $ | 3 |
| | $ | 3 |
| | $ | 1 |
| | $ | 1 |
|
| Interest Cost | 11 |
| | 12 |
| | 2 |
| | 2 |
| 4 |
| | 4 |
| | 1 |
| | 1 |
|
| Expected Return on Plan Assets | (15 | ) | | (13 | ) | | (1 | ) | | — |
| (6 | ) | | (5 | ) | | — |
| | — |
|
| Actuarial Loss Amortization | 7 |
| | 5 |
| | — |
| | — |
| 1 |
| | 2 |
| | — |
| | — |
|
| Net Periodic Benefit Cost | $ | 13 |
| | $ | 12 |
| | $ | 4 |
| | $ | 4 |
| $ | 2 |
| | $ | 4 |
| | $ | 2 |
| | $ | 2 |
|
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
NOTE 8.9. SHARE-BASED COMPENSATION PLANS
RESTRICTED STOCK UNITS
In May 2013,February 2014, the UNS Energy Compensation Committee granted 8,870 restricted stock units to non-employee directors at a grant date fair value of $48.99 per share. We recognize compensation expense equal to the fair value on the grant date over the one-year vesting period. The grant date fair value was calculated by reducing the grant date share price by the present value of the dividends expected to be paid on the shares during the vesting period. Fully vested but undistributed non-employee director stock unit awards accrue dividend equivalent stock units based on the fair market value of common shares on the date the dividend is paid. We issue UNS Energy Common Stock (Common Stock) for the vested stock units in the January following the year the person is no longer a director.
In February 2013, the UNS Energy Compensation Committee granted 21,56016,910 restricted stock units to certain management employees at a grant date fair value, based on the grant date closing share price, of $46.23$60.39 per share. The restricted stock units vest on the third anniversary of grant and are distributed in shares of UNS Energy's Common Stock (Common Stock) upon vesting. We recognize compensation expense equal to the fair value on the grant date over the vesting period. These restricted stock units accrue dividend equivalents during the vesting period, which are distributed in shares of Common Stock upon vesting.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
PERFORMANCE SHARES
In February 2013,2014, the UNS Energy Compensation Committee granted 43,12033,820 performance share awards to certain management employees. Half of the performance share awards had a grant date fair value, based on a Monte Carlo simulation, of $45.54$57.47 per share. Those awards will be paid out in Common Stock based on a comparison of UNS Energy’s cumulative Total Shareholder Returncompound annualized total shareholder return relative to the companies included in the Edison Electric Institute Utility Index duringfor the three-year performance period of January 1, 2013 throughended December 31, 2015.2016. We recognize compensation expense equal to the fair value on the grant date over the vesting period if the requisite service period is fulfilled, whether or not the threshold is achieved. The remaining half had a grant date fair value, based on the grant date closing share price, of $46.23$60.39 per share and will be paid out in Common Stock based on cumulative net income for the three-year performance period ended December 31, 2015.2016. We recognize compensation expense equal to the fair value on the grant date over the requisite service period only for the awards that ultimately vest.
The performance shares vest based on the achievement of these goals by the end of the three-year performance period; any unearned awards are forfeited. Performance shares accrue dividend equivalents during the performance period, which are paid upon vesting.
SHARE-BASED COMPENSATION EXPENSE
UNS Energy and TEP recorded $1 million of share-based compensation expense for the three months ended September 30, 2013 and September 30, 2012. For the nine months ended September 30, 2013, UNS Energy recorded share-based compensation expense of $3 million, $2 million of which related to TEP. For the nine months ended September 30, 2012, UNS Energy and TEP recorded share-based compensation expense of $2less than $1 million. for the three months ended March 31, 2014 and March 31, 2013.
At September 30, 2013March 31, 2014, the total unrecognized compensation cost related to non-vested share-based compensation was $4$5 million, which will be recorded as compensation expense over the remaining vesting periods through February 2016.2017. At September 30, 2013March 31, 2014, 1less than 0.5 million shares were awarded but not yet issued, including target performance shares, under the share-based compensation plans.
NOTE 9.10. UNS ENERGY EARNINGS PER SHARE
We compute basic Earnings Per Share (EPS) by dividing Net Income by the weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could result if outstanding stock options or share-based compensation awards or UNS Energy's Convertible Senior Notes were exercised or converted into Common Stock. We excluded anti-dilutive stock options and contingently issuable shares from the calculation of diluted EPS. The numerator in calculating diluted EPS is Net Income adjusted for the interest on Convertible Senior Notes (net of tax) that would not be paid if the remaining notes, not yet converted, were converted to Common Stock.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
The following table illustrates the effect of dilutive securities on net income and weighted average Common Stock outstanding:
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | Thousands of Dollars |
| Numerator: | | | | | | | |
| Net Income | $ | 67,990 |
| | $ | 50,664 |
| | $ | 113,953 |
| | $ | 83,414 |
|
Income from Assumed Conversion of Convertible Senior Notes (1) | — |
| | — |
| | — |
| | 1,100 |
|
| Adjusted Net Income Available for Diluted Common Stock Outstanding | $ | 67,990 |
| | $ | 50,664 |
| | $ | 113,953 |
| | $ | 84,514 |
|
| | | | | | | | |
| | Thousands of Shares |
| Denominator: | | | | | | | |
| Weighted Average Shares of Common Stock Outstanding: | | | | | | | |
| Common Shares Issued | 41,472 |
| | 41,290 |
| | 41,427 |
| | 39,835 |
|
| Fully Vested Deferred Stock Units | 178 |
| | 156 |
| | 169 |
| | 148 |
|
| Total Weighted Average Common Stock Outstanding – Basic | 41,650 |
| | 41,446 |
| | 41,596 |
| | 39,983 |
|
| Effect of Dilutive Securities: | | | | | | | |
Convertible Senior Notes (1) | — |
| | — |
| | — |
| | 1,417 |
|
| Options and Stock Issuable Under Share-Based Compensation Plans | 378 |
| | 417 |
| | 345 |
| | 319 |
|
| Total Weighted Average Common Stock Outstanding – Diluted | 42,028 |
| | 41,863 |
| | 41,941 |
| | 41,719 |
|
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2014 | | 2013 |
| | Thousands of Dollars |
| Numerator: Net Income | $ | 15,475 |
| | $ | 11,345 |
|
| | Thousands of Shares |
| Denominator: | |
| Weighted Average Shares of Common Stock Outstanding: | | | |
| Common Shares Issued | 41,619 |
| | 41,381 |
|
| Fully Vested Deferred Stock Units | 118 |
| | 159 |
|
| Total Weighted Average Common Stock Outstanding — Basic | 41,737 |
| | 41,540 |
|
| Effect of Dilutive Securities: | | | |
| Options and Stock Issuable Under Share-Based Compensation Plans | 347 |
| | 335 |
|
| Total Weighted Average Common Stock Outstanding — Diluted | 42,084 |
| | 41,875 |
|
(1) In 2012,For the Convertible Senior Notes were converted to Common Stock or redeemed for cash.
Wethree months ended March 31, 2013, we excluded the following outstanding stock options, with an exercise price above market, and24,000 contingently issuable shares from our diluted EPS computation as their effect would be anti-dilutive:anti-dilutive.
|
| | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | Thousands of Shares |
| Stock Options | — |
| | — |
| | — |
| | 67 |
|
| Restricted Stock Units | — |
| | — |
| | 8 |
| | — |
|
| Total Anti-Dilutive Shares Excluded from the Diluted EPS Computation | — |
| | — |
| | 8 |
| | 67 |
|
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
NOTE 10.11. SUPPLEMENTAL CASH FLOW INFORMATION
A reconciliation of Net Income to Net Cash Flows from Operating Activities follows:
| | | | UNS Energy | UNS Energy |
| | Nine Months Ended September 30, | Three Months Ended March 31, |
| | 2013 | | 2012 | 2014 | | 2013 |
| | Thousands of Dollars | Thousands of Dollars |
| Net Income | $ | 113,953 |
| | $ | 83,414 |
| $ | 15,475 |
| | $ | 11,345 |
|
| Adjustments to Reconcile Net Income | | | | | | |
| To Net Cash Flows from Operating Activities | | | | | | |
| Depreciation Expense | 111,175 |
| | 105,319 |
| 39,081 |
| | 36,300 |
|
| Amortization Expense | 21,600 |
| | 26,845 |
| 6,176 |
| | 8,289 |
|
| Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense | 5,399 |
| | 4,911 |
| |
| Amortization of Deferred Debt-Related Costs Included in Interest Expense | 2,280 |
| | 2,250 |
| |
| Depreciation and Amortization Recorded to Fuel and O&M Expense | | 1,990 |
| | 1,759 |
|
| Amortization of Deferred Debt-Related Costs included in Interest Expense | | 785 |
| | 750 |
|
| Provision for Retail Customer Bad Debts | 1,703 |
| | 2,017 |
| 537 |
| | 318 |
|
| Use of RECs for Compliance | 12,999 |
| | 4,017 |
| |
| Use of Renewable Energy Credits for Compliance | | 5,528 |
| | 3,870 |
|
| Deferred Income Taxes | 77,962 |
| | 63,057 |
| 10,131 |
| | 22,078 |
|
| Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset | (11,039 | ) | | — |
| |
| Pension and Retiree Expense | 17,087 |
| | 16,391 |
| 3,942 |
| | 5,696 |
|
| Pension and Retiree Funding | (27,602 | ) | | (23,649 | ) | (1,694 | ) | | (1,734 | ) |
| Share-Based Compensation Expense | 2,810 |
| | 1,952 |
| 985 |
| | 722 |
|
| Allowance for Equity Funds Used During Construction | (4,145 | ) | | (2,708 | ) | (1,898 | ) | | (1,175 | ) |
| Increase (Decrease) to Reflect PPFAC/PGA Recovery | (6,814 | ) | | 29,730 |
| |
| PPFAC Reduction - 2013 TEP Rate Order | 3,000 |
| | — |
| |
| Liquidated Damages for Springerville Unit 3 Outage | — |
| | 1,921 |
| |
| Decrease to Reflect PPFAC/PGA Recovery | | (8,920 | ) | | (5,368 | ) |
| Changes in Assets and Liabilities which Provided (Used) | | | | | | |
| Cash Exclusive of Changes Shown Separately | | | | | | |
| Accounts Receivable | (32,883 | ) | | (28,686 | ) | 27,778 |
| | 19,003 |
|
| Materials and Fuel Inventory | 14,839 |
| | (33,038 | ) | (3,057 | ) | | 1,574 |
|
| Accounts Payable | (18,497 | ) | | (5,220 | ) | (12,387 | ) | | (13,458 | ) |
| Income Taxes | (15,847 | ) | | (11,738 | ) | (146 | ) | | (16,028 | ) |
| Interest Accrued | (2,137 | ) | | (1,551 | ) | (6,426 | ) | | (9,974 | ) |
| Taxes Other Than Income Taxes | 18,718 |
| | 16,478 |
| 11,697 |
| | 12,534 |
|
| Other | 20,473 |
| | 16,426 |
| (12,792 | ) | | 4,552 |
|
| Net Cash Flows – Operating Activities | $ | 305,034 |
| | $ | 268,138 |
| $ | 76,785 |
| | $ | 81,053 |
|
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
| | | | TEP | TEP |
| | Nine Months Ended September 30, | Three Months Ended March 31, |
| | 2013 | | 2012 | 2014 | | 2013 |
| | Thousands of Dollars | Thousands of Dollars |
| Net Income | $ | 96,433 |
| | $ | 65,018 |
| $ | 9,172 |
| | $ | 1,478 |
|
| Adjustments to Reconcile Net Income | | | | | | |
| To Net Cash Flows from Operating Activities | | | | | | |
| Depreciation Expense | 87,729 |
| | 82,656 |
| 30,811 |
| | 28,558 |
|
| Amortization Expense | 24,393 |
| | 29,621 |
| 7,099 |
| | 9,222 |
|
| Depreciation and Amortization Recorded to Fuel and Operations and Maintenance Expense | 4,602 |
| | 3,922 |
| |
| Depreciation and Amortization Recorded to Fuel and O&M Expense | | 1,704 |
| | 1,493 |
|
| Amortization of Deferred Debt-Related Costs Included in Interest Expense | 1,831 |
| | 1,628 |
| 635 |
| | 601 |
|
| Provision for Retail Customer Bad Debts | 1,315 |
| | 1,348 |
| 342 |
| | 246 |
|
| Use of RECs for Compliance | 11,766 |
| | 3,324 |
| 4,844 |
| | 3,540 |
|
| Deferred Income Taxes | 64,132 |
| | 51,638 |
| 5,635 |
| | 12,276 |
|
| Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset | (10,751 | ) | | — |
| |
| Pension and Retiree Expense | 14,909 |
| | 14,466 |
| 3,412 |
| | 4,970 |
|
| Pension and Retiree Funding | (26,118 | ) | | (20,989 | ) | (1,657 | ) | | (1,676 | ) |
| Share-Based Compensation Expense | 2,239 |
| | 1,540 |
| 792 |
| | 575 |
|
| Allowance for Equity Funds Used During Construction | (2,923 | ) | | (2,265 | ) | (1,721 | ) | | (850 | ) |
| Increase (Decrease) to Reflect PPFAC Recovery | (5,079 | ) | | 25,150 |
| |
| PPFAC Reduction - 2013 TEP Rate Order | 3,000 |
| | — |
| |
| Liquidated Damages for Springerville Unit 3 Outage | — |
| | 1,921 |
| |
| Decrease to Reflect PPFAC Recovery | | (1,730 | ) | | (2,360 | ) |
| Changes in Assets and Liabilities which Provided (Used) | | | | | | |
| Cash Exclusive of Changes Shown Separately | | | | | | |
| Accounts Receivable | (42,542 | ) | | (44,269 | ) | 16,274 |
| | 11,408 |
|
| Materials and Fuel Inventory | 14,955 |
| | (32,448 | ) | (3,182 | ) | | 1,654 |
|
| Accounts Payable | (8,678 | ) | | 4,977 |
| (3,425 | ) | | (6,094 | ) |
| Income Taxes | (10,681 | ) | | (11,424 | ) | (5 | ) | | (10,877 | ) |
| Interest Accrued | 1,008 |
| | 2,729 |
| (3,260 | ) | | (6,826 | ) |
| Taxes Other Than Income Taxes | 17,405 |
| | 16,710 |
| 9,948 |
| | 10,068 |
|
| Other | 15,234 |
| | 11,898 |
| (10,374 | ) | | 1,993 |
|
| Net Cash Flows – Operating Activities | $ | 254,179 |
| | $ | 207,151 |
| $ | 65,314 |
| | $ | 59,399 |
|
Non-Cash Transactions
In August 2013, TEP recorded an increase of $39 million to both Utility Plant Under Capital Leases and Capital Lease Obligations due to TEP's commitment to purchase leased interests in January 2015. See Note 5.
NON-CASH TRANSACTIONS
In March 2013, TEP issued $91 million of tax-exempt bonds and used the proceeds to redeem debt using a trustee. Since the cash flowed through a trust account, the issuance and redemption of debt resulted in a non-cash transaction. See Note 5.
In September 2012, TEP declared a $30 million dividend to UNS Energy which was paid in October 2012.
In the first nine months of 2012, UNS Energy converted $147 million of the previously outstanding $150 million Convertible Senior Notes into Common Stock, resulting in non-cash transactions.
In the first nine months of 2012, TEP's redemption of $193 million of tax-exempt bonds resulted in a non-cash transaction.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
NOTE 11.12. FAIR VALUE MEASUREMENTS AND DERIVATIVE INSTRUMENTS
We categorize our assets and liabilities accounted for at fair value into the three-level hierarchy based on inputs used to determine the fair value. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in an active market. Level 2 inputs include quoted prices for similar assets or liabilities, quoted prices in non-active markets, and pricing models whose inputs are observable, directly or indirectly. Level 3 inputs are unobservable and supported by little or no market activity.
FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE
The fair value Transfers between levels are recorded at the end of a financial instrument isreporting period. There were no transfers between levels in the market price to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair valueperiods presented.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The carrying amounts of our current assets, current liabilities, including current maturities of long-term debt, and amounts outstanding under our credit agreements approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below.
For Investment in Lease Debt, we calculated the present value of remaining cash flows using current market rates for instruments with similar characteristics such as credit rating and time-to-maturity. We also incorporated the impact of counterparty credit risk using market credit default swap data. TEP's Investment in Lease Debt matured in January 2013.
For Investment in Lease Equity, we estimate the price at which an investor would realize a target internal rate of return. Our estimates include: the mix of debt and equity an investor would use to finance the purchase; the cost of debt; the required return on equity; and income tax rates. The estimate assumes a residual value based on an appraisal of Springerville Unit 1 conducted in 2011.
For Long-Term Debt, we use quoted market prices, when available, or calculate the present value of remaining cash flows at the balance sheet date. When calculating present value, we use current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We consider the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. We also incorporate the impact of our own credit risk using a credit default swap rate.
The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following:
|
| | | | | | | | | | | | | | | | | |
| | | | September 30, 2013 | | December 31, 2012 |
| | Fair Value Hierarchy | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | Millions of Dollars |
| Assets: | | | | | | | | | |
| TEP Investment in Lease Debt | Level 2 | | $ | — |
| | $ | — |
| | $ | 9 |
| | $ | 9 |
|
| TEP Investment in Lease Equity | Level 3 | | 36 |
| | 24 |
| | 36 |
| | 23 |
|
| Liabilities: | | | | | | | | | |
| Long-Term Debt | | | | | | | | | |
| UNS Energy | Level 2 | | 1,506 |
| | 1,522 |
| | 1,498 |
| | 1,583 |
|
| TEP | Level 2 | | 1,224 |
| | 1,215 |
| | 1,223 |
| | 1,271 |
|
FINANCIAL INSTRUMENTS MEASURED AT FAIR VALUE ON A RECURRING BASIS
The following tables present, by level within the fair value hierarchy, UNS Energy’s and TEP’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. |
| | | | | | | | | | | | | | | | | | | | | | | |
| | UNS Energy |
| | Total | | Level 1 | | Level 2 | | Level 3 | | Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5) | | Net Amount |
| | March 31, 2014 |
| | Millions of Dollars |
| Assets | | | |
Cash Equivalents(1) | $ | 74 |
| | $ | 74 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 74 |
|
Restricted Cash(1) | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Rabbi Trust Investments(2) | 23 |
| | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Energy Contracts - Regulatory Recovery(3) | 11 |
| | — |
| | 5 |
| | 6 |
| | (5 | ) | | 6 |
|
| Total Assets | 110 |
| | 76 |
| | 28 |
| | 6 |
| | (5 | ) | | 105 |
|
| Liabilities | | | | | | | | | | | |
Energy Contracts - Regulatory Recovery(3) | (7 | ) | | — |
| | (2 | ) | | (5 | ) | | 5 |
| | (2 | ) |
Energy Contracts - Cash Flow Hedge(3) | (1 | ) | | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
Interest Rate Swaps(4) | (6 | ) | | — |
| | (6 | ) | | — |
| | — |
| | (6 | ) |
| Total Liabilities | (14 | ) | | — |
| | (8 | ) | | (6 | ) | | 5 |
| | (9 | ) |
| Net Total Assets (Liabilities) | $ | 96 |
| | $ | 76 |
| | $ | 20 |
| | $ | — |
| | $ | — |
| | $ | 96 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | UNS Energy |
| | Total | | Level 1 | | Level 2 | | Level 3 | | Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5) | | Net Amount |
| | December 31, 2013 |
| | Millions of Dollars |
| Assets | | | |
Cash Equivalents(1) | $ | 14 |
| | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 14 |
|
Restricted Cash(1) | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Rabbi Trust Investments(2) | 22 |
| | — |
| | 22 |
| | — |
| | — |
| | 22 |
|
Energy Contracts - Regulatory Recovery(3) | 7 |
| | — |
| | 3 |
| | 4 |
| | (5 | ) | | 2 |
|
| Total Assets | 45 |
| | 16 |
| | 25 |
| | 4 |
| | (5 | ) | | 40 |
|
| Liabilities | | | | | | | | | | | |
Energy Contracts - Regulatory Recovery(3) | (7 | ) | | — |
| | (2 | ) | | (5 | ) | | 5 |
| | (2 | ) |
Energy Contracts - Cash Flow Hedge(3) | (1 | ) | | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
Interest Rate Swaps(4) | (7 | ) | | — |
| | (7 | ) | | — |
| | — |
| | (7 | ) |
| Total Liabilities | (15 | ) | | — |
| | (9 | ) | | (6 | ) | | 5 |
| | (10 | ) |
| Net Total Assets (Liabilities) | $ | 30 |
| | $ | 16 |
| | $ | 16 |
| | $ | (2 | ) | | $ | — |
| | $ | 30 |
|
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | TEP |
| | Total | | Level 1 | | Level 2 | | Level 3 | | Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5) | | Net Amount |
| | March 31, 2014 |
| | Millions of Dollars |
| Assets | | | |
Cash Equivalents(1) | $ | 62 |
| | $ | 62 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 62 |
|
Restricted Cash(1) | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Rabbi Trust Investments(2) | 23 |
| | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Energy Contracts - Regulatory Recovery(3) | 4 |
| | — |
| | 2 |
| | 2 |
| | (2 | ) | | 2 |
|
| Total Assets | 91 |
| | 64 |
| | 25 |
| | 2 |
| | (2 | ) | | 89 |
|
| Liabilities | | | | | | | | | | | |
Energy Contracts - Regulatory Recovery(3) | (4 | ) | | — |
| | (1 | ) | | (3 | ) | | 2 |
| | (2 | ) |
Energy Contracts - Cash Flow Hedge(3) | (1 | ) | | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
Interest Rate Swaps(4) | (6 | ) | | — |
| | (6 | ) | | — |
| | — |
| | (6 | ) |
| Total Liabilities | (11 | ) | | — |
| | (7 | ) | | (4 | ) | | 2 |
| | (9 | ) |
| Net Total Assets (Liabilities) | $ | 80 |
| | $ | 64 |
| | $ | 18 |
| | $ | (2 | ) | | $ | — |
| | $ | 80 |
|
| | | | UNS Energy | TEP |
| | Total | | Level 1 | | Level 2 | | Level 3 | | Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5) | | Net Amount | Total | | Level 1 | | Level 2 | | Level 3 | | Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5) | | Net Amount |
| | September 30, 2013 | December 31, 2013 |
| | Millions of Dollars | Millions of Dollars |
| Assets | | | | | | |
Cash Equivalents(1) | $ | 31 |
| | $ | 31 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 31 |
| $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Restricted Cash(1) | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
| 2 |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Rabbi Trust Investments(2) | 21 |
| | — |
| | 21 |
| | — |
| | — |
| | 21 |
| 22 |
| | — |
| | 22 |
| | — |
| | — |
| | 22 |
|
Energy Contracts - Regulatory Recovery(3) | 2 |
| | — |
| | 1 |
| | 1 |
| | (2 | ) | | — |
| 2 |
| | — |
| | 1 |
| | 1 |
| | (1 | ) | | 1 |
|
| Total Assets | 56 |
| | 33 |
| | 22 |
| | 1 |
| | (2 | ) | | 54 |
| 26 |
| | 2 |
| | 23 |
| | 1 |
| | (1 | ) | | 25 |
|
| Liabilities | | | | | | | | | | | | | | | | | | | | | | |
Energy Contracts - Regulatory Recovery(3) | (11 | ) | | — |
| | (5 | ) | | (6 | ) | | 2 |
| | (9 | ) | (2 | ) | | — |
| | — |
| | (2 | ) | | 1 |
| | (1 | ) |
Energy Contracts - Cash Flow Hedge(3) | (1 | ) | | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) | (1 | ) | | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
Interest Rate Swaps(4) | (8 | ) | | — |
| | (8 | ) | | — |
| | — |
| | (8 | ) | (7 | ) | | — |
| | (7 | ) | | — |
| | — |
| | (7 | ) |
| Total Liabilities | (20 | ) | | — |
| | (13 | ) | | (7 | ) | | 2 |
| | (18 | ) | (10 | ) | | — |
| | (7 | ) | | (3 | ) | | 1 |
| | (9 | ) |
| Net Total Assets (Liabilities) | $ | 36 |
| | $ | 33 |
| | $ | 9 |
| | $ | (6 | ) | | $ | — |
| | $ | 36 |
| $ | 16 |
| | $ | 2 |
| | $ | 16 |
| | $ | (2 | ) | | $ | — |
| | $ | 16 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | UNS Energy |
| | Total | | Level 1 | | Level 2 | | Level 3 | | Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5) | | Net Amount |
| | December 31, 2012 |
| | Millions of Dollars |
| Assets | | | |
Cash Equivalents(1) | $ | 20 |
| | $ | 20 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 20 |
|
Restricted Cash(1) | 7 |
| | 7 |
| | — |
| | — |
| | — |
| | 7 |
|
Rabbi Trust Investments(2) | 19 |
| | — |
| | 19 |
| | — |
| | — |
| | 19 |
|
Energy Contracts - Regulatory Recovery(3) | 7 |
| | — |
| | 2 |
| | 5 |
| | (5 | ) | | 2 |
|
| Total Assets | 53 |
| | 27 |
| | 21 |
| | 5 |
| | (5 | ) | | 48 |
|
| Liabilities | | | | | | | | | | | |
Energy Contracts - Regulatory Recovery(3) | (15 | ) | | — |
| | (7 | ) | | (8 | ) | | 5 |
| | (10 | ) |
Energy Contracts - Cash Flow Hedge(3) | (2 | ) | | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
Interest Rate Swaps(4) | (10 | ) | | — |
| | (10 | ) | | — |
| | — |
| | (10 | ) |
| Total Liabilities | (27 | ) | | — |
| | (17 | ) | | (10 | ) | | 5 |
| | (22 | ) |
| Net Total Assets (Liabilities) | $ | 26 |
| | $ | 27 |
| | $ | 4 |
| | $ | (5 | ) | | $ | — |
| | $ | 26 |
|
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | TEP |
| | Total | | Level 1 | | Level 2 | | Level 3 | | Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5) | | Net Amount |
| | September 30, 2013 |
| | Millions of Dollars |
| Assets | | | |
Cash Equivalents(1) | $ | 15 |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 15 |
|
Restricted Cash(1) | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Rabbi Trust Investments(2) | 21 |
| | — |
| | 21 |
| | — |
| | — |
| | 21 |
|
Energy Contracts - Regulatory Recovery(3) | 1 |
| | — |
| | 1 |
| | — |
| | (1 | ) | | — |
|
| Total Assets | 39 |
| | 17 |
| | 22 |
| | — |
| | (1 | ) | | 38 |
|
| Liabilities | | | | | | | | | | | |
Energy Contracts - Regulatory Recovery(3) | (3 | ) | | — |
| | (2 | ) | | (1 | ) | | 1 |
| | (2 | ) |
Energy Contracts - Cash Flow Hedge(3) | (1 | ) | | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
Interest Rate Swaps(4) | (8 | ) | | — |
| | (8 | ) | | — |
| | — |
| | (8 | ) |
| Total Liabilities | (12 | ) | | — |
| | (10 | ) | | (2 | ) | | 1 |
| | (11 | ) |
| Net Total Assets (Liabilities) | $ | 27 |
| | $ | 17 |
| | $ | 12 |
| | $ | (2 | ) | | $ | — |
| | $ | 27 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | TEP |
| | Total | | Level 1 | | Level 2 | | Level 3 | | Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5) | | Net Amount |
| | December 31, 2012 |
| | Millions of Dollars |
| Assets | | | |
Cash Equivalents(1) | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
Restricted Cash(1) | 7 |
| | 7 |
| | — |
| | — |
| | — |
| | 7 |
|
Rabbi Trust Investments(2) | 19 |
| | — |
| | 19 |
| | — |
| | — |
| | 19 |
|
Energy Contracts - Regulatory Recovery(3) | 3 |
| | — |
| | 1 |
| | 2 |
| | (1 | ) | | 2 |
|
| Total Assets | 30 |
| | 8 |
| | 20 |
| | 2 |
| | (1 | ) | | 29 |
|
| Liabilities | | | | | | | | | | | |
Energy Contracts - Regulatory Recovery(3) | (3 | ) | | — |
| | (3 | ) | | — |
| | 1 |
| | (2 | ) |
Energy Contracts - Cash Flow Hedge(3) | (2 | ) | | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
Interest Rate Swaps(4) | (10 | ) | | — |
| | (10 | ) | | — |
| | — |
| | (10 | ) |
| Total Liabilities | (15 | ) | | — |
| | (13 | ) | | (2 | ) | | 1 |
| | (14 | ) |
| Net Total Assets (Liabilities) | $ | 15 |
| | $ | 8 |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 15 |
|
| |
(1) | Cash Equivalents and Restricted Cash represent amounts held in money market funds and certificates of deposit valued at cost, including interest. Cash Equivalents are included in Cash and Cash Equivalents on the balance sheets. Restricted Cash is included in Investments and Other Property – Other on the balance sheets. |
| |
(2) | Rabbi Trust Investments include amounts related to deferred compensation and Supplement Executive Retirement Plan (SERP) benefits held in mutual and money market funds valued at quoted prices traded in active markets. These investments are included in Investments and Other Property – Other on the balance sheets. |
| |
(3) | Energy Contracts include gas swap agreements (Level 2), power options (Level 2), gas options (Level 3), and forward power purchase and sales contracts (Level 3), and forward power purchase contracts indexed to gas (Level 3), entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the UNS Energy and TEP balance sheets. The valuation techniques are described below. |
| |
| (4) | Interest Rate Swaps are valued based on the 3-month or 6-month LIBOR index or the Securities Industry and Financial Markets Association municipal swap index. These interest rate swaps are included in Derivative Instruments on the balance sheets. |
| |
(5) | All energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk. We have presented the effect of offset by counterparty; however, we present derivatives on a gross basis on the balance sheets. |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
DERIVATIVE INSTRUMENTS
Regulatory Recovery
We are exposedenter into various derivative and non-derivative contracts to reduce our exposure to energy price risk associated with our gas and purchased power requirements. We reduce our energy price risk through a variety of derivative and non-derivative instruments. The objectives for entering into such contracts include: creating price stability; meeting load and reserve requirements; and reducing exposure to price volatility that may result from delayed recovery under the PPFAC or PGA. See Note 2.
We primarily apply the market approach for recurring fair value measurements. When we have observable inputs for substantially the full term of the asset or liability or use quoted prices in an inactive market, we categorize the instrument in Level 2. We categorize derivatives in Level 3 when we use an aggregate pricing service or published prices that represent a consensus reporting of multiple brokers.
For both power and gas prices we obtain quotes from brokers, major market participants, exchanges, or industry publications and rely on our own price experience from active transactions in the market. We primarily use one set of quotations each for power and for gas and then validate those prices using other sources. We believe that the market information provided is reflective of market conditions as of the time and date indicated.
Published prices for energy derivative contracts may not be available due to the nature of contract delivery terms such as non-standard time blocks and non-standard delivery points. In these cases, we apply adjustments based on historical price curve relationships, transmission, and line losses.
We estimate the fair value of our gas options using a Black-Scholes-Merton option pricing model which includes inputs such as implied volatility, interest rates, and forward price curves. Beginning inIn the thirdfirst quarter of 2013, the fairwe also used this pricing model to value of our power options is based on contractually specified option premiums instead of the Black-Scholes-Merton option pricing model because the needed inputs are no longer available. Based on the change, we transferred the power options out of Level 3 and in to Level 2 at the end of third quarter of 2013. The amount transferred was less than $0.5 million. We record transfers between levels in the fair value hierarchy at the end of the reporting period. There were no other transfers between levels in the periods presented.options.
We also consider the impact of counterparty credit risk using current and historical default and recovery rates, as well as our own credit risk using credit default swap data.
Our assessments of the significance of a particular input to the fair value measurements require judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. We review the assumptions underlying our contractsprice curves monthly.
Cash Flow Hedges
We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. TheseThe interest rate swap agreements expire through January 2020. We also have a power purchase swap to hedge the cash flow risk associated with a long-term power supply agreement. ThisThe power purchase swap agreement expires in September 2015. The after-tax unrealized gains and losses on cash flow hedge activities and amounts reclassified to earnings are reported in the statements of other comprehensive income and Note 1213. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $4 million. for UNS Energy and $3 million for TEP.
Financial Impact of Energy Contracts
We record unrealized gains and losses on energy contracts that are recoverable through the PPFAC or PGA on the balance sheets as a regulatory asset or a regulatory liability rather than reporting the transaction in the income statements or in the statements of other comprehensive income, as shown in following tables:
|
| | | | | | | | | | | | | | | |
| | UNS Energy | | TEP |
| | Three Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | Millions of Dollars |
| Increase (Decrease) to Regulatory Assets/Liabilities | $ | 1 |
| | $ | (12 | ) | | $ | 1 |
| | $ | (6 | ) |
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
|
| | | | | | | | | | | | | | | |
| | UNS Energy | | TEP |
| | Nine Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | Millions of Dollars |
| Increase (Decrease) to Regulatory Assets/Liabilities | $ | — |
| | $ | (20 | ) | | $ | 2 |
| | $ | (7 | ) |
|
| | | | | | | | | | | | | | | |
| | UNS Energy | | TEP |
| | Three Months Ended March 31, |
| | 2014 | | 2013 | | 2014 | | 2013 |
| | Millions of Dollars |
| Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities | $ | 4 |
| | $ | 9 |
| | $ | 1 |
| | $ | 2 |
|
Realized gains and losses on settled contracts are fully recoverable through the PPFAC or PGA. At September 30, 2013March 31, 2014, UNS Energy and TEP have energy contracts that will settle through the thirdfirst quarter of 20162017.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Derivative Volumes
The volumes associated with our energy contracts were as follows:
| | | | UNS Energy | | TEP | UNS Energy | | TEP |
| | September 30, 2013 | | December 31, 2012 | | September 30, 2013 | | December 31, 2012 | March 31, 2014 | | December 31, 2013 | | March 31, 2014 | | December 31, 2013 |
| Power Contracts GWh | 1,819 |
| | 2,228 |
| | 856 |
| | 820 |
| 1,901 |
| | 1,583 |
| | 896 |
| | 779 |
|
| Gas Contracts GBtu | 29,022 |
| | 17,851 |
| | 8,504 |
| | 7,958 |
| 45,173 |
| | 33,371 |
| | 15,821 |
| | 9,615 |
|
Level 3 Fair Value Measurements
The following table provides quantitative information regarding significant unobservable inputs in UNS Energy’s Level 3 fair value measurements: |
| | | | | | | | | | | | | | | | | | | |
| | | | Fair Value at | | | | | | |
| | | | March 31, 2014 | | | | Range of |
| | Valuation Approach | | Assets | | Liabilities | | Unobservable Inputs | | Unobservable Input |
| | | | Millions of Dollars | | | | | | |
Forward Contracts(1) | Market approach | | $ | 3 |
| | $ | (5 | ) | | Market price per MWh | | $ | 25.05 |
| - | $ | 60.10 |
|
| | | | | | | | | | | |
Option Contracts(2) | Option model | | 3 |
| | (1 | ) | | Market price per MMbtu | | $ | 3.77 |
| - | $ | 4.66 |
|
| | | | | | | Gas volatility | | 19.81 | % | - | 31.62 | % |
| Level 3 Energy Contracts | | | $ | 6 |
| | $ | (6 | ) | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | | | Fair Value at | | | | | | |
| | | | September 30, 2013 | | | | Range of |
| | Valuation Approach | | Assets | | Liabilities | | Unobservable Inputs | | Unobservable Input |
| | | | Millions of Dollars | | | | | | |
Forward Contracts(1) | Market approach | | $ | 1 |
| | $ | (7 | ) | | Market price per MWh | | $ | 23.00 |
| - | $ | 48.00 |
|
| |
(1) | TEP comprises $1 million of the forward contract assets and $24 million of the forward contract liabilities. |
| |
(2) | TEP comprises $1 million of the option contract assets. |
Our exposure to risk resulting from changesChanges in one or more of the unobservable inputs identified above is mitigated as we reportcould have a significant impact on the fair value measurement depending on the magnitude of the change inand the direction of the change for each input. The impact of changes to fair value, of energy contract derivativesincluding changes from unobservable inputs, are subject to recovery or refund through the PPFAC or PGA mechanisms and are reported as a regulatory asset or a regulatory liability, recoverable through the PPFAC or PGA mechanisms, or as a component of other comprehensive income, rather than in the income statement.
The following tables present a reconciliation of changes in the fair value of assets and liabilities classified as Level 3 in the fair value hierarchy:
| | | | Three Months Ended September 30, 2013 | UNS Energy | | TEP |
| | UNS Energy | | TEP | Millions of Dollars |
| | Millions of Dollars | |
| Balances at June 30, 2013 | $ | (5 | ) | | $ | (1 | ) | |
| Balances at December 31, 2013 | | $ | (2 | ) | | $ | (2 | ) |
| Realized/Unrealized Gains/(Losses) Recorded to: | | | | | | |
| Net Regulatory Assets/Liabilities – Derivative Instruments | (3 | ) | | (1 | ) | 3 |
| | (1 | ) |
| Settlements | 2 |
| | — |
| (1 | ) | | 1 |
|
| Balances at September 30, 2013 | $ | (6 | ) | | $ | (2 | ) | |
| Balances at March 31, 2014 | | $ | — |
| | $ | (2 | ) |
| | | | | | | |
| Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period | $ | (2 | ) | | $ | — |
| $ | 2 |
| | $ | — |
|
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
|
| | | | | | | |
| | Nine Months Ended September 30, 2013 |
| | UNS Energy | | TEP |
| | Millions of Dollars |
| Balances at December 31, 2012 | $ | (5 | ) | | $ | — |
|
| Realized/Unrealized Gains/(Losses) Recorded to: | | | |
| Net Regulatory Assets/Liabilities – Derivative Instruments | (4 | ) | | (2 | ) |
| Settlements | 3 |
| | — |
|
| Balances at September 30, 2013 | $ | (6 | ) | | $ | (2 | ) |
| | | | |
| Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period | $ | (5 | ) | | $ | (1 | ) |
|
| | | | | | | |
| | Three Months Ended September 30, 2012 |
| | UNS Energy | | TEP |
| | Millions of Dollars |
| Balances at June 30, 2012 | $ | (7 | ) | | $ | (1 | ) |
| Realized/Unrealized Gains/(Losses) Recorded to: | | | |
| Net Regulatory Assets/Liabilities – Derivative Instruments | — |
| | 1 |
|
| Settlements | 1 |
| | — |
|
| Balances at September 30, 2012 | $ | (6 | ) | | $ | — |
|
| | | | |
| Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period | $ | — |
| | $ | — |
|
| | | | Nine Months Ended September 30, 2012 | UNS Energy | | TEP |
| | UNS Energy | | TEP | Millions of Dollars |
| | Millions of Dollars | |
| Balances at December 31, 2011 | $ | (10 | ) | | $ | — |
| |
| Balances at December 31, 2012 | | $ | (5 | ) | | $ | — |
|
| Realized/Unrealized Gains/(Losses) Recorded to: | | | | | | |
| Net Regulatory Assets/Liabilities – Derivative Instruments | (4 | ) | | — |
| 1 |
| | (1 | ) |
| Settlements | 8 |
| | — |
| 1 |
| | — |
|
| Balances at September 30, 2012 | $ | (6 | ) | | $ | — |
| |
| Balances at March 31, 2013 | | $ | (3 | ) | | $ | (1 | ) |
| | | | | | | |
| Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period | $ | (1 | ) | | $ | — |
| $ | 1 |
| | $ | (1 | ) |
CREDIT RISK
The use of contractual arrangements to manage the risks associated with changes in energy commodity prices creates credit risk exposure resulting from the possibility of non-performance by counterparties pursuant to the terms of their contractual obligations. We enter into contracts for the physical delivery of energy and gas which contain remedies in the event of non-performance by the supply counterparties. In addition, volatile energy prices can create significant credit exposure from energy market receivables and subsequent measurement at fair value.
We have contractual agreements for energy procurement and hedging activities that contain certain provisions requiring each company to post collateral under certain circumstances. These circumstances include: exposures in excess of unsecured credit limits provided to TEP, UNS Electric, or UNS Gas; credit rating downgrades; or a failure to meet certain financial ratios. In the event that such credit events were to occur, we would have to provide certain credit enhancements in the form of cash or LOCs to fully collateralize our exposure to these counterparties.
We consider the effect of counterparty credit risk in determining the fair value of derivative instruments that are in a net asset position after incorporating collateral posted by counterparties and allocate the credit risk adjustment to individual contracts. We also consider the impact of our own credit risk after considering collateral posted on instruments that are in a net liability position and allocate the credit risk adjustment to all individual contracts. The impact of counterparty credit risk and our own credit risk on the fair value of derivative contracts was less than $0.5 million at September 30, 2013 and at December 31, 2012.
Material adverse changes could trigger credit risk-related contingent features. At September 30, 2013March 31, 2014, the fair value of derivative instruments in a net liability position under contracts with credit risk-related contingent features, including contracts under the normal purchase normal sale exception, was $3512 million for UNS Energy and $136 million for TEP. The additional collateral to be posted if credit-risk contingent features were triggered would be $3512 million for UNS Energy and $136 million for TEP.
FINANCIAL INSTRUMENTS NOT CARRIED AT FAIR VALUE
The fair value of a financial instrument is the market price to sell an asset or transfer a liability at the measurement date. We use the following methods and assumptions for estimating the fair value of our financial instruments:
The carrying amounts of our current liabilities, including current maturities of long-term debt, and amounts outstanding under our credit agreements approximate the fair values due to the short-term nature of these financial instruments. These items have been excluded from the table below.
For Investment in Lease Equity, we estimate the price at which an investor would realize a target internal rate of return. Our estimates include: the mix of debt and equity an investor would use to finance the purchase; the cost of debt; the required return on equity; and income tax rates. The estimate assumes a residual value based on an appraisal of Springerville Unit 1 conducted in 2011.
For Long-Term Debt, we use quoted market prices, when available, or calculate the present value of remaining cash flows at the balance sheet date. When calculating present value, we use current market rates for bonds with similar characteristics such as credit rating and time-to-maturity. We consider the principal amounts of variable rate debt outstanding to be reasonable estimates of the fair value. We also incorporate the impact of our own credit risk using a credit default swap rate.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited
The use of different estimation methods and/or market assumptions may yield different estimated fair value amounts. The carrying values recorded on the balance sheets and the estimated fair values of our financial instruments include the following: |
| | | | | | | | | | | | | | | | | |
| | | | March 31, 2014 | | December 31, 2013 |
| | Fair Value Hierarchy | | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | | | Millions of Dollars |
| Assets: | | | | | | | | | |
| TEP Investment in Lease Equity | Level 3 | | $ | 36 |
| | $ | 25 |
| | $ | 36 |
| | $ | 25 |
|
| Liabilities: | | | | | | | | | |
| Long-Term Debt | | | | | | | | | |
| UNS Energy | Level 2 | | $ | 1,659 |
| | $ | 1,722 |
| | $ | 1,507 |
| | $ | 1,521 |
|
| TEP | Level 2 | | 1,372 |
| | 1,407 |
| | 1,223 |
| | 1,214 |
|
NOTE 12.13. CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT
The realized changes in AOCI by component are as follows:
|
| | | | | | | | | | |
| Details About Accumulated Other Comprehensive Income Components | | Amount Reclassified from Other Comprehensive Income | | Affected Line Item in the Income Statement |
| | | UNS Energy | | TEP | | |
| | | Three Months Ended September 30, 2013 | | |
| | | Thousands of Dollars | | |
| Realized Losses on Cash Flow Hedges | | | | | | |
| Interest Rate Swaps - Debt | | $ | (350 | ) | | $ | (296 | ) | | Interest Expense Long-Term Debt |
| Interest Rate Swaps - Capital Leases | | (612 | ) | | (612 | ) | | Interest Expense Capital Leases |
| Commodity Contracts | | (556 | ) | | (556 | ) | | Purchased Energy/Purchased Power |
| Tax Benefit | | 601 |
| | 579 |
| | |
| Realized Losses on Cash Flow Hedges, Net of Taxes | | (917 | ) | | (885 | ) | | |
| | | | | | | |
| Amortization of SERP and Defined Benefit Plans | | | | | | |
| Prior Service Costs | | (110 | ) | | (110 | ) | | Other Expense |
| Tax Benefit | | 42 |
| | 42 |
| | |
| Amortization, Net of Taxes | | (68 | ) | | (68 | ) | | |
| | | | | | | |
| Total Reclassifications from Other Comprehensive Income for the Period | | $ | (985 | ) | | $ | (953 | ) | | |
| | | | | | | | | | | | | UNS Energy | |
| Details About Accumulated Other Comprehensive Income Components | | Amount Reclassified from Other Comprehensive Income | | Affected Line Item in the Income Statement |
| Amount Reclassified from Other Comprehensive Income |
| Affected Line Item in the Income Statement |
| | | UNS Energy | | TEP | |
| Three Months Ended March 31, |
|
| | | Nine Months Ended September 30, 2013 | | | 2014 | | 2013 | |
| | | Thousands of Dollars | |
| Thousands of Dollars |
|
| Realized Losses on Cash Flow Hedges | | | | | |
|
|
|
|
|
| Interest Rate Swaps - Debt | | $ | (1,026 | ) | | $ | (871 | ) | | Interest Expense Long-Term Debt |
| $ | (353 | ) | | $ | (331 | ) |
| Interest Expense Long-Term Debt |
| Interest Rate Swaps - Capital Leases | | (1,820 | ) | | (1,820 | ) | | Interest Expense Capital Leases |
| (596 | ) | | (604 | ) |
| Interest Expense Capital Leases |
| Commodity Contracts | | (747 | ) | | (747 | ) | | Purchased Energy/Purchased Power | |
| Tax Benefit | | 1,420 |
| | 1,360 |
| |
| 304 |
| | 370 |
|
|
| Realized Losses on Cash Flow Hedges, Net of Taxes | | (2,173 | ) | | (2,078 | ) | |
| (645 | ) | | (565 | ) |
|
| | | | | | |
| | | |
|
| Amortization of SERP and Defined Benefit Plans | | | | | | |
| Prior Service Costs | | (332 | ) | | (332 | ) | | Other Expense | |
| Amortization of SERP | |
|
| |
|
|
| Prior Service Costs and Net Loss | |
| (39 | ) | | (110 | ) |
| Operations and Maintenance |
| Tax Benefit | | 127 |
| | 127 |
| |
| 15 |
| | 42 |
|
|
| Amortization, Net of Taxes | | (205 | ) | | (205 | ) | |
| (24 | ) | | (68 | ) |
|
| | | | | | |
| | | |
|
| Total Reclassifications from Other Comprehensive Income for the Period | | $ | (2,378 | ) | | $ | (2,283 | ) | |
| $ | (669 | ) | | $ | (633 | ) |
|
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued) - Unaudited(Concluded)
|
| | | | | | | | | | |
| | | TEP | | |
| Details About Accumulated Other Comprehensive Income Components | | Amount Reclassified from Other Comprehensive Income | | Affected Line Item in the Income Statement |
| | | Three Months Ended March 31, | | |
| | | 2014 | | 2013 | | |
| | | Thousands of Dollars | | |
| Realized Losses on Cash Flow Hedges | | | | | | |
| Interest Rate Swaps - Debt | | $ | (298 | ) | | $ | (281 | ) | | Interest Expense Long-Term Debt |
| Interest Rate Swaps - Capital Leases | | (596 | ) | | (604 | ) | | Interest Expense Capital Leases |
| Tax Benefit | | 284 |
| | 350 |
| | |
| Realized Losses on Cash Flow Hedges, Net of Taxes | | (610 | ) | | (535 | ) | | |
| | |
| |
| | |
| Amortization of SERP | |
| |
| | |
| Prior Service Costs and Net Loss | | (39 | ) | | (110 | ) | | Other Expense |
| Tax Benefit | | 15 |
| | 42 |
| | |
| Amortization, Net of Taxes | | (24 | ) | | (68 | ) | | |
| | |
| |
| | |
| Total Reclassifications from Other Comprehensive Income for the Period | | $ | (634 | ) | | $ | (603 | ) | | |
NOTE 13. POTENTIAL PURCHASE OF GAS-FIRED GENERATION FACILITY
In August 2013, TEP entered into exclusive negotiations with Entegra Power Group LLC (Entegra) to purchase Unit 3 of the Gila River Generating Station (Gila River Unit 3) located in Gila Bend, Arizona. Gila River Unit 3 is a gas-fired combined cycle unit with a nominal capacity rating of 550 MW. Although there can be no assurance that TEP and Entegra will reach agreement on TEP's purchase of Gila River Unit 3, TEP anticipates that, if such an agreement is reached, definitive purchase and sale agreements would be executed prior to year-end 2013. TEP further anticipates any such purchase would close by year-end 2014 and would be subject to, among other things, the receipt of required regulatory approvals. UNS Electric may purchase up to 150 MW of Gila River Unit 3, while TEP would purchase the remaining capacity.
NOTE 14. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
TheIn April 2014, the Financial Accounting Standards Board (FASB) issued guidancean accounting standards update that changes the threshold for the recognition, measurement,reporting discontinued operations and disclosure of certain obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. On adoption, an entity would recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay, and any additional amount the entity expects to pay on behalf of its co-obligors.adds new disclosures. This guidance will be effective in the first quarter of 2014.2015. We do not expectare evaluating the adoption of this guidanceimpact to have a material impact on our financial condition, results of operations, or cash flows.
The FASB issued guidance which permits an entity to designate the Federal Funds Rate (the interest rate at which depository institutions lend balances to each other overnight) as a benchmark interest rate for fair valuestatements and cash flow hedges. Prior to this guidance, only interest rates on direct treasury obligations of the U.S. Government and the LIBOR were considered benchmark interest rates in the U.S. This guidance is effective immediately, and can be applied prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We have not entered into any new cash flow or fair value hedges since the effective date of this guidance. We do not expect this guidance to have a material impact on our financial condition, results of operations, or cash flows.
The FASB issued new guidance on the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. We will be required to comply with the guidance on a prospective basis beginning in the first quarter of 2014. Although adoption of this new guidance may impact how such items are classified on our balance sheets, we do not expect such change to be material. In addition, there will be no changes in the presentations of our other financial statements.
NOTE 15. REVIEW BY INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The UNS Energy and TEP condensed consolidated financial statements as of September 30, 2013, and for the three-month and nine-month periods ended September 30, 2013 and 2012, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their reports (dated November 6, 2013) are included on pages 1 and 2. The reports of PricewaterhouseCoopers LLP state that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their reports on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their reports on the unaudited financial information because neither of those reports is a “report” or a “part” of the registration statements prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.disclosures.
ITEM 2. – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Management’s Discussion and Analysis explains the results of operations, the general financial condition, and the outlook for UNS Energy and its three primary business segments. It includes the following:
outlook and strategies;
operating results during the thirdfirst quarter and first nine months of 20132014, compared with the same periods infirst quarter of 20122013;
factors affecting our results and outlook;
liquidity, capital needs, capital resources, and contractual obligations;
dividends; and
critical accounting estimates.
Management’s Discussion and Analysis should be read in conjunction with (i) UNS Energy’s and TEP's 2012 Annual Report on Form 10-K and (ii) the Condensed Consolidated Financial Statements that begin on page three of this document. The Condensed Consolidated Financial Statements present the results of operations for the three- and nine-month periods ended September 30, 2013 and 2012. Management’s Discussion and Analysis explains the differences between periods for specific line items of the Condensed Consolidated Financial Statements.
UNS ENERGY CORPORATION
OVERVIEW OF CONSOLIDATED BUSINESS
UNS Energy is a utility services holding company engaged, through its primary subsidiaries, in the electric generation and energy delivery business. Each of UNS Energy’s subsidiaries is a separate legal entity with its own assets and liabilities. UNS Energy owns 100% of TEP, and UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).
TEP is a regulated public utility and UNS Energy’s largest operating subsidiary, representing approximately 84% of UNS Energy’s total assets as of September 30, 2013.at March 31, 2014. TEP generates, transmits and distributes electricity to approximately 412,000414,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. Beginning on July 1, 2013, TEP revised its methodology for counting customers as a result of rate design changes from TEP's new retail rate structure. By applying the same revised methodology to the period ended September 30, 2012, TEP's retail customer count increased by approximately 0.8%.
TEP also sells electricity to other utilities and power marketing entities, located primarily in the western United States. In addition, TEP operates Springerville Generating Station (Springerville) Unit 3 on behalf of Tri-State and Springerville Unit 4 on behalf of Salt River Project Agricultural Improvement and Power District (SRP).SRP.
UES holds the common stock of two regulated public utilities, UNS Gas, Inc. (UNS Gas)Electric and UNS Electric, Inc. (UNS Electric). UNS Gas is a regulated gas distribution company, which services approximately 149,000 retail customers in Mohave, Yavapai, Coconino, and Navajo counties in northern Arizona, as well as in Santa Cruz County in southern Arizona.Gas. UNS Electric is a regulated public utility, which generates, transmits and distributes electricity to approximately 93,000 retail customers in Mohave and Santa Cruz counties.counties in Arizona. UNS Gas is a regulated gas distribution company, which services approximately 150,000 retail customers in Mohave, Yavapai, Coconino, Navajo, and Santa Cruz counties in Arizona.
UNS Energy's non-reportable business segments include Millennium Energy Holdings, Inc. (Millennium)UED and UniSource Energy Development (UED). UED's and Millennium'sMillennium’s investments in unregulated businesses represent less than 1% of UNS Energy'sEnergy’s assets as of September 30, 2013.March 31, 2014.
References in this report to “we” and “our” are to UNS Energy and its subsidiaries, collectively.
OUTLOOK AND STRATEGIES
Agreement and Plan of Merger
In December 2013, UNS Energy entered into an Agreement and Plan of Merger (Merger Agreement) with Fortis Parent, Fortis and Color Acquisition Sub, Inc. The Boards of Directors of each of UNS Energy and Fortis Parent have approved the Merger. At the completion of the Merger, each outstanding share of UNS Energy Common Stock will be converted into the right to receive $60.25 in cash and UNS Energy will become a wholly-owned subsidiary of Fortis.
UNS Energy's shareholders approved the merger at a meeting on March 26, 2014.
On April 2, 2014, the FERC issued an order approving the merger.
The merger is subject to the remaining closing conditions:
the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended;
approval of the ACC;
confirmation of review, without unresolved concerns, from the Committee on Foreign Investment in the United States; and
the absence of any injunction, order or other law prohibiting the merger.
In January 2014, UNS Energy and Fortis Parent filed an application and supporting testimony with the ACC requesting approval of the merger. Settlement discussions are scheduled to begin on May 5, 2014 and hearings before an ACC administrative law judge are expected to begin on June 16, 2014. The merger is expected to close by the end of 2014. If the merger is completed, UNS Energy expects to record approximately $19 million of merger-related expenses in 2014.
Operating Plans and Strategies
Our financial prospects and outlook are affected by many factors including: national, regional, and local economic conditions; volatility in the financial markets; environmental laws and regulations; and other regulatory factors. Our plans and strategies include the following:
Completing the proposed merger with Fortis including obtaining all necessary approvals;
Developing aCompleting the purchases of Gila River Unit 3 and certain interests in Springerville Unit 1, which are both key components of our long-term diversification strategy for our generating portfolio. We are evaluating several energy resource options including coal, natural gas, and renewable generating resources. The focus of our resource strategy is to provide long-term rate stability for our customers, mitigate environmental impacts, comply with regulatory requirements, and leverage our existing utility infrastructure.
Strengthening the underlying financial condition of our utility subsidiaries by achieving constructive regulatory outcomes, improving our capital structure and our credit ratings, and promoting economic development in our service territories.
Developing strategic responses to new environmental regulations and potential new legislation, including potential limits on greenhouse gas emissions. We are evaluating TEP's existing mix of generation resources and defining steps to achieve environmental objectives that protect the financial stability of our utility businesses.
Focusing on our core utility businesses through operational excellence, investing in utility rate base, emphasizing customer service, and maintaining a strong community presence.
Expanding TEP's and UNS Electric's portfolio of renewable energy resources and programs to meet Arizona's Renewable Energy Standard (RES) while creating ownership opportunities for renewable energy projects that benefit customers, shareholders, and the communities we serve.
Developing strategic responses to Arizona's Energy Efficiency StandardsArizona’s requirements for renewable energy, distributed generation, and energy efficiency that protect the financial stability of our utility businesses and providebusiness while providing benefits tofor our customers.
RESULTS OF OPERATIONS
Contribution by Business Segment
The table below shows the contributions to our consolidated net income by business segment:
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended March 31, |
| | 2013 | | 2012 | | 2013 | | 2012 | 2014 | | 2013 |
| | Millions of Dollars | Millions of Dollars |
| TEP | $ | 64 |
| | $ | 45 |
| | $ | 96 |
| | $ | 65 |
| $ | 9 |
| | $ | 1 |
|
| UNS Electric | | 2 |
| | 2 |
|
| UNS Gas | (1 | ) | | — |
| | 6 |
| | 5 |
| 5 |
| | 8 |
|
| UNS Electric | 5 |
| | 6 |
| | 11 |
| | 14 |
| |
Other Non-Reportable Segments and Adjustments (1) | — |
| | — |
| | 1 |
| | (1 | ) | (1 | ) | | — |
|
| Consolidated Net Income | $ | 68 |
| | $ | 51 |
| | $ | 114 |
| | $ | 83 |
| $ | 15 |
| | $ | 11 |
|
| |
(1) | Includes: UNS Energy parent company expenses; Millennium; UED; and intercompanyinter-company eliminations. |
Executive Overview
Third QuarterFirst quarter 2014 ofcompared with first quarter 2013 Compared with the Third Quarter of 2012
TEP
TEP reported net income of $649 million in the thirdfirst quarter of 20132014 compared with net income of $451 million in the third quarter of 2012.same period last year. The increase in net income is due in part to: a $30$7 million increase in retail margin revenues due to a Base Rate increase effective July 1, 2013; $5 million of LFCR revenues related to a non-fuel base rate increase that was effective on July 1, 2013 and higherreductions in retail kWh sales resulting from an increasedue to energy efficiency programs and distributed generation implemented in Cooling Degree Days;2013 (See Tucson Electric Power, Factors Affecting Results of Operations, 2013 TEP Rate Order and Note 3); a $1 million increase in the margin on long-term wholesale sales due to higher market prices for wholesale power; and a $2 million decrease in interest expense due in part to a redcutionreduction in capital lease obligation balances; partially offset by a $4 million increase in Base O&M due in part to unplanned maintenance on TEP's generating facilities. Results in the third quarter of 2012 reflect a $2 million reduction to pre-tax income due to an unplanned outage at Springerville Unit 3. See Tucson Electric Power Company, Results of Operations, for more information.
UNS Gas
UNS Gas reported a net loss of $1 million in the third quarter of 2013 compared with no net income or net loss in the third quarter of 2012. The decrease in net income is due in part to higher operations and maintenance expense. See UNS Gas, Results of Operations, for more information.
UNS Electric
UNS Electric reported net income of $5 million in the third quarter of 2013 compared with $6 million in the third quarter of 2012. The decrease in net income was due in part to the loss of an industrial customer in the second half of 2012. See UNS Electric, Results of Operations, for more information.
Nine Months Ended September 30, 2013 Compared with the Nine Months Ended September 30, 2012
TEP
TEP reported net income of $96 million in the first nine months of 2013 compared with net income of $65 million in the same period of 2012. The increase in net income is due in part to: a $32 million increase in retail margin revenues related to a non-fuel base rate increase that was effective on July 1, 2013 and higher retail kWh sales resulting from favorable weather conditions; a $2 million increase in the margin on long-term wholesale sales due to higher market prices for wholesale power; and a $6 million decrease in interest expense due in part to a reduction in capital lease obligation balances; partially offset by a $6 million increase in Base O&M due in part to unplannedplanned maintenance on TEP's generating facilities, during the first nine monthsas well as merger-related expenses of 2013;$1 million; and a $3$1 million increase in taxes other than income taxes due in part to an increase in property tax rates and higher asset balances.
Additionally, TEP's net income in the first nine months of 2013 includes an income tax benefit of $11 million. In June 2013, we recorded a regulatory asset and corresponding reduction of income tax expense of $11 million to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. The regulatory asset will be amortized as income tax expense as the qualifying assets are depreciated. See Note 6. TEP's year-to-date 2013 results also include additional fuel expense of $3 million related to a one-time credit to customers resulting from the 2013 TEP Rate Order. TEP's results in the first nine months of 2012 reflect a $3 million reduction to pre-tax income due to an unplanned outage at Springerville Unit 3. See Tucson Electric Power, Company, Results of Operations for more information..
UNS Electric
UNS Electric reported net income of $2 million in both the first quarters of 2014 and 2013. See UNS Electric, Results of Operations.
UNS Gas
UNS Gas reported net income of $65 million in the first nine monthsquarter of 20132014 compared with net income of $58 million in the same period of 2012.last year. The increasedecrease in net income is due primarily to:to lower sales volumes resulting from mild winter weather, which contributed to a $4 million increasedecline in retail margin revenues related to cold weather that contributed to a 9.6% increase in retail therm sales; and a non-fuel base rate increase that was effective in May 2012; partially offset by a $1 million increase in depreciation and amortization expense related to higher net plant in service.revenues. See UNS Gas, Results of Operations for more information.
UNS Electric
UNS Electric reported net income of $11 million in the first nine months of 2013 compared with net income of $14 million in the same period of 2012. The decrease in net income was due in part to the loss of an industrial customer in the second half of 2012. See UNS Electric, Results of Operations, for more information.
Operations and Maintenance Expense
The table below summarizes the items included in UNS Energy’s Operations and Maintenance (O&M) expense:expense. Base O&M in first quarter of 2014 includes merger-related expenses of $1 million.
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended March 31, |
| | 2013 | | 2012 | | 2013 | | 2012 | 2014 | | 2013 |
| | Millions of Dollars | | Millions of Dollars | Millions of Dollars |
UNS Energy Base O&M (Non-GAAP)(1) | $ | 68 |
| | $ | 61 |
| | $ | 208 |
| | $ | 198 |
| $ | 73 |
| | $ | 69 |
|
| Reimbursed Expenses Related to Springerville Units 3 and 4 | 18 |
| | 26 |
| | 49 |
| | 53 |
| 14 |
| | 14 |
|
Expenses Related to Customer-Funded Renewable Energy and Demand Side Management (DSM) Programs(2) | 7 |
| | 11 |
| | 21 |
| | 33 |
| |
Expenses Related to Customer-Funded Renewable Energy and DSM Programs(2) | | 6 |
| | 7 |
|
| Total UNS Energy O&M (GAAP) | $ | 93 |
| | $ | 98 |
| | $ | 278 |
| | $ | 284 |
| $ | 93 |
| | $ | 90 |
|
| |
(1) | Base O&M, a non-GAAP financial measure, should not be considered as an alternative to 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 business. Base O&M excludes expenses that are directly offset by revenues collected from customers and other third parties. |
| |
(2) | Represents expenses related to customer-funded renewable energy and DSM programs; these expenses are being collected from customers and the corresponding amounts are recorded in retail revenue. |
LIQUIDITY AND CAPITAL RESOURCES
UNS Energy Consolidated Liquidity
During 2013, UNS Energy expects its regulated subsidiaries to generate sufficient operating cash flows to fund the majority of its capital expenditures. Cash flows may vary during the year, with cash flow from operations typically the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, UNS Energy will use, as needed, its revolving credit facility to assist in funding its business activities. The table below provides a summary of the liquidity position of UNS Energy and each of its segments:
| | | Balances at September 30, 2013 | Cash and Cash Equivalents | | Borrowings under Revolving Credit Facility(1) | | Amount Available under Revolving Credit Facility | |
| Balances at March 31, 2014 | | Cash and Cash Equivalents | | Borrowings under Revolving Credit Facility(1) | | Amount Available under Revolving Credit Facility |
| | Millions of Dollars | Millions of Dollars |
| UNS Energy Stand-Alone | $ | 3 |
| | $ | 52 |
| | $ | 73 |
| $ | 2 |
| | $ | 57 |
| | $ | 68 |
|
| TEP | 35 |
| | 1 |
| | 199 |
| 88 |
| | 1 |
| | 199 |
|
UNS Electric(2) | | 6 |
| | 25 |
| | 45 |
|
UNS Gas(2) | 27 |
| | — |
| | 70 |
| 21 |
| | — |
| | 70 |
|
UNS Electric(2) | 4 |
| | 23 |
| | 47 |
| |
Other(3) | 3 |
| | N/A |
| | N/A |
| 3 |
| | N/A |
| | N/A |
|
| Total | $ | 72 |
| | | | | $ | 120 |
| | | | |
| |
(1) | Includes Letters of Credit (LOCs)LOCs issued under revolving credit facilities. |
| |
(2) | 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. |
| |
(3) | Includes cash and cash equivalents at Millennium and UED. |
TEP expects to provide, in the second quarter of 2014, an LOC for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. TEP's borrowing capacity under the TEP Credit Agreement would be reduced by $15 million until the Gila River transaction closes and the LOC is terminated.
Dividends from UNS Energy’s subsidiaries represent the parent company’s main source of liquidity.
Dividends from Subsidiaries
UNS Energy received $20 million in dividends from TEP and $10 million in dividends from each of UNS Gas and UNS Electric during the first nine months of 2013. During the first nine months of 2012, UNS Energy received $20 million in dividends from UNS Gas $14 million in dividends from Millennium,first three months of 2014 and $10 million in dividends from UNS Electric.2013.
Short-term Investments
UNS Energy’s short-term investment policy governs the investment of excess cash balances. We regularly review and update this policy in response to market conditions. At September 30, 2013March 31, 2014, UNS Energy’s short-term investments included highly-rated and liquid money market funds and certificates of deposit.
Access to Revolving Credit Facilities
We have access to working capital through revolving credit agreements with lenders. Each of these agreements is a committed facility that expires in November 2016. The TEP Revolving Credit Facility and UNS Gas/Electric/UNS ElectricGas Revolver may be used for revolving borrowings as well as to issue LOCs. TEP, UNS Gas,Electric, and UNS ElectricGas each issue LOCs from time to time to provide credit enhancement to counterparties for their energy procurement and hedging activities. The UNS Credit Agreement also may be used to issue LOCs for general corporate purposes.
We believe that we have sufficient liquidity under our revolving credit facilities to meet short-term working capital needs and to provide credit enhancement as necessary under energy procurement and hedging agreements. See Item 3. Quantitative and Qualitative Disclosures about Market Risk below..
UNS Energy Consolidated Cash Flows
| | | | Nine Months Ended September 30, | Three Months Ended March 31, |
| | 2013 | | 2012 | 2014 | | 2013 |
| | Millions of Dollars | Millions of Dollars |
| Operating Activities | $ | 305 |
| | $ | 268 |
| $ | 77 |
| | $ | 81 |
|
| Investing Activities | (239 | ) | | (192 | ) | (87 | ) | | (75 | ) |
| Financing Activities | (118 | ) | | (2 | ) | 55 |
| | (66 | ) |
| Net Increase (Decrease) in Cash | (52 | ) | | 74 |
| 45 |
| | (60 | ) |
| Beginning Cash | 124 |
| | 76 |
| 75 |
| | 124 |
|
| Ending Cash | $ | 72 |
| | $ | 150 |
| $ | 120 |
| | $ | 64 |
|
UNS Energy’s operating cash flows are generated primarily by retail and wholesale energy sales at TEP, UNS Gas,Electric, and UNS Electric,Gas, net of the related payments for fuel and purchased power. Generally, cash from operations is lowest in the first quarter and highest in the third quarter due to TEP’s summer-peaking load. TEP, UNS Gas,Electric, and UNS ElectricGas typically use their revolving credit facilities to assist in funding their business activities during periods when sales are seasonally lower.
Capital expenditures at TEP, UNS Gas,Electric, and UNS ElectricGas represent the primary use of cash for investing activities.
Cash used for investing and financing activities can fluctuate year-to-year depending on: capital expenditures; repayments and borrowings under revolving credit facilities; debt issuances or retirements; capital lease payments by TEP; and dividends paid by UNS Energy to its shareholders.
Operating Activities
In the first ninethree months of 2013,2014, net cash flows from operating activities were $374 million higherlower than they were in the same period last year. The following items affected the year-over-yearquarter-over-quarter change in operating cash flows: an $11 million decrease in operating cash flows at UNS Gas due to the return of the over-collected PGA balance to customers; partially offset by a $2 million increase in cash receipts from retail sales related to an increase in sales volumes from cold weather during the first three months of 2013, an increase in TEP's PPFAC rate that became effective in April 2012, and a non-fuel base rate increase that became effective on July 1, 2013; an increase in cash receipts from wholesale sales, net of fuel and purchased power costs paid, due in part to higher market prices for wholesale power; lowerBase Rate increases at TEP and UNS Electric; a $2 million decrease in interest paid on capital lease obligations due to a decline in the balance of capital lease obligations; and various timing differences compared with the first nine monthsa $2 million decrease in taxes paid, net of 2012.amounts capitalized, due to a decrease in sales tax rates effective in June 2013.
Investing Activities
Net cash flows used for investing activities increased $4712 million in the first ninethree months of 20132014 compared with the same period last year due in part to a lower$9 million decrease in the return of investmentsinvestment in Springerville lease debt and a decrease in proceeds from a note receivable, and an$7 million increase in REC purchases due to an increase in renewable energy PPAs.capital expenditures.
Capital Expenditures
|
| | | | | | | |
| | Actual Year-to-Date | | Full Year Estimate |
| | September 30, 2013 | | 2013 |
| | Millions of Dollars |
| TEP | $ | 180 |
| | $ | 255 |
|
| UNS Gas | 13 |
| | 14 |
|
| UNS Electric | 45 |
| | 52 |
|
| UNS Energy Consolidated | $ | 238 |
| | $ | 321 |
|
Financing Activities
Net cash flows used forfrom financing activities were $116121 million higher in the first ninethree months of 20132014 when compared with the same period last year due to: the issuance of $150 million of long-term debt by TEP duringin March 2014; partially offset by a $25 million decrease in borrowings (net of repayments) under the first nine months of 2012; an increase in scheduled capital lease payments; anrevolving credit facilities; and a $2 million increase in dividends paid on Common Stock; and a decrease in proceeds from borrowings (net of repayments) under revolving credit facilities.Stock.
UNS Credit Agreement
The UNS Credit Agreement, which expires in November 2016, consists of a $125 million revolving credit and LOC facility. At September 30, 2013March 31, 2014, there was $52$57 million outstanding at a weighted-average interest rate of 1.68%1.41%. The UNS Credit Agreement restricts additional indebtedness, liens, mergers, and sales of assets. The UNS Credit Agreement also requires UNS Energy to meet a minimum cash flow to debt service coverage ratio determined on a UNS Energy stand-alone basis. Additionally, UNS Energy cannot exceed a maximum leverage ratio determined on a consolidated basis. Under the terms of the UNS Credit Agreement, UNS Energy may pay dividends so long as it maintains compliance with the agreement. UNS Energy’s obligations under the agreement are secured by a pledge of the common stock of Millennium, UES, and UED.
At September 30, 2013March 31, 2014, we were in compliance with the terms of the UNS Credit Agreement.
Interest Rate Risk
UNS Energy is subject to interest rate risk resulting from changes in interest rates on its borrowings under the revolving credit facility. The interest paid on revolving credit borrowings is variable. UNS Energy may be required to pay higher rates of interest on borrowings under its revolving credit facility if LIBOR and other benchmark interest rates increase. See Item 3. Quantitative and Qualitative Disclosures about Market Risk below..
Contractual Obligations
There are no changes in our contractual obligations or other commercial commitments from those reported in our 20122013 Annual Report on Form 10-K, other than the following changes in 2013:2014:
We entered into new forward energy commitments with minimum payment obligationsIn March 2014, TEP issued $150 million of $2 million in 2014, $3 million in 2015 and $2 million in 2016.5.0% unsecured notes due March 2044. See Note 4.5.
In April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase its undivided ownership interests in the Springerville Coal Handling Facilities at the fixed purchase price of $120 million upon the expiration of the lease term in April 2015. Upon TEP's purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for approximately $24 million, and Tri-State is then obligated to either 1) buy a portion of the facilities for $24 million or 2) continue to make payments to TEP for the use of the facilities. See Note 5.
We entered into new forward purchased power commitments with minimum payment obligations of $15 million in 2014 and $62015. See Note 6.
We entered into new forward energy commitments with minimum payment obligations of $1 million in 2015. See Note 4.
TEP has a 20-year Power Purchase Agreement (PPA) with a renewable energy generation facility that achieved commercial operation in June 2013. TEP is obligated to purchase 100% of the output from this facility. TEP expects to make minimum payment obligations under this contract of approximately $2 million in 2013, $4 million per year from 2014 through 2017, and approximately $58 million total thereafter. See Note 4.
We entered into new purchase agreements to purchase the environmental attributes, or RECs, from retail customers with solar installations. Payments for these RECs are termed Performance-Based Incentives (PBIs) and are paid in contractually agreed-upon intervals, usually quarterly, based on metered renewable energy production over periods ranging from 9 to 20 years. Our total obligation related to RES PBI payments over future periods increased by $13 million from $68 million at December 31, 2012, to $81 million at September 30, 2013. PBIs are recoverable through the RES tariff. See Note 4.
In August 2013, TEP elected to purchase leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of continuous operating capability, for an aggregate purchase price of $46 million, the appraised value, upon the expiration of the lease term in January 2015. In October 2013, TEP elected to purchase an additional 10.6% leased interest in Springerville Unit 1, representing 41 MW of continuous operating capability, for $20 million, the appraised value, with the purchase scheduled to occur in December 2014. See Note 5.
We entered into new gas transportation agreements that will settle through 2023, resulting in an additional commitment of $7 million in 2013, $14 million in each of 2014, 2015, and 2016, $15 million in 2017, and $57 million thereafter. See Note 4.
In March 2013, $91 million of unsecured tax-exempt industrial development bonds were issued on behalf of TEP. The bonds bear interest at a rate of 4.0% and are due in September 2029. Proceeds were used to redeem $91 million of 2008 Pima Bonds bearing interest at a rate of 6.375% with the same maturity date. As a result, our interest obligations decreased by about $2 million per year. See Note 5.
In the first quarter of 2013, we reduced unrecognized tax benefits by $28 million based on a favorable ruling from the Internal Revenue Service (IRS) allowing us to deduct, rather than defer and amortize, up-front incentive payments to customers who install renewable energy resources. See Note 6.
Dividends on Common Stock
In the first ninethree months of 2013,2014, UNS Energy paid dividends on Common Stock of $54 million.$20 million. The following table shows the dividends declared to UNS Energy shareholders for 2013:2014:
|
| | | | | | | |
| Declaration Date | Record Date | | Payment Date | | Dividend Amount Per
Share of Common Stock |
| February 25, 2013 | March 13, 2013 | | March 25, 2013 | | $ | 0.435 |
|
| May 2, 2013 | June 7, 2013 | | June 26, 2013 | | $ | 0.435 |
|
| August 2, 2013 | September 3, 2013 | | September 25, 2013 | | $ | 0.435 |
|
|
| | | | | | | |
| Declaration Date | Record Date | | Payment Date | | Dividend Amount Per
Share of Common Stock |
| February 24, 2014 | March 13, 2014 | | March 25, 2014 | | $ | 0.48 |
|
Income Tax Position
The 2010 Federal Tax Relief Act and the American Taxpayer Relief Act of 2012 include provisions that make qualified property placed in service during 2012between 2010 and 2013 eligible for 50% bonus depreciation for tax purposes. In addition, the IRS issued new guidance related to the treatment of expenditures to maintain, replace, or improve property. These provisions are an acceleration of tax benefits UNS Energy and TEP otherwise would have received over 20 years. As a result of these provisions, UNS Energy and TEP do not expect to pay any federal or state income taxes through 2015.2017.
TUCSON ELECTRIC POWER COMPANY
RESULTS OF OPERATIONS
TEP’s financial condition and results of operations are the principal factors affecting the financial condition and results of operations of UNS Energy. The following discussion relates to TEP, unless otherwise noted.
ThirdFirst quarterof20132014 compared with the thirdfirst quarterof20122013
TEP reported net income of $649 million in the thirdfirst quarter of 20132014 compared with net income of $451 million in the thirdfirst quarter of 20122013. The following factors affected TEP’s results in the thirdfirst quarter of 20132014:
a $30$7 million increase in retail margin revenues due primarily to a non-fuel base rateBase Rate increase that was effective on July 1, 2013;
$5 million of LFCR revenues recorded in the first quarter of 2014 related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013. See Factors Affecting Results of Operations, 2013 TEP Rate Order, below, and Note 3;
a $1 million increase in the margin on long-term wholesale sales due in part to an increase in the market price for wholesale power;
a $2 million increase in pre-tax income related to the operation of Springerville Units 3 and 4. An unplanned outage at Springerville Unit 3 negatively affected results in the third quarter of 2012; and
a $2 million decrease in interest expense due to a reduction in the balance of capital lease obligations.obligations;
partially offset by:by
a $4 million increase in Base O&M due in part to higher unplannedscheduled generating plant maintenance expense.
Nine months ended September 30, 2013 compared with nine months ended September 30, 2012
TEP reported net income of $96 million in the first nine months of 2013 compared with net income of $65 million in the first nine months of 2012. The following factors affected TEP’s results in the first nine months of 2013:
a $32 million increase in retail margin revenues due to a non-fuel base rate increase that was effective on July 1, 2013expense, as well as favorable weather during the first nine monthsmerger-related expenses of 2013 compared with the same period last year. An increase in Heating Degree Days in the first quarter of 2013 and an increase in Cooling Degree Days during the second and third quarters of 2013 contributed to a 1.1% increase in retail kilowatt-hour (kWh) sales during the first nine months of 2013;
a $2 million increase in the margin on long-term wholesale sales due in part to an increase in the market price for wholesale power;
a $3 million increase in pre-tax income related to the operation of Springerville Units 3 and 4. An unplanned outage at Springerville Unit 3 negatively affected results in the first nine months of 2012;
a $6 million decrease in interest expense due to a reduction in the balance of capital lease obligations; and
an $11 million tax benefit related to a regulatory asset recorded in June 2013 to recover previously recorded income tax expense through future rates as a result of the 2013 TEP Rate Order. See Note 6
partially offset by
a one-time charge of $3 million recorded to fuel and purchased energy expense resulting from the 2013 TEP Rate Order. See Factors Affecting Results of Operations, Purchased Power and Fuel Adjustor Clause, below;
a $6 million increase in Base O&M due in part to higher unplanned generating plant maintenance expense;$1 million; and
a $3$1 million increase in taxes other than income taxes due in part to an increase in property tax rates and higher asset balances.
Utility Sales and Revenues
Changes in the number of customers, weather, economic conditions, and other factors affect retail sales of electricity. The table below provides a summary of TEP’s retail kWh sales, revenues, and weather data during the third quartersfirst quarters of 20132014 and 20122013:
| | | | Three Months Ended September 30, | | Increase (Decrease) | Three Months Ended March 31, | | Increase (Decrease) |
| | 2013 | | 2012 | | Amount | | Percent(1) | 2014 | | 2013 | | Amount | | Percent(1) |
| Energy Sales, kWh (in Millions): | | | | | | | | | | | | | | |
| Electric Retail Sales: | | | | | | | | | | | | | | |
| Residential | 1,354 |
| | 1,332 |
| | 22 |
| | 1.6 | % | 668 |
| | 793 |
| | (125 | ) | | (15.8 | )% |
Commercial | 652 |
| | 648 |
| | 4 |
| | 0.5 | % | 444 |
| | 451 |
| | (7 | ) | | (1.6 | )% |
| Industrial | 621 |
| | 616 |
| | 5 |
| | 0.9 | % | 471 |
| | 473 |
| | (2 | ) | | (0.4 | )% |
| Mining | 275 |
| | 275 |
| | — |
| | 0.1 | % | 279 |
| | 270 |
| | 9 |
| | 3.3 | % |
Other | 7 |
| | 7 |
| | — |
| | 5.7 | % | 9 |
| | 8 |
| | 1 |
| | 12.5 | % |
| Total Electric Retail Sales | 2,909 |
| | 2,878 |
| | 31 |
| | 1.1 | % | 1,871 |
| | 1,995 |
| | (124 | ) | | (6.2 | )% |
| Retail Margin Revenues (in Millions): | | | | | | | | | | | | | | |
| Residential | $ | 102 |
| | $ | 89 |
| | $ | 13 |
| | 14.9 | % | $ | 51 |
| | $ | 50 |
| | $ | 1 |
| | 2.0 | % |
| Commercial | 63 |
| | 52 |
| | 11 |
| | 19.9 | % | 34 |
| | 34 |
| | — |
| | — | % |
| Industrial | 31 |
| | 27 |
| | 4 |
| | 12.1 | % | 22 |
| | 19 |
| | 3 |
| | 15.8 | % |
| Mining | 11 |
| | 9 |
| | 2 |
| | 23.3 | % | 9 |
| | 6 |
| | 3 |
| | 50.0 | % |
| Other | — |
| | — |
| | — |
| | — | % | 1 |
| | 1 |
| | — |
| | — | % |
Total Retail Margin Revenues (Non-GAAP)(2)(3) | 207 |
| | 177 |
| | 30 |
| | 16.3 | % | 117 |
| | 110 |
| | 7 |
| | 6.4 | % |
| Fuel and Purchased Power Revenues | 94 |
| | 115 |
| | (21 | ) | | (18.4 | )% | 53 |
| | 64 |
| | (11 | ) | | (17.2 | )% |
| RES, DSM, and ECA Revenues | 11 |
| | 11 |
| | — |
| | (1.0 | )% | |
| RES, DSM, ECA, and LFCR Revenues | | 16 |
| | 11 |
| | 5 |
| | 45.5 | % |
| Total Retail Revenues (GAAP) | $ | 312 |
| | $ | 303 |
| | $ | 9 |
| | 2.5 | % | $ | 186 |
| | $ | 185 |
| | $ | 1 |
| | 0.5 | % |
Average Retail Margin Rate (Cents / kWh):(1) | | | | | | | | | | | | | | |
| Residential | 7.53 |
| | 6.67 |
| | 0.86 |
| | 12.9 | % | 7.63 |
| | 6.29 |
| | 1.34 |
| | 21.3 | % |
| Commercial | 9.62 |
| | 8.07 |
| | 1.55 |
| | 19.2 | % | 7.66 |
| | 7.54 |
| | 0.12 |
| | 1.6 | % |
| Industrial | 4.92 |
| | 4.43 |
| | 0.49 |
| | 11.1 | % | 4.67 |
| | 4.10 |
| | 0.57 |
| | 13.9 | % |
| Mining | 3.85 |
| | 3.13 |
| | 0.72 |
| | 23.0 | % | 3.23 |
| | 2.41 |
| | 0.82 |
| | 34.0 | % |
| Other | 5.66 |
| | 5.98 |
| | (0.32 | ) | | (5.4 | )% | 11.11 |
| | 12.50 |
| | (1.39 | ) | | (11.1 | )% |
| Average Retail Margin Revenue | 7.09 |
| | 6.17 |
| | 0.92 |
| | 14.9 | % | 6.25 |
| | 5.51 |
| | 0.74 |
| | 13.4 | % |
| Average Fuel and Purchased Power Revenue | 3.23 |
| | 4.00 |
| | (0.77 | ) | | (19.3 | )% | 2.83 |
| | 3.22 |
| | (0.39 | ) | | (12.1 | )% |
| Average RES & DSM Revenue | 0.36 |
| | 0.36 |
| | — |
| | NM |
| |
| Average RES, DSM, ECA and LFCR Revenue | | 0.86 |
| | 0.54 |
| | 0.32 |
| | 59.3 | % |
| Total Average Retail Revenue | 10.68 |
| | 10.53 |
| | 0.15 |
| | 1.4 | % | 9.94 |
| | 9.27 |
| | 0.67 |
| | 7.2 | % |
| | | | | | | | | | | |
| Weather Data: | | | | | | | | | | | | | | |
| Cooling Degree Days | | | | | | | | |
| Three Months Ended September 30, | 1,042 |
| | 957 |
| | 85 |
| | 8.9 | % | |
| Heating Degree Days | | | | | | | | |
| Three Months Ended March 31, | | 429 |
| | 953 |
| | (524 | ) | | (55.0 | )% |
| 10-Year Average | 992 |
| | 990 |
| | NM |
| | NM |
| 777 |
| | 821 |
| | NM |
| | NM |
|
| Wholesale Energy Market Indicators: | | | | | | | | |
Power Prices ($ / MWh) (3) | $ | 41.21 |
| | $ | 35.85 |
| | $ | 5.36 |
| | 15.0 | % | |
Natural Gas Prices ($ / MMBtu) (4) | $ | 3.45 |
| | $ | 2.78 |
| | $ | 0.67 |
| | 24.1 | % | |
| |
(1) | Calculated on un-rounded data and may not correspond exactly to data shown in table. |
| |
(2) | Retail kWh sales to commercial and other customers for 2013 have been adjusted to reflect a change in the methodology for counting customers resulting from rate design changes from the 2013 TEP Rate Order. |
| |
(3) | Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude: (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 non-fuel operating expenses of our core utility business. |
| |
(3)
| On-peak market price of energy is based on the Intercontinental Exchange Palo Verde Index. |
| |
(4)
| Average market price for natural gas is based on the Permian Index. |
Residential
Residential kWh sales were 1.6% higher in the third quarter of 2013 than they were during the same period last year due in part to an increase in Cooling Degree Days. The higher sales volumes combined with a non-fuel base rate increase effective July 1, 2013 led to an increase in residential margin revenues of 14.9%, or $13 million. Residential use per customer increased by 0.8% due in part to warmer weather. The average number of residential customers grew by 0.8% in the third quarter of 2013 compared with the same period last year.
Commercial
Commercial kWh sales increased by 0.5% compared with the third quarter of 2012 due in part to more Cooling Degree Days than last year. The higher sales combined with a non-fuel base rate increase effective July 1, 2013 lead to an increase in commercial margin revenues of 19.9%, or $11 million.
Industrial
Industrial kWh sales increased by 0.9% compared with the third quarter of 2012, and industrial margin revenues increased by 12.1%, or $4 million when compared with the same period in 2012. The increase in industrial retail margins primarily resulted from a non-fuel base rate increase effective July 1, 2013.
Mining
Mining kWh sales increased by 0.1% compared with the third quarter of 2012. Margin revenues from mining customers increased by $2 million due in part to a non-fuel base rate increase effective July 1, 2013. See Factors Affecting Results of Operations, Sales to Mining Customers, below.
The table below provides a summary of TEP’sRetail kWh Sales and Margin Revenues
TEP's total retail kWh sales revenues, and weather data duringdecreased by 6.2% in the first quarter of nine2014 monthsprimarily due to a 55.0% decrease in heating degree days compared with the first quarter of 2013 and . Despite the mild weather, total retail margin revenues increased by $7 million, or 6.4%, due to a Base Rate increase that was effective on July 1, 2013.2012: |
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, | | Increase (Decrease) |
| | 2013 | | 2012 | | Amount | | Percent(1) |
| Energy Sales, kWh (in Millions): | | | | | | | |
| Electric Retail Sales: | | | | | | | |
| Residential | 3,149 |
| | 3,085 |
| | 64 |
| | 2.1 | % |
| Commercial | 1,702 |
| | 1,682 |
| | 20 |
| | 1.2 | % |
| Industrial | 1,638 |
| | 1,628 |
| | 10 |
| | 0.6 | % |
| Mining | 803 |
| | 818 |
| | (15 | ) | | (1.7 | )% |
| Other | 23 |
| | 23 |
| | — |
| | 2.2 | % |
| Total Electric Retail Sales | 7,314 |
| | 7,236 |
| | 78 |
| | 1.1 | % |
| Retail Margin Revenues (in Millions): | | | | | | | |
| Residential | $ | 218 |
| | $ | 202 |
| | $ | 16 |
| | 7.9 | % |
| Commercial | 144 |
| | 132 |
| | 12 |
| | 8.5 | % |
| Industrial | 74 |
| | 71 |
| | 3 |
| | 4.7 | % |
| Mining | 25 |
| | 23 |
| | 2 |
| | 8.7 | % |
| Other | 1 |
| | 1 |
| | — |
| | 8.3 | % |
Total Retail Margin Revenues (Non-GAAP)(2) | 461 |
| | 429 |
| | 32 |
| | 7.6 | % |
| Fuel and Purchased Power Revenues | 245 |
| | 256 |
| | (11 | ) | | (4.4 | )% |
| RES, DSM, and ECA Revenues | 33 |
| | 32 |
| | 1 |
| | 3.4 | % |
| Total Retail Revenues (GAAP) | $ | 739 |
| | $ | 717 |
| | $ | 22 |
| | 3.1 | % |
Average Retail Margin Rate (Cents / kWh):(1) | | | | | | | |
| Residential | 6.90 |
| | 6.53 |
| | 0.37 |
| | 5.7 | % |
| Commercial | 8.43 |
| | 7.87 |
| | 0.56 |
| | 7.1 | % |
| Industrial | 4.53 |
| | 4.35 |
| | 0.18 |
| | 4.1 | % |
| Mining | 3.12 |
| | 2.83 |
| | 0.29 |
| | 10.2 | % |
| Other | 5.65 |
| | 5.33 |
| | 0.32 |
| | 6.0 | % |
| Average Retail Margin Revenue | 6.31 |
| | 5.93 |
| | 0.38 |
| | 6.4 | % |
| Average Fuel and Purchased Power Revenue | 3.35 |
| | 3.54 |
| | (0.19 | ) | | (5.4 | )% |
| Average RES & DSM Revenue | 0.45 |
| | 0.44 |
| | 0.01 |
| | 2.3 | % |
| Total Average Retail Revenue | 10.11 |
| | 9.91 |
| | 0.20 |
| | 2.0 | % |
| | | | | | |
| Weather Data: | | | | | | | |
| Cooling Degree Days | | | | | | | |
| Nine Months Ended September 30, | 1,619 |
| | 1,523 |
| | 96 |
| | 6.3 | % |
| 10-Year Average | 1,456 |
| | 1,443 |
| | NM |
| | NM |
|
| Heating Degree Days | | | | | | | |
| Nine Months Ended September 30, | 983 |
| | 790 |
| | 193 |
| | 24.4 | % |
| 10-Year Average | 867 |
| | 845 |
| | NM |
| | NM |
|
| Wholesale Energy Market Indicators: | | | | | | | |
Power Prices ($ / MWh) (3) | $ | 37.16 |
| | $ | 28.91 |
| | $ | 8.25 |
| | 28.5 | % |
Natural Gas Prices ($ / MMBtu) (4) | $ | 3.57 |
| | $ | 2.46 |
| | $ | 1.11 |
| | 45.1 | % |
| |
(1)
| Calculated on un-rounded data and may not correspond exactly to data shown in table. |
| |
(2)
| Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Retail Margin Revenues exclude: (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 non-fuel operating expenses of our core utility business. |
| |
(3)
| On-peak market price of energy is based on the Intercontinental Exchange Palo Verde Index. |
| |
(4)
| Average market price for natural gas is based on the Permian Index. |
Residential
ResidentialMining kWh sales wereincreased by 2.1%3.3% higher incompared with the first nine monthsquarter of 2013 due in part to favorable weather conditions compared with the same period last year. Higher sales and a non-fuel base rate increase effective July 1, 2013 led to an increase in residential margin revenues of 7.9%, or $16 million. The average number of residential customers grew by 0.7% in the first nine months of 2013 compared with the same period last year.
Commercial
Commercial kWh sales increased by 1.2% compared with the first nine months of 2012. Higher sales and a non-fuel base rate increase effective July 1, 2013 contributed to an increase in commercial margin revenues of 8.5%, or $12 million.
Industrial
Industrial kWh sales increased by 0.6% compared with the first nine months of 2012. Higher sales and a non-fuel base rate increase effective July 1, 2013 lead to an increase in industrial margin revenues of $3 million.
Mining
Mining kWh sales decreased by 1.7% compared with the first nine months of 2012. Oneone of TEP's mining customers performedperforming maintenance on its facilities resulting in a temporary decrease in production. See Factors Affecting Results of Operations, Sales to Mining Customers, below.last year.
Wholesale Sales and Transmission Revenues
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended March 31, |
| | 2013 | | 2012 | | 2013 | | 2012 | 2014 | | 2013 |
| | Millions of Dollars | | Millions of Dollars | Millions of Dollars |
| Long-Term Wholesale Revenues: | | | | | | | | | | |
Long-Term Wholesale Margin Revenues (Non-GAAP)(1) | $ | 2 |
| | $ | 1 |
| | $ | 5 |
| | $ | 3 |
| |
| Long-Term Wholesale Margin Revenues (Non-GAAP)(1) | | $ | 3 |
| | $ | 2 |
|
| Fuel and Purchased Power Expense Allocated to Long- Term Wholesale Revenues | 4 |
| | 6 |
| | 14 |
| | 15 |
| 5 |
| | 6 |
|
| Total Long-Term Wholesale Revenues | 6 |
| | 7 |
| | 19 |
| | 18 |
| 8 |
| | 8 |
|
| Transmission Revenues | 4 |
| | 4 |
| | 11 |
| | 12 |
| 4 |
| | 4 |
|
| Short-Term Wholesale Revenues | 17 |
| | 14 |
| | 61 |
| | 47 |
| 30 |
| | 22 |
|
| Electric Wholesale Sales (GAAP) | $ | 27 |
| | $ | 25 |
| | $ | 91 |
| | $ | 77 |
| $ | 42 |
| | $ | 34 |
|
| |
(1) | 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. |
Long-Term Wholesale Margin Revenues in the thirdfirst quarter and first nine months of 20132014 were higher than the same periods in 2012when compared with first quarter of 2013 due in part to higher market prices for wholesale power. See Factors Affecting Results of Operations, Long-Term Wholesale Sales, below.
Short-Term Wholesale Revenues
All revenues from short-term wholesale sales and 10% of the profits from wholesale trading activity are credited against the fuel and purchased power costs eligible for recovery in the PPFAC.
Other Revenues
| | | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended March 31, |
| | 2013 | | 2012 | | 2013 | | 2012 | 2014 | | 2013 |
| | Millions of Dollars | | Millions of Dollars | Millions of Dollars |
Revenue related to Springerville Units 3 and 4(1) | $ | 27 |
| | $ | 31 |
| | $ | 73 |
| | $ | 74 |
| $ | 21 |
| | $ | 21 |
|
| Other Revenue | 7 |
| | 8 |
| | 21 |
| | 22 |
| 6 |
| | 7 |
|
| Total Other Revenue | $ | 34 |
| | $ | 39 |
| | $ | 94 |
| | $ | 96 |
| $ | 27 |
| | $ | 28 |
|
| |
(1) Represents revenues and reimbursements from Tri-State and SRP, owners of Springerville Units 3 and 4, respectively, to TEP related to the operation of these plants.
| Represents revenues and reimbursements from Tri-State and SRP, owners of Springerville Units 3 and 4, respectively, to TEP related to the operation of these plants. |
In addition to reimbursements related to Springerville Units 3 and 4, TEP’s other revenues include inter-company revenues from UNS Gas and UNS Electric for corporate services provided by TEP, and miscellaneous service-related revenues such as rent on power pole attachments, damage claims, and customer late fees.
Operating Expenses
Generating Output and Fuel and Purchased Power Expense
Total generating output decreased in the first quarter of 2014 when compared with first quarter of 2013 due in part to lower retail kWh sales than the same period last year.
TEP’s fuel and purchased power expense and energy resources for the first quarters of three and nine months ended September 30,20132014 and 20122013 are detailed below:
|
| | | | | | | | | | | | | |
| | Generation and Purchased Power | | Fuel and Purchased Power Expense |
| | Three Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | Millions of kWh | | Millions of Dollars |
| Coal-Fired Generation | 2,616 |
| | 2,577 |
| | $ | 66 |
| | $ | 64 |
|
| Gas-Fired Generation | 329 |
| | 491 |
| | 14 |
| | 23 |
|
| Renewable Generation | 8 |
| | 10 |
| | — |
| | — |
|
| Reimbursed Fuel Expense for Springerville Units 3 and 4 | — |
| | — |
| | 2 |
| | 1 |
|
| Total Fuel | 2,953 |
| | 3,078 |
| | 82 |
| | 88 |
|
| Total Purchased Power | 875 |
| | 759 |
| | 42 |
| | 28 |
|
| Transmission and Other PPFAC Recoverable Costs | — |
| | — |
| | 5 |
| | 2 |
|
| Increase (Decrease) to Reflect PPFAC Recovery Treatment | — |
| | — |
| | (8 | ) | | 20 |
|
| Total Resources | 3,828 |
| | 3,837 |
| | $ | 121 |
| | $ | 138 |
|
| Less Line Losses and Company Use | (261 | ) | | (242 | ) | | | | |
| Total Energy Sold | 3,567 |
| | 3,595 |
| | | | |
|
| | | | | | | | | | | | | |
| | Generation and Purchased Power | | Fuel and Purchased Power Expense |
| | Nine Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | Millions of kWh | | Millions of Dollars |
| Coal-Fired Generation | 7,726 |
| | 7,247 |
| | $ | 208 |
| | $ | 182 |
|
| Gas-Fired Generation | 747 |
| | 1,187 |
| | 34 |
| | 51 |
|
| Renewable Generation | 31 |
| | 35 |
| | — |
| | — |
|
| Reimbursed Fuel Expense for Springerville Units 3 and 4 | — |
| | — |
| | 5 |
| | 5 |
|
| Total Fuel | 8,504 |
| | 8,469 |
| | 247 |
| | 238 |
|
| Total Purchased Power | 1,848 |
| | 1,854 |
| | 90 |
| | 62 |
|
| Transmission and Other PPFAC Recoverable Costs | — |
| | — |
| | 8 |
| | 4 |
|
| Increase (Decrease) to Reflect PPFAC Recovery Treatment | — |
| | — |
| | (5 | ) | | 25 |
|
| Total Resources | 10,352 |
| | 10,323 |
| | $ | 340 |
| | $ | 329 |
|
| Less Line Losses and Company Use | (680 | ) | | (669 | ) | | | | |
| Total Energy Sold | 9,672 |
| | 9,654 |
| | | | |
Generation |
| | | | | | | | | | | | | |
| | Generation and Purchased Power | | Fuel and Purchased Power Expense |
| | Three Months Ended March 31, |
| | 2014 | | 2013 | | 2014 | | 2013 |
| | Millions of kWh | | Millions of Dollars |
| Coal-Fired Generation | 2,296 |
| | 2,471 |
| | $ | 56 |
| | $ | 71 |
|
| Gas-Fired Generation | 239 |
| | 186 |
| | 11 |
| | 8 |
|
| Renewable Generation | 10 |
| | 11 |
| | — |
| | — |
|
| Reimbursed Fuel Expense for Springerville Units 3 and 4 | — |
| | — |
| | 1 |
| | 2 |
|
| Total Fuel | 2,545 |
| | 2,668 |
| | 68 |
| | 81 |
|
| Total Purchased Power | 441 |
| | 428 |
| | 22 |
| | 19 |
|
| Transmission and Other PPFAC Recoverable Costs | — |
| | — |
| | 4 |
| | 1 |
|
| Increase (Decrease) to Reflect PPFAC Recovery Treatment | — |
| | — |
| | (2 | ) | | (3 | ) |
| Total Resources | 2,986 |
| | 3,096 |
| | $ | 92 |
| | $ | 98 |
|
| Less Line Losses and Company Use | (169 | ) | | (170 | ) | | | | |
| Total Energy Sold | 2,817 |
| | 2,926 |
| | | | |
Total generating output increased during the first nine months of 2013 when compared with the same period last year due in part to higher retail kWh sales than the same period last year. Coal-fired generation increased by 6.6% during the first nine months of 2013 when compared with the same period last year due in part to the use of coal to fuel Sundt Unit 4 instead of natural gas.
Purchased Power
Purchased power volumes decreased during the first nine months of2013 compared with the same period last year due in part to higher output from TEP's generating facilities.
The table below summarizes TEP’s average fuel cost per kWh generated or purchased:
| | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended March 31, |
| | | 2013 | | 2012 | | 2013 | | 2012 | 2014 | | 2013 |
| | | cents per kWh | | cents per kWh | cents per kWh |
| Coal | | 2.53 |
| | 2.49 |
| | 2.70 |
| | 2.50 |
| 2.42 |
| | 2.87 |
|
| Gas | | 4.35 |
| | 4.69 |
| | 4.55 |
| | 4.31 |
| 4.61 |
| | 4.36 |
|
| Purchased Power | | 4.85 |
| | 3.63 |
| | 4.86 |
| | 3.35 |
| 5.13 |
| | 4.42 |
|
| All Sources | | 3.63 |
| | 3.28 |
| | 3.56 |
| | 3.15 |
| 3.34 |
| | 3.44 |
|
O&M
The table below summarizes the items included in TEP’s O&M expense.
Base O&M in first quarter of 2014 includes merger-related expenses of $1 million. | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | Three Months Ended March 31, |
| | 2013 | | 2012 | | 2013 | | 2012 | 2014 | | 2013 |
| | Millions of Dollars | | Millions of Dollars | Millions of Dollars |
Base O&M (Non-GAAP)(1) | $ | 57 |
| | $ | 53 |
| | $ | 179 |
| | $ | 173 |
| $ | 64 |
| | $ | 60 |
|
| O&M Recorded in Other Expense | (2 | ) | | (1 | ) | | (6 | ) | | (3 | ) | (2 | ) | | (2 | ) |
| Reimbursed Expenses Related to Springerville Units 3 and 4 | 18 |
| | 26 |
| | 49 |
| | 53 |
| 14 |
| | 14 |
|
Expenses Related to Customer Funded Renewable Energy and DSM Programs(2) | 6 |
| | 9 |
| | 17 |
| | 25 |
| 5 |
| | 6 |
|
| Total O&M (GAAP) | $ | 79 |
| | $ | 87 |
| | $ | 239 |
| | $ | 248 |
| $ | 81 |
| | $ | 78 |
|
| |
(1) | Base O&M is a non-GAAP financial measure and should not be considered as an alternative to O&M, which is determined in accordance with GAAP. TEP believes that Base O&M, which is O&M less reimbursed expenses and expenses related to customer-funded renewable energy and DSM programs, provides useful information to investors because it represents the fundamental level of operating and maintenance expense related to our core business. |
| |
(2) | Represents expenses related to customer-funded renewable energy and DSM programs; these expenses are being collected from customers and the corresponding amounts are recorded in retail revenue. |
The table below summarizes TEP’s pension and other retiree benefit expenses included in TEP's Base O&M in the first quarters of 2014 and 2013: |
| | | | | | | |
| | Three Months Ended March 31, |
| | 2014 | | 2013 |
| | Millions of Dollars |
| Pension Expense Charged to O&M | $ | 2 |
| | $ | 3 |
|
| Retiree Benefit Expense Charged to O&M | 1 |
| | 1 |
|
| Total | $ | 3 |
| | $ | 4 |
|
FACTORS AFFECTING RESULTS OF OPERATIONS
2013 TEP Rate Order
In June 2013, the ACC issued an order (2013 TEP Rate Order) that resolved the rate case filed by TEP in July 2012, which was based on a test year ended December 31, 2011. The 2013 TEP Rate Order approved new rates effective July 1, 2013.
The provisions of the 2013 TEP Rate Order include, but are not limited to:
anAn increase in non-fuel retail Base Rates of approximately $76 million over adjusted test year revenues;
an Original Cost Rate Base (OCRB) of approximately $1.5 billion and a Fair Value Rate Base (FVRB) of approximately $2.3 billion;
a return on equity of 10.0%, a long-term cost of debt of 5.18%, and a short-term cost of debt of 1.42%, resulting in a weighted average cost of capital of 7.26%;
a capital structure of approximately 43.5% equity, 56.0% long-term debt, and 0.5% short-term debt;
a 0.68% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $800 million);million.
aA revision in depreciation rates from an average rate of 3.32% to 3.0% for generation and distribution plant regulated by the ACC, primarily due to revised estimates of asset removal costs, which will have the effect of reducing depreciation expense by approximately $11$11 million annually; andannually.
an agreement by TEP to seek recovery of costs related to the Nogales transmission line from the Federal Energy Regulatory Commission (FERC) before seeking rate recovery from the ACC.
The 2013 TEP Rate Order also approved the following cost recovery mechanisms:
A Lost Fixed Cost RecoveryAn LFCR mechanism (LFCR) that allows TEP to recover certain non-fuel costs that would otherwise go unrecovered due to reduced retail kWh sales attributed to energy efficiency programs and distributed generation. The LFCR rate will be adjusted annually and is subject to ACC approvalreview and a year-over-year cap of 1% of TEP's total retail revenues. TEP expects to file its first LFCR report with the ACC on or before May 15, 2014. That report may include an estimated $2 million to $4 million of unrecovered non-fuel costs incurred during calendar year 2013. We expect the new LFCR rate to become effective on July 1, 2014. TEP’s 2015TEP recorded LFCR report may include an estimated $6revenues of $5 million in the first quarter of 2014 related to $8reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013. See Note 3. TEP estimates that it will record total LFCR revenues of approximately $10 million of unrecovered non-fuel costs incurred during 2014.
An Environmental Compliance Adjustor (ECA) mechanism that allows TEP to recover the costs of complying with environmental standards required by federal or other governmental agencies between rate cases. The ECA will be adjusted annually to recover environmental compliance costs and is subject to ACC approval and a cap of $0.00025 per kWh, which approximates 0.25% of TEP's total retail revenues. TEP expects to filefiled its first ECA report in March 2014 to recover the return on or before March 1, 2014. That report will includeand of qualified investments and costs to be included in the ECA.of approximately $3 million. TEP expects the new ECA rate to become effective on May 1, 2014. We estimateTEP estimates that theit will record total ECA could benefit pre-tax income byrevenues of less than $1 million in 2014.
An energy efficiency provision which includes a 2013 calendar year budget to fund programs that support the ACC's Electric Energy Efficiency Standards (Electric EE Standards), as well as a performance incentive. See Electric Energy Efficiency Standards, below.
A new rate under TEP's PPFAC. See Purchased Power and Fuel Adjustment Clause, below.
Competition
Retail Electric Competition Rules
In 1999, the ACC approved the Rules that provided a framework for the introduction of retail electric competition in Arizona. Certain portions of the ACC Rules that enabled Electric Service Providers (ESPs) to compete in the retail market were invalidated by an Arizona Court of Appeals decision in 2004. During 2012, a small number of companies filed applications for a Certificate of Convenience and Necessity (CC&N) with the ACC to provide competitive retail electric services in TEP's service territory as an ESP. Unless and until the ACC clarifies the Rules and/or grants a CC&N to an ESP, it is not possible for TEP's retail customers to use an alternative ESP.
In May 2013, the ACC voted to commence a process to consider the possibility of opening Arizona to retail electric competition. The first step in the process was to solicit comments on questions raised by the ACC on the potential benefits and risks to Arizona electric customers associated with retail electric competition. In July 2013, various parties, including TEP and UNS Electric, filed comments. TEP and UNS Electric oppose opening Arizona to retail electric competition. Responsive comments from the parties were filed in August 2013. In September 2013, the ACC voted to close the docket and did not take any steps to implement retail electric competition. We cannot predict if the ACC will consider retail electric competition in the future.
Technological Developments and Energy Efficiency
New technological developments and the implementation of Electric EE Standards have reduced energy consumption by TEP's retail customers. TEP's customers also have the ability to install renewable energy technologies and conventional generation units that could reduce their reliance on TEP's services. In the wholesale energy market, TEP competes with other utilities, power marketers, and independent power producers in the sale of electric capacity and energy.
Coal-Fired Generating Resources
At September 30, 2013March 31, 2014 , approximately 70% of TEP's generating capacity was fueled by coal (of which 120 MW can be converted to 156 MW of natural gas capacity)capacity at Sundt Unit 4). Existing and proposed federal environmental regulations, as well potential changes in state regulation, may increase the cost of operating coal-fired generating facilities. TEP is evaluating various strategies for reducing the proportion of coal in its fuel mix. TEP's ability to reduce its coal-fired generating capacity will depend on several factors, including, but not limited to:
the resolution of the non-binding agreement between the State of New Mexico, the EPA, and PNM as it relates to San Juan, (see seeNote Part II, Item. 5 - Other Information, Environmental Matters;
TEP's option to permanently convert Sundt Unit 4 to be fueled by natural gas, see) Part II, Item. 5 - Other Information, Environmental Matters;
TEP's future ownership interest in Springerville Unit 1, (seesee Springerville Unit 1, below);below; and
the potentialplanned purchase of Gila River Unit 3, a combined cycle natural gas plant, (seesee Gila River Generating Station Unit 3,, below). below.
Springerville Unit 1
TEP leases Unit 1 of the Springerville Generating Station and an undivided one-half interest in certain Springerville Common Facilities (collectively Springerville Unit 1) under seven separate lease agreements (Springerville Unit 1 Leases) that are accounted for as capital leases. The leases expire in January 2015 and include fair market value renewal and purchase options. In 2006, TEP purchased a 14.1% undivided ownership interest in Springerville Unit 1, representing approximately 55 megawatts (MW)MW of continuous operating capability.capacity.
In 2011, TEP and the owner participants of Springerville Unit 1 completed a formal appraisal procedure to determine the fair market value purchase price of Springerville Unit 1 in accordance with the Springerville Unit 1 Leases. The purchase price was determined to be $478 per kW of capacity based on a continuous capacity rating of 387 MW.
On August 29,During 2013, TEP notified certain owner participants and their lessors that TEP electedagreed to purchase their undivided ownership interests in Springerville Unit 1 at the appraised value upon the expiration of the lease term in January 2015. In total, TEP elected to purchase leased interests comprising 24.8% of Springerville Unit 1, representing 96 MW of continuous operating capability, for an aggregatetotaling 35.4%, or 137 MW. The purchase price is the same as the appraisal value of $46$478 per kW, or approximately $65 million.
On October 3, 2013, TEP agreed to purchase an additional 10.6% leased interest in Springerville Unit 1 for $20 million, the appraised value, with the purchase scheduled to occur in December 2014. The 10.6% ownership interest represents 41 MW of continuous operating capability.
Upon the close of these lease option purchases in December 2014 and January 2015, TEP will own 49.5% of Springerville Unit 1, or 192 MW of continuous operating capability.capacity. Due to TEP’s purchase commitments, TEP and UNS Energy expect to recordrecorded an increase to both Utility Plant Under Capital Leases and Capital Lease Obligations on their balance sheets in the aggregate amount of approximately $55 million, of which $39 million is reflected as of September 30, 2013.million.
TEP does not expect that its final undivided ownership interest in Springerville Unit 1 will exceed 49.5%, or 192 MW of continuous operating capability.capacity. The remaining 50.5% of Springerville Unit 1, or 195 MW of capacity, will be owned by third parties. TEP is not obligated to purchase any of the remaining power from Springerville Unit 1; however, TEP is obligated to operate Springerville Unit 1 for the remaining third-party owners following the expiration of the leases.
Because TEP expects to replace the owner participants whose195 MW of expiring leased interests TEP elected to purchase have agreed to sell their interests for amounts equal to the appraised value, TEP dismissed the legal action associatedcapacity with the appraisal.purchase of Gila River Unit 3. See Part II, Item 1. Legal Proceedings, SpringervilleGila River Generating Station Unit 1 Appraisal3., below.
Gila River Generating Station Unit 3
In AugustDecember 2013, TEP and UNS Electric entered into exclusive negotiations with Entegra Power Group LLC (Entegra)an agreement (the Purchase Agreement) to purchase Gila River Unit 3 for $219 million from a subsidiary of Entegra. The purchase price is subject to adjustments to prorate certain fees and expenses through the closing and in respect of certain operational matters. It is anticipated that TEP will purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million and UNS Electric will purchase the remaining 25% undivided interest (137 MW) for approximately $55 million, although TEP and UNS Electric may modify the percentage ownership allocation between them. We expect the transaction to close in December 2014.
The Purchase Agreement is subject to, among other things:
the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended;
the approval of the FERC;
an amendment satisfactory to TEP, UNS Electric and the owners of the other units of the Gila River GeneratingPower Station (Gila River Unit 3)of the agreement with the other unit owners to address the ownership, operations and maintenance of common facilities and future generation located in Gila Bend, Arizona.at the station;
the completion of certain other agreements associated with the operation of Gila River Unit 3 is3; and
other customary closing conditions.
TEP expects to provide, in the second quarter of 2014, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW. Entegra provided a proposal in responseLOC for $15 million to TEP's request for proposals for generating capacity issued in May 2013. UNS Electric may purchase up to 150 MWthe seller of Gila River Unit 3 whileto satisfy a condition of the Purchase Agreement. The seller of Gila River Unit 3 would be entitled to draw upon the LOC and apply such amount as liquidated damages if it has validly terminated the Purchase Agreement as a result of misrepresentations by TEP would purchase the remaining capacity. See and UNS Electric Factors Affecting Resultsor the failure of Operations, Gila River Generating Station Unit 3, for more information. See Note 13.TEP and UNS Electric to close the transaction when the closing conditions have been satisfied. Upon the close of the transaction, the LOC would be canceled.
The purchase of Gila River Unit 3, which would replace the forgoneexpiring coal-fired leased capacity from Springerville Unit 1 and the expected reduction of coal-fired generating capacity from San Juan Unit 2, would beis consistent with TEP's strategy to diversify its generation fuel mix. See Note 46.
Although there can be no assurance that TEP and Entegra will reach agreement on the purchase by TEP of Gila River Unit 3, TEP anticipates that, if suchIn December 2013, UNS Electric filed an agreement is reached, definitive purchase and sale agreements would be executed prior to year-end 2013. TEP further anticipates any such purchase would close by year-end 2014 and would be subject to, among other things, the receipt of required regulatory approvals.
Purchased Power and Fuel Adjustment Clause
The 2013 TEP Rate Order approved a new PPFAC rate, effective July 1, 2013, which is a credit to retail customers of 0.14 cents per kWh. This PPFAC rate will be in effect until the rate is reset byapplication requesting the ACC in the second quarter of 2014.
TEP’s new PPFAC rate includes:
a one-time reduction in the PPFAC bank balance, recorded in June 2013 asto approve an increase to fuel expense, of $3 million related to prior Sulfur Credits; and
a transfer of $10 million, recorded in June 2013, from the PPFAC bank balance to a new regulatory assetaccounting order that would authorize UNS Electric to defer coalfor future recovery specific non-fuel operating costs related to the San Juan mine fire. These costs will be eligible for recovery through the PPFAC upon final insurance settlement.associated with its anticipated ownership of 25% of
At September 30, 2013, TEP had under-collected fuel and purchased power costs on a billed-to-customer basisGila River Unit 3. See UNS Electric, Factors Affecting Results of $11 million. TEP's previous PPFAC mechanism will continue with certain modifications, including the recovery of the following costs and/or credits: lime costs used to control SO2 emissions, net of Sulfur Credits received from TEP’s coal suppliers; broker fees; and all of the proceeds from the sale of SO2 allowances.
TEP estimates that from July 1 to December 31, 2013, approximately $5 million of net lime expense will be recorded in fuel and purchased energy expense and recovered through the PPFAC. Prior to July 1, 2013, lime costs were recorded in O&M expense.
Springerville Units 3 and 4
TEP receives annual benefits in the form of rental payments and other fees and cost savings from operating SpringervilleOperations, Gila River Generating Station Unit 3 on behalf of Tri-State and Unit 4 on behalf of SRP.
The table below summarizes the income statement line items in which TEP records revenues and expenses related to Springerville Units 3 and 4:
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | Millions of Dollars | | Millions of Dollars |
| Other Revenues | $ | 27 |
| | $ | 31 |
| | $ | 73 |
| | $ | 74 |
|
| Fuel Expense | (2 | ) | | (1 | ) | | (5 | ) | | (5 | ) |
| O&M Expense | (18 | ) | | (26 | ) | | (49 | ) | | (53 | ) |
| Taxes Other Than Income Taxes | — |
| | — |
| | (1 | ) | | (1 | ) |
| Total Pre-Tax Income | $ | 7 |
| | $ | 4 |
| | $ | 18 |
| | $ | 15 |
|
Pension and Retiree Benefit Expense
The table below summarizes TEP’s pension and other retiree benefit expenses charged to O&M in 2013 and2012. See Note 7.
Springerville Coal Handling Facilities Leases |
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | Millions of Dollars | | Millions of Dollars |
| Pension Expense Charged to O&M | $ | 3 |
| | $ | 3 |
| | $ | 8 |
| | $ | 8 |
|
| Retiree Benefit Expense Charged to O&M | 1 |
| | 1 |
| | 4 |
| | 3 |
|
| Total | $ | 4 |
| | $ | 4 |
| | $ | 12 |
| | $ | 11 |
|
Long-Term Wholesale Sales
TEP’s two primary long-term wholesale contracts are with SRPIn April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase their undivided ownership interests in the Navajo Tribal Utility Authority (NTUA).
Salt River Project
From January 1, 2012, throughfacilities at the endfixed purchase price of $120 million upon the expiration of the contractlease term in May 2016,April 2015. Due to TEP’s purchase commitment, TEP will record, in the second quarter of 2014, an increase to both Utility Plant Under Capital Leases and Capital Lease Obligations on its balance sheets in the amount of $109 million.
TEP previously agreed with Tri-State, the lessee of Springerville Unit 3, and SRP, the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities Leases were not renewed, TEP would exercise the purchase option under those contracts. Upon TEP’s purchase, SRP is requiredobligated to purchase 500,000 MWh of on-peak energy per year. TEP does not receivebuy a demand charge and the price of energy is based on a discount to the wholesale market price of on-peak power.
Navajo Tribal Utility Authority
TEP serves the portion of NTUA's load thatthe Springerville Coal Handling Facilities from TEP for approximately $24 million and Tri-State is not served from NTUA's allocation of federal hydroelectric power. Over the last three years, salesobligated to NTUA averaged 225,000 MWh. Prior to June 30, 2013, the power sold to NTUA was ateither 1) buy a fixed price. In May 2013, TEP amended its contract with NTUA and extended the contract from December 2015 to December 2022.
As a resultportion of the amendment, on July 1, 2013,facilities for approximately $24 million or 2) continue to make payments to TEP began receiving monthly capacity payments in exchange for providing 15 MW from July to September (June to September beginning in 2014 and thereafter) and 50 MW for the remainder of each year. Starting in 2016, the July to September capacity increases to 25 MW. Any energy sold above those amounts will be indexed to
the wholesale market price of natural gas. TEP estimates that sales to NTUA will be approximately 225,000 MWh in 2013 and 2014.
Long-Term Wholesale Margin and Sensitivity
TEP’s margin on long-term wholesale sales was $5 million during the first nine months of 2013 and $3 million during the same period last year.
The average price of on-peak power during the first nine months of 2013 was $37 per MWh. A change of $5 per MWh in the on-peak market price of power for the balanceuse of the year would change 2013 pre-tax income related to the SRP contract by approximately $1 million.
Electric Energy Efficiency Standards
In 2010, the ACC approved new Electric EE Standards designed to require TEP, UNS Electric, and other affected electric utilities to implement cost-effective programs to reduce customers' energy consumption. In 2013, the Electric EE Standards target total kWh savings of 5% of 2012 retail kWh sales; in 2014, the Electric EE Standards target total kWh savings of 7.25% of 2013 retail kWh sales. The Electric EE Standards increase annually thereafter up to a targeted cumulative annual reduction in retail kWh sales of 22% by 2020.
DSM programs approved by the ACC, direct load control programs, and energy efficient building codes are acceptable means to meet the Electric EE Standards as set forth by the ACC.
As part of the 2013 TEP Rate Order, the ACC approved a 2013 calendar year energy efficiency budget of $21 million, which includes a performance incentive of approximately $1 million. The performance incentive could be recognized in 2013 if TEP's DSM programs meet certain requirements. The Electric EE Standards provide for the recovery of costs incurred to implement DSM programs. TEP's programs, and the rates charged to customers for such programs, are subject to annual review and approval by the ACC. See2013 TEP Rate Order, above.
Renewable Energy Standard and Tariff
In October 2013, the ACC approved TEP's 2014 RES implementation plan. Under the plan, TEP expects to collect approximately $34 million from retail customers during 2014 to fund: the above market cost of renewable energy purchases; performance based incentives for customer installed distributed generation; a return on and of TEP's investments in company-owned solar projects; and various other program costs. The plan includes approval for a TEP investment of $28 million in 2014 for company-owned solar projects and an additional $12 million in 2015. In accordance with the funding mechanism approved by the ACC, TEP could earn approximately $1 million pre-tax in 2014 on company-owned solar investments. TEP expects to meet the 2013 renewable energy target of 4.0% of retail kWh sales and the 2014 target of 4.5%.
facilities.
Sales to Mining Customers
Copper prices have triggered an increase in mining activity at the copper mines operating in TEP's service area. TEP's mining customers have indicated they are taking initial steps to increase production either through expansion of their current mining operations or by the re-opening of non-operational mine sites. If efforts to increase production are successful, TEP's mining load could increase by up to 100 MW over the next several years. The market price for copper and the ability to obtain necessary permits could affect the mining industry's expansion plans.
In addition to the mining customers that TEP currently serves, Augusta Resources Corporation filed a plan of operations with the United States Forest Service in 2007 for the proposed Rosemont Copper Mine near Tucson, Arizona. The Rosemont Copper Mine requires electric service from TEP via a 138 kilo-volt (kV) transmission line for the construction and ongoing operation of the mine. The state line siting committee approved a Certificate of Environmental Compatibility (CEC) in 2011 for the 138 kV transmission line. In 2012, the ACC finalized the CEC. If the Rosemont Copper Mine is constructed and reaches full production, it would be expected to become TEP's largest retail customer, with TEP serving the mine's estimated load of approximately 85 MW.
TEP cannot predict if or when existing mines will expand operations or new or re-opened mines will commence operations.
Springerville Units 3 and 4
56TEP receives annual benefits in the form of rental payments and other fees and cost savings from operating Springerville Unit 3 on behalf of Tri-State and Unit 4 on behalf of SRP.
The table below summarizes the income statement line items in which TEP records revenues and expenses related to Springerville Units 3 and 4:
Table of Contents |
| | | | | | | |
| | Three Months Ended March 31, |
| | 2014 | | 2013 |
| | Millions of Dollars |
| Other Revenues | $ | 21 |
| | $ | 21 |
|
| Fuel Expense | (1 | ) | | (2 | ) |
| O&M Expense | (14 | ) | | (14 | ) |
Interest Rates
TEP is exposed to interest rate risk resulting from changes in interest rates on certain of its variable rate debt obligations, as well as borrowings under its revolving credit facility. As a result, TEP may be required to pay significantly higher rates of interest on outstanding variable rate debt and borrowings under the TEP Revolving Credit Facility. At September 30, 2013, TEP had $215 million in tax-exempt variable rate debt outstanding. The interest rates on TEP’s tax-exempt variable rate debt are reset weekly by its remarketing agents. The maximum interest payable under the indentures for the bonds is 10% on $37 million of bonds and 20% on the other $178 million. During the first nine months of 2013, the average rates paid ranged from 0.06% to 0.25%.
TEP has a fixed-for-floating interest rate swap to hedge $50 million of its tax-exempt variable rate debt.
TEP is also subject to interest rate risk resulting from changes in interest rates on its borrowings under the TEP Revolving Credit Facility. The interest paid on revolving credit borrowings is variable. If LIBOR and other benchmark interest rates increase, TEP may be required to pay higher rates of interest on borrowings under its revolving credit facility. See Item 3. Quantitative and Qualitative Disclosures about Market Risk below..
Fair Value Measurements
TEP’s income statement exposure to energy price risk is mitigated as TEP reports the change in fair value of energy contract derivatives as either a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement. See Note 11.
12.
LIQUIDITY AND CAPITAL RESOURCES
TEP Cash Flows
The tables below show TEP's net cash flows after capital expenditures, scheduled lease debt payments, and payments on capital lease obligations: |
| | | | | | | |
| | Three Months Ended March 31, |
| | 2014 | | 2013 |
| | Millions of Dollars |
| Net Cash Flows – Operating Activities (GAAP) | $ | 65 |
| | $ | 59 |
|
| Less: Capital Expenditures | (73 | ) | | (62 | ) |
Net Cash Flows after Capital Expenditures (Non-GAAP)(1) | (8 | ) | | (3 | ) |
| Less: Payments of Capital Lease Obligations | (80 | ) | | (81 | ) |
| Plus: Proceeds from Investment in Lease Debt | — |
| | 9 |
|
Net Cash Flows after Capital Expenditures and Required Payments on Lease Debt and Capital Lease Obligations (Non-GAAP)(1) | $ | (88 | ) | | $ | (75 | ) |
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2014 | | 2013 |
| | Millions of Dollars |
| Net Cash Flows – Operating Activities (GAAP) | $ | 65 |
| | $ | 59 |
|
| Net Cash Flows – Investing Activities (GAAP) | (70 | ) | | (55 | ) |
| Net Cash Flows – Financing Activities (GAAP) | 68 |
| | (62 | ) |
| Net Increase (Decrease) in Cash | 63 |
| | (58 | ) |
| Beginning Cash | 25 |
| | 80 |
|
| Ending Cash | $ | 88 |
| | $ | 22 |
|
|
| | | | | | | |
| | Nine Months Ended September 30, |
| | 2013 | | 2012 |
| | Millions of Dollars |
| Net Cash Flows – Operating Activities (GAAP) | $ | 254 |
| | $ | 207 |
|
| Amounts from Statements of Cash Flows: | | | |
| Less: Capital Expenditures | (180 | ) | | (196 | ) |
Net Cash Flows after Capital Expenditures (Non-GAAP)(1) | 74 |
| | 11 |
|
| Amounts From Statements of Cash Flows: | | | |
| Less: Payments for Capital Lease Obligations | (100 | ) | | (89 | ) |
| Plus: Proceeds from Investment in Lease Debt | 9 |
| | 19 |
|
Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations (Non-GAAP)(1) | $ | (17 | ) | | $ | (59 | ) |
|
| | | | | | | |
| | Nine Months Ended September 30, |
| | 2013 | | 2012 |
| | Millions of Dollars |
| Net Cash Flows – Operating Activities (GAAP) | $ | 254 |
| | $ | 207 |
|
| Net Cash Flows – Investing Activities (GAAP) | (180 | ) | | (173 | ) |
| Net Cash Flows – Financing Activities (GAAP) | (119 | ) | | 41 |
|
| Net Increase (Decrease) in Cash | (45 | ) | | 75 |
|
| Beginning Cash | 80 |
| | 28 |
|
| Ending Cash | $ | 35 |
| | $ | 103 |
|
| | | | |
Net Cash Flows after Capital Expenditures (Non-GAAP)(1) | $ | 74 |
| | $ | 11 |
|
Net Cash Flows after Capital Expenditures and Required Payments on Capital Lease Obligations (Non-GAAP)(1) | (17 | ) | | (59 | ) |
| |
(1) | Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on Lease Debt and Capital Lease Obligations, both non-GAAP measures of liquidity, should not be considered as alternatives to Net Cash Flows—Operating Activities, which is determined in accordance with GAAP. We believe that Net Cash Flows after Capital Expenditures and Net Cash Flows after Capital Expenditures and Required Payments on Lease Debt and Capital Lease Obligations provide useful information to investors as measures of TEP’s ability to fund capital requirements, make required payments on lease debt and capital lease obligations, and pay dividends to UNS Energy before consideration of financing activities. |
Liquidity Outlook
During 2013, TEP expects to generate sufficient operating cash flows to fund the majority of its capital expenditures. Cash flows may vary during the year, with cash flow from operations typically the lowest in the first quarter and highest in the third quarter due to TEP’s summer peaking load. As a result of the varied seasonal cash flow, TEP will use, as needed, its revolving credit facility to assist in funding its business activities.
If the Merger Agreement is approved by all necessary parties, Fortis will contribute $200 million of equity capital to UNS Energy upon closing. If the contribution is made by December 2014, UNS Energy may then contribute this capital to TEP and UNS Electric to help fund the Gila River Unit 3 and Springerville Unit 1 purchase commitments.
Operating Activities
In the first ninethree months of 20132014, net cash flows from operating activities were $476 million higher than in the first nine months of 2012.same period last year. The increase was due primarily to: higher cash receipts from retail sales related to a base rateBase Rate increase at TEP that becamewas effective on July 1, 2013, as well as2013; and lower interest paid on capital leases; partially offset by an increase in sales volumes and an increase in TEP's PPFAC rate that became effective in April 2012; and a decrease in capital lease interestO&M paid due to a decline in capital lease obligation balances.planned maintenance outages and merger-related costs.
Investing Activities
Net cash flows used for investing activities increased by $7$15 million in the first ninethree months of 20132014 compared with the same period last year due primarily to: lower proceeds from the investment in lease debt; andto an $11 million increase in purchases of RECs due to an increase in renewable energy PPAs; partially offset by lower capital expenditures.
TEP’s capital expenditures were related primarily to scheduled outage work performed on our generating facilities.$180 million in the first nine months
Financing Activities
In the first ninethree months of 20132014, net cash from financing activities was $160130 million lowerhigher than in the same period in 2012. Financing activities in the first nine months of 2013 included a $20 million dividend paymentlast year due to UNS Energy and an $11 million increase in payments made on capital lease obligations. Financing activities in the first nine months of 2012 included:proceeds from the issuance of $150 million of long-term debt; $7 million of repayments of long-term debt; anddebt offset by $1020 million ofmore in repayments (net of borrowings) under the TEP Revolving Credit Facility.
TEP Mortgage Indenture
2014 Bond Issuances
PriorIn March 2014, TEP issued $150 million of unsecured notes. The bonds bear interest at a fixed rate of 5.0%, mature in March 2044, and may be redeemed at par on or after September 15, 2043. The proceeds of the bond issuance were used to November 2013,repay approximately $90 million outstanding under TEP's revolving credit facility, with the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement were secured by $423 million in Mortgage Bonds issued under the 1992 Mortgage. As a result of TEP's credit rating upgrade, in October 2013, TEP (i) requested $423 million in Mortgage Bondsremaining proceeds to be returnedapplied to TEP for cancellation, and (ii) discharged the 1992 Mortgage, which had created a lien on and security interest in substantially all of TEP’s utility plant assets. TEP’s obligations under the TEP Credit Agreement and the 2010 TEP Reimbursement Agreement are now unsecured.general corporate purposes. See Note 5.
TEP Credit Agreement
The TEP Credit Agreement consists of a $200 million revolving credit, and revolving letter of creditLOC facility and a $186an $82 million letter of creditLOC facility to support tax-exempt bonds. The TEP Credit Agreement expires in November 2016.
TEP expects to provide, in the second quarter of 2014, an LOC for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. TEP's borrowing capacity under the TEP Credit Agreement would be reduced by $15 million until the Gila River transaction closes and the LOC is terminated.
At September 30, 2013March 31, 2014, there were no outstanding borrowings and there were $1 million of LOCs issued under the TEP Revolving Credit Facility.
The TEP Credit Agreement contains restrictions on liens, mergers and sale of assets. The TEP Credit Agreement also requires TEP not to exceed a maximum leverage ratio. If TEP complies with the terms of the TEP Credit Agreement, TEP may pay dividends to UNS Energy. At September 30, 2013March 31, 2014, TEP was in compliance with the terms of the TEP Credit Agreement. See Note 5.
2010 TEP Reimbursement Agreement
In December 2010, TEP entered into a four-year $37 million reimbursement agreement (2010 TEP Reimbursement Agreement). A $37 million LOC was issued pursuant to the 2010 TEP Reimbursement Agreement. The LOC supports $37
million aggregate principal amount of variable rate tax-exempt pollution control bonds that were issued on behalf of TEP in December 2010.
In February 2014, TEP amended the 2010 TEP Reimbursement Agreement to extend the expiration date of the LOC from 2014 to 2019.
The 2010 TEP Reimbursement Agreement contains substantially the same restrictive covenants as the TEP Credit Agreement described above. At September 30, 2013March 31, 2014, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement. See Note 5.
2013 Bond Issuances and Redemptions
In March 2013, approximately $91 million of unsecured tax-exempt industrial development bonds were issued on behalf of TEP. The bonds bear interest at a fixed rate of 4.0%, mature in September 2029 and may be redeemed at par on or after March 1, 2023. In April 2013, the proceeds of the bond issuance were used to redeem approximately $91 million of unsecured tax-exempt bonds with an interest rate of 6.375% and a maturity date of September 2029. See Note 5.
Capital Lease Obligations
At September 30, 2013March 31, 2014, TEP had $299237 million of total capital lease obligations on its balance sheet. The table below provides a summary of the outstanding lease obligations:
| | | | Capital Lease Obligation Balance As Of | | Capital Lease Obligation Balance As Of | |
| Capital Leases | September 30, 2013 | | Expiration | | Renewal/Purchase Option | March 31, 2014 | | Expiration | | Renewal/Purchase Option |
| | Millions of Dollars | | | | | Millions of Dollars | | | | |
Springerville Unit 1(1) | $ | 176 |
| | 2015 | | Fair market value purchase option of $478 per kW(2) | $ | 128 |
| | 2015 | | Fair market value |
| Springerville Coal Handling Facilities | 28 |
| | 2015 | | Fixed price purchase option of $120 million(3) | 22 |
| | 2015 | | Fixed price purchase option of $120 million(2) |
Springerville Common Facilities(4)(3) | 95 |
| | 2017 and 2021 | | Fixed price purchase option of $106 million(3) | 87 |
| | 2017 and 2021 | | Fixed price purchase option of $106 million(3) |
| Total Capital Lease Obligations | $ | 299 |
| | $ | 237 |
| |
| |
(1) | The Springerville Unit 1 Leases cover both Unit 1 and an undivided one-half interest in certain Springerville Common Facilities. The $128 million balance includes the present value of the lease purchase options agreed to in 2013. |
| |
(2) | As determinedThe $22 million balance does not include the $109 million present value of the lease purchase options elected in December 2011 in an appraisal procedure undertaken pursuantApril 2014. Upon TEP’s purchase, SRP is obligated to buy a portion of the Springerville Unit 1 lease agreements. See Part II, Item 1.—Legal Proceedings.Coal Handling Facilities from TEP electedfor approximately $24 million and agreedTri-State is obligated to purchase certain interests ineither 1) buy a portion of the Springerville Unit 1 lease agreements in August and October 2013. facilities for approximately $24 million or 2) continue to make payments to TEP for the use of the facilities.See Factors Affecting Results of Operations, Coal-Fired Generating Resources, Springerville Unit 1, Coal Handling Facilities Leasesabove.. Also see Note 5.
|
| |
(3) | TEP agreed with Tri-State, the lessee of Springerville Unit 3 and SRP, the owner of Springerville Unit 4, that if the Springerville Coal Handling Facilities and Common Leases are not renewed, TEP will exercise the purchase options under these contracts. SRP will then be obligated to buy a portion of these facilities and Tri State will then be obligated to either 1) buy a portion of these facilities; or 2) continue making payments to TEP for the use of these facilities. |
| |
(4)
| The Springerville Common Facilities Leases cover an undivided one-half interest in certain Springerville Common Facilities. |
TEP's capital lease obligation balances decline over time due to the normal capital lease payments made by TEP.
Income Tax Position
See UNS Energy Consolidated, Liquidity and Capital Resources, Income Tax Position above..
Contractual Obligations
There have been no changes in TEP’sTEP's contractual obligations or other commercial commitments from those reported in our 20122013 Annual Report on Form 10-K, other than the following changes in 2013:2014:
In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. See Note 5.
In April 2014, TEP entered into new forward purchase power commitmentsnotified the owner participants and their lessors that will settle through 2015. Some of these contracts are at fixed prices per MWh and others are indexed to natural gas prices. Based on projected market prices as of September 30, 2013, TEP's estimated minimum payment obligations for these additional purchases are $14 million in 2014 and $2 million in 2015. See Note 4.
TEP has a 20-year PPA with a renewable energy generation facility that achieved commercial operation in June 2013. TEP is obligated to purchase 100% of the output from this facility. TEP expects to make minimum payment obligations under this contract of approximately $2 million in 2013, $4 million per year from 2014 through 2017, and approximately $58 million total thereafter. See Note 4.
TEP is contractually obligated to certain retail customers with solar installations to make RES PBI payments for environmental attributes, or RECs. In 2013, TEP's total obligation for RES PBIs increased by $12 million from $62 million on December 31, 2012 to $74 million on September 30, 2013. TEP will make required payments over periods ranging from 9 to 20 years based on metered renewable energy production. PBIs are recoverable through the RES tariff. See Note 4.
In August 2013, TEP elected to purchase leasedits undivided ownership interests comprising 24.8% ofin the Springerville Unit 1, representing 96 MW of continuous operating capability, for an aggregateCoal Handling Facilities at the fixed purchase price of $46$120 million, the appraised value, upon the expiration of the lease term in JanuaryApril 2015. In October 2013,Upon TEP's purchase, SRP is obligated to buy a portion of the Springerville Coal Handling Facilities from TEP agreedfor approximately $24 million, and Tri-State is obligated to purchase an additional 10.6% leased interest in Springerville Unit 1, representing 41 MWeither 1) buy a portion of continuous operating capability,the facilities for $20$24 million, or 2) continue to make payments to TEP for the appraised value, withuse of the purchase scheduled to occur in December 2014.facilities. See Note 5.
5.TEP entered into new gas transportation agreements that will settle through 2018, resulting in an additional commitmentforward purchased power commitments with minimum payment obligations of $4$7 million in 2015. See Note 6.
See UNS Energy Consolidated, Liquidity and Capital Resources, Contractual Obligations, for a description of these obligations.
We have reviewed our contractual obligations and provide the following additional information:
The TEP Credit Agreement, the 2010 Reimbursement Agreement, and the 2013 $5 million per year fromCovenants Agreement contain pricing based on TEP’s credit ratings. A change in TEP’s credit ratings can cause an increase or decrease in the amount of interest TEP pays on its borrowings, and the amount of fees it pays for its LOCs and unused commitments. A downgrade in TEP’s credit ratings would not cause a restriction in TEP’s ability to borrow under its revolving credit facility.
The TEP Credit Agreement, the 2010 Reimbursement Agreement, and the 2013 Covenants Agreement contain certain financial and other restrictive covenants, including a leverage test. Failure to comply with these covenants would entitle the lenders to accelerate the maturity of all amounts outstanding. At March 31, 2014, through 2017TEP was in compliance with these covenants. See TEP Credit Agreement, above.
TEP conducts its wholesale marketing and risk management activities under certain master agreements whereby TEP may be required to post credit enhancements in the form of cash or an LOC due to exposures exceeding unsecured credit limits provided to TEP, changes in contract values, a change in TEP’s credit ratings, or if there has been a material change in TEP’s creditworthiness. As of March 31, 2014, TEP had posted less than $1 million in 2018. See Note 4.
In March 2013, $91 million of unsecured tax-exempt industrial development bonds were issued on behalf of TEP. The bonds bear interest at a rate of 4.0% and are due in September 2029. Proceeds were used to redeem $91 million of 2008 Pima Bonds bearing interest at a rate of 6.375%LOCs as collateral with the same maturity date. As a result, TEP's interest obligations decreased by about $2 million per year. See Note 5.
In the first quarter of 2013, TEP reduced unrecognized tax benefits by $22 million based on a favorable ruling from the IRS allowing us to deduct, rather than defer and amortize, up-front incentive payments to customers who install renewable energy resources. See Note 6.
counterparties for credit enhancement.
Dividends on Common Stock
TEP paid $20 million indid not pay any dividends to UNS Energy in the first nine monthsquarters of 20132014 compared with no dividends paid to UNS Energy during the same period inor 20122013.
TEP can pay dividends to UNS Energy if it maintains compliance with the TEP Credit Agreement, and the 2010 TEP Reimbursement Agreement and the 2013 Covenants Agreement. At September 30, 2013March 31, 2014, TEP was in compliance with the terms of the TEP Credit Agreement, and the 2010 TEP Reimbursement Agreement and the 2013 Covenants Agreement.
UNS ELECTRIC
RESULTS OF OPERATIONS
UNS Electric reported net income of $2 million in both the first quarter of 2014 and first quarter of 2013.
Like TEP, UNS Electric’s operations are typically seasonal in nature, with peak energy demand occurring in the summer months. The Federaltable below provides summary financial information for UNS Electric: |
| | | | | | | |
| | Three Months Ended March 31, |
| | 2014 | | 2013 |
| | Millions of Dollars |
| Retail Electric Revenues | $ | 39 |
| | $ | 36 |
|
| Wholesale Electric Revenues | 2 |
| | 1 |
|
| Total Operating Revenues | 41 |
| | 37 |
|
| Purchased Energy Expense | 18 |
| | 17 |
|
| Fuel Expense | — |
| | 1 |
|
| Transmission Expense | 3 |
| | 3 |
|
| Increase (Decrease) to Reflect PPFAC Recovery | 1 |
| | (2 | ) |
| O&M | 7 |
| | 7 |
|
| Depreciation and Amortization Expense | 5 |
| | 5 |
|
| Taxes Other Than Income Taxes | 2 |
| | 1 |
|
| Total Operating Expenses | 36 |
| | 32 |
|
| Operating Income | 5 |
| | 5 |
|
| Interest Expense | 2 |
| | 1 |
|
| Income Tax Expense | 1 |
| | 2 |
|
| Net Income | $ | 2 |
| | $ | 2 |
|
The table below shows UNS Electric’s kWh sales and margin revenues: |
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | | | |
| | 2014 | | 2013 | | Amount | | Percent(1) |
| Electric Retail Sales, kWh (in Millions): | | | | | | | |
| Residential | 159 |
| | 190 |
| | (31 | ) | | (16.3 | )% |
| Commercial | 131 |
| | 128 |
| | 3 |
| | 2.3 | % |
| Industrial | 44 |
| | 42 |
| | 2 |
| | 4.8 | % |
| Mining | 14 |
| | 13 |
| | 1 |
| | 7.7 | % |
| Other | 1 |
| | 1 |
| | — |
| | — | % |
| Total Electric Retail Sales | 349 |
| | 374 |
| | (25 | ) | | (6.7 | )% |
| | | | |
| Retail Margin Revenues (in Millions): | | | |
| Residential | $ | 7 |
| | $ | 7 |
| | $ | — |
| | — | % |
| Commercial | 6 |
| | 6 |
| | — |
| | — | % |
| Industrial | 2 |
| | 2 |
| | — |
| | — | % |
| Mining | 1 |
| | 2 |
| | (1 | ) | | (50.0 | )% |
| Other | — |
| | — |
| | — |
| | — | % |
Total Retail Margin Revenues (Non-GAAP)(2) | 16 |
| | 17 |
| | (1 | ) | | (5.9 | )% |
| Fuel and Purchased Power Revenues | 20 |
| | 17 |
| | 3 |
| | 17.6 | % |
| RES, DSM, & LFCR Revenues | 3 |
| | 2 |
| | 1 |
| | 50.0 | % |
| Total Retail Revenues (GAAP) | $ | 39 |
| | $ | 36 |
| | $ | 3 |
| | 8.3 | % |
| Weather Data: | | | | | | | |
| Heating Degree Days | | | | | | | |
| Three Months Ended March 31, | 748 |
| | 1,160 |
| | (412 | ) | | (35.5 | )% |
| 10-Year Average | 1,088 |
| | 1,102 |
| | NM |
| | NM |
|
| |
(1) | Percent change calculated on un-rounded data and may not correspond exactly to data shown in table. |
| |
(2) | Total Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Total Retail Margin Revenues exclude revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Total Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Total Retail Margin Revenues represents the portion of retail operating revenues available to cover the non-fuel operating expenses of our core utility business. |
In the first quarter of 2014, total retail kWh sales decreased by 6.7% compared with the first quarter of 2013 due primarily to a 36% decrease in heating-degree days. Despite lower retail kWh sales, retail margin revenues decreased by just $1 million, or 5.9%, due to a Base Rate increase that was effective on January 1, 2014. UNS Electric recorded LFCR revenues of $1 million in the first quarter of 2014, a portion of which relates to reductions in 2013 retail kWh sales due to energy efficiency programs and distributed generation.
FACTORS AFFECTING RESULTS OF OPERATIONS
2013 UNS Electric Rate Order
In December 2013, the ACC approved a new rate structure for UNS Electric that became effective on January 1, 2014 (2013 UNS Electric Rate Order). The provisions of the 2013 UNS Electric Rate Order include, but are not limited to:
an increase in Base Rates of approximately $3 million;
an LFCR mechanism that will allow UNS Electric to recover certain non-fuel costs that would otherwise go unrecovered due to reduced retail kWh sales attributed to compliance with the ACC's Electric EE Standards and distributed generation requirements under the ACC's RES. The LFCR rate will be adjusted annually and is subject to ACC review and a year-over-year cap of 1% of UNS Electric's total retail revenues. The LFCR is not a full
decoupling mechanism because it is not intended to recover lost fixed costs attributable to weather or economic conditions. UNS Electric expects to file its first LFCR report with the ACC on or before May 15, 2014. We expect the new LFCR rate to become effective on July 1, 2014. UNS Electric recorded LFCR revenues of $1 million in the first quarter of 2014 related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013. See Note 3. UNS Electric estimates that it will record total LFCR revenues of approximately $2 million during 2014; and
a Transmission Cost Adjustment Mechanism (TCA) that will allow more timely recovery of transmission costs associated with serving retail customers at the level approved by FERC. UNS Electric's approved Base Rates include a transmission component based on UNS Electric’s current FERC Open Access Transmission Tariff (OATT) rate. The OATT rates are adjusted annually and the TCA will be limited to the recovery (or refund) of costs associated with future changes in UNS Electric’s OATT rate. UNS Electric expects to make an informational TCA filing with the ACC on or before May 1, 2014. The filing will include an updated retail transmission rate calculated pursuant to UNS Electric's OATT rate. UNS Electric expects the new TCA rate to be effective in June 2014.
Gila River Generating Station Unit 3
In December 2013, TEP and UNS Electric entered into an agreement to purchase Gila River Unit 3 for $219 million. It is anticipated that TEP will purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million and UNS Electric will purchase the remaining 25% undivided interest (137 MW) for approximately $55 million, although TEP and UNS Electric may modify the percentage ownership allocation between them. We expect the transaction to close in December 2014. See Tucson Electric Power, Act statesFactors Affecting Results of Operations, Gila River Generating Station Unit 3 and Note 7.
Also in December 2013, UNS Electric filed an application requesting the ACC to approve an accounting order that would authorize UNS Electric to defer for future recovery specific non-fuel operating costs associated with Gila River Unit 3. If UNS Electric purchases 25% of Gila River Unit 3, the deferred costs, including depreciation, amortization, property taxes, O&M expense and a carrying cost on UNS Electric's investment in Gila River Unit 3, are expected to total approximately $9 million annually. We cannot predict if the ACC will approve UNS Electric's request.
Fair Value Measurements
See Note 12.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity Outlook
UNS Electric expects operating cash flows to fund a portion of its construction expenditures during 2014. Additional sources of funding capital expenditures could include draws on the UNS Electric/UNS Gas Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UNS Energy.
Cash Flows and Capital Expenditures
The table below provides summary cash flow information for UNS Electric: |
| | | | | | | |
| | Three Months Ended March 31, |
| | 2014 | | 2013 |
| | Millions of Dollars |
| Cash Provided By (Used In): | | | |
| Operating Activities | $ | 10 |
| | $ | 8 |
|
| Investing Activities | (12 | ) | | (16 | ) |
| Financing Activities | 3 |
| | 7 |
|
| Net Increase/(Decrease) in Cash | 1 |
| | (1 | ) |
| Beginning Cash | 5 |
| | 8 |
|
| Ending Cash | $ | 6 |
| | $ | 7 |
|
Operating Activities
Cash provided by operating activities increased by $2 million in the first three months of 2014 when compared with the same period last year due primarily to a Base Rate increase that was effective on January 1, 2014.
Investing Activities
UNS Electric had capital expenditures of $12 million in the first quarter of 2014 compared with $15 million in the first quarter of 2013. The decrease is related to the completion of construction of a transmission line in 2013 to increase reliability to UNS Electric's service territory in Nogales, Arizona.
Financing Activities
Cash provided by financing activities at UNS Electric in the first three months of 2014 decreased by $4 million when compared with the same period last year. Financing activities in the first three months of 2014 included $3 million of borrowings under the UNS Electric/UNS Gas Revolver (net of repayments) whereas activity in the same period last year included $5 million of borrowings under the UNS Electric/UNS Gas Revolver (net of repayments) and a $2 million receipt related to a contribution in aid of construction from a large customer.
UNS Electric/UNS Gas Credit Agreement
The UNS Electric/UNS Gas Credit Agreement consists of a $100 million unsecured revolving credit and revolving LOC facility. Either company can borrow up to a maximum of $70 million as long as the combined amount borrowed does not exceed $100 million. The UNS Electric/UNS Gas Credit Agreement expires November 2016.
UNS Electric is only liable for UNS Electric’s borrowings, and similarly, UNS Gas is only liable for UNS Gas' borrowings under the UNS Electric/UNS Gas Credit Agreement.
The UNS Electric/UNS Gas Credit Agreement restricts additional indebtedness, liens, and mergers. It also requires each borrower not to exceed a maximum leverage ratio. Each borrower may pay dividends shall not be paid out of funds properly includedso long as it maintains compliance with the agreement. At March 31, 2014, UNS Electric and UNS Gas each were in capital accounts. Althoughcompliance with the terms of the Federal Power ActUNS Electric/UNS Gas Credit Agreement.
UNS Electric expects to draw upon the UNS Electric/UNS Gas Revolver from time to time for seasonal working capital purposes, to fund a portion of its capital expenditures or to issue LOCs to provide credit enhancement for its energy procurement and hedging activities. At March 31, 2014, UNS Electric had $25 million of outstanding borrowings and less than $1 million of LOCs issued under the UNS Electric/UNS Gas Credit Agreement.
Contractual Obligations
There are unclear, we believe that there is a reasonable basis for TEPno changes in UNS Electric's contractual obligations or other commercial commitments from those reported in our 2013 Annual Report on Form 10-K, other than the following changes in 2014:
UNS Electric entered into new forward purchased power commitments with minimum payment obligations of $8 million in 2015. See Note 6.
Dividends on Common Stock
UNS Electric did not pay any dividends to UNS Energy, through UES, in first quarters of 2014 and 2013. UNS Electric’s ability to pay future dividends from current year earnings.will depend on the cash needs for capital expenditures and various other factors.
60The note purchase agreement for UNS Electric contains restrictions on dividends. UNS Electric may pay dividends so long as 1) no default or event of default exists, and 2) it could incur additional debt under the debt incurrence test. At March 31, 2014, UNS Electric was in compliance with the terms of its note purchase agreement and the terms of the UNS Electric/UNS Gas Revolver.
UNS GAS
RESULTS OF OPERATIONS
UNS Gas reported a net lossincome of $5 million in the first quarter of $12014 compared with $8 million in the thirdfirst quarter of 2013 compared with no net income or net loss in the third quarter of 2012. In the first nine months of 2013, UNS Gas reported net income of $6 million compared with net income of $5 million in the same period last year. The increase in net income for the nine months ended September 30, 2013 is due primarily to: coldMild weather induring the first quarter which contributed to a 9.6% increase in retail therm sales in the first nine months of 20132014 relativeled to 2012;lower retail sales volumes and a non-fuel base rate increase that was effective in May 2012.retail margin revenues.
The table below provides summary financial information for UNS Gas:
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | Millions of Dollars | | Millions of Dollars |
| Gas Revenues | $ | 18 |
| | $ | 18 |
| | $ | 91 |
| | $ | 90 |
|
| Other Revenues | — |
| | — |
| | 2 |
| | 3 |
|
| Total Operating Revenues | 18 |
| | 18 |
| | 93 |
| | 93 |
|
| Purchased Gas Expense | 5 |
| | 8 |
| | 48 |
| | 49 |
|
| Increase (Decrease) to Reflect PGA Recovery Treatment | 3 |
| | — |
| | 1 |
| | 3 |
|
| O&M | 7 |
| | 6 |
| | 19 |
| | 19 |
|
| Depreciation and Amortization | 2 |
| | 2 |
| | 7 |
| | 6 |
|
| Taxes Other Than Income Taxes | 1 |
| | 1 |
| | 3 |
| | 3 |
|
| Total Other Operating Expenses | 18 |
| | 17 |
| | 78 |
| | 80 |
|
| Operating Income | — |
| | 1 |
| | 15 |
| | 13 |
|
| Interest Expense | 2 |
| | 2 |
| | 5 |
| | 5 |
|
| Income Tax Expense | (1 | ) | | (1 | ) | | 4 |
| | 3 |
|
| Net Income | $ | (1 | ) | | $ | — |
| | $ | 6 |
| | $ | 5 |
|
The table below includes UNS Gas’ therm sales and margin revenues for the third quarters of 2013 and 2012:
|
| | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Increase (Decrease) |
| | 2013 | | 2012 | | Amount | | Percent(1) |
| Gas Retail Sales, Therms (in Millions): | | | | | | | |
| Residential | 6 |
| | 5 |
| | 1 |
| | 7.7 | % |
| Commercial | 4 |
| | 4 |
| | — |
| | 5.6 | % |
| All Other | — |
| | — |
| | — |
| | 13.2 | % |
| Total Gas Retail Sales | 10 |
| | 9 |
| | 1 |
| | 7.2 | % |
| Negotiated Sales Program (NSP) | 8 |
| | 11 |
| | (3 | ) | | (26.6 | )% |
| Total Gas Sales | 18 |
| | 20 |
| | (2 | ) | | (10.6 | )% |
| Retail Margin Revenues (in Millions): | | | |
| Residential | $ | 6 |
| | $ | 6 |
| | $ | — |
| | 3.4 | % |
| Commercial | 2 |
| | 2 |
| | — |
| | — | % |
| All Other | — |
| | — |
| | — |
| | — | % |
Total Retail Margin Revenues (Non-GAAP)(2) | 8 |
| | 8 |
| | — |
| | 2.6 | % |
| Transport and NSP | 5 |
| | 5 |
| | — |
| | (8.5 | )% |
| Retail Fuel Revenues | 5 |
| | 5 |
| | — |
| | 4.0 | % |
| Total Gas Revenues (GAAP) | $ | 18 |
| | $ | 18 |
| | $ | — |
| | (1.1 | )% |
| Weather Data: | | | | | | | |
| Heating Degree Days | | | | | | | |
| Three Months Ended September 30, | 101 |
| | 54 |
| | 47 |
| | 87.0 | % |
| 10-Year Average | 72 |
| | 74 |
| | NM |
| | NM |
|
|
| | | | | | | |
| | Three Months Ended March 31, |
| | 2014 | | 2013 |
| | Millions of Dollars |
| Gas Revenues | $ | 39 |
| | $ | 51 |
|
| Other Revenues | 2 |
| | 1 |
|
| Total Operating Revenues | 41 |
| | 52 |
|
| Purchased Gas Expense | 30 |
| | 30 |
|
| Increase (Decrease) to Reflect PGA Recovery Treatment | (8 | ) | | (1 | ) |
| O&M | 6 |
| | 6 |
|
| Depreciation and Amortization | 2 |
| | 2 |
|
| Taxes Other Than Income Taxes | 1 |
| | 1 |
|
| Total Operating Expenses | 31 |
| | 38 |
|
| Operating Income | 10 |
| | 14 |
|
| Interest Expense | 2 |
| | 2 |
|
| Income Tax Expense | 3 |
| | 4 |
|
| Net Income | $ | 5 |
| | $ | 8 |
|
The table below includes UNS Gas' therm sales and margin revenues: |
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, | | Increase (Decrease) |
| | 2014 | | 2013 | | Amount | | Percent(1) |
| Gas Retail Sales, Therms (in Millions): | | | | | | | |
| Residential | 27 |
| | 35 |
| | (8 | ) | | (22.9 | )% |
| Commercial | 10 |
| | 11 |
| | (1 | ) | | (9.1 | )% |
| All Other | 3 |
| | 4 |
| | (1 | ) | | (25.0 | )% |
| Total Gas Retail Sales | 40 |
| | 50 |
| | (10 | ) | | (20.0 | )% |
| Negotiated Sales Program (NSP) | 5 |
| | 7 |
| | (2 | ) | | (28.6 | )% |
| Total Gas Sales | 45 |
| | 57 |
| | (12 | ) | | (21.1 | )% |
| Retail Margin Revenues (in Millions): | | | | | | | |
| Residential | $ | 13 |
| | $ | 16 |
| | $ | (3 | ) | | (18.8 | )% |
| Commercial | 3 |
| | 4 |
| | (1 | ) | | (25.0 | )% |
| All Other | 1 |
| | 1 |
| | — |
| | — | % |
Total Retail Margin Revenues (Non-GAAP)(2) | 17 |
| | 21 |
| | (4 | ) | | (19.0 | )% |
| Transport and NSP | 4 |
| | 4 |
| | — |
| | — | % |
| Retail Fuel Revenues | 18 |
| | 26 |
| | (8 | ) | | (30.8 | )% |
| Total Gas Revenues (GAAP) | $ | 39 |
| | $ | 51 |
| | $ | (12 | ) | | (23.5 | )% |
| Weather Data: | | | | | | | |
| Heating Degree Days | | | | | | | |
| Three Months Ended March 31, | 1,722 |
| | 2,188 |
| | (466 | ) | | (21.3 | )% |
| 10-Year Average | 2,110 |
| | 2,096 |
| | NM |
| | NM |
|
| |
(1) | Percent change calculated on un-rounded data and may not correspond exactly to data shown in table. |
| |
(2) | Total Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Gas Revenues, which is determined in accordance with GAAP. Total Retail Margin Revenues excludes revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Total Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Total Retail Margin Revenues represents the portion of retail operating revenues available to cover the non-fuel operating expenses of our core utility business. |
Retail therm sales duringin the first quarter of third2014 decreased by 20.0% when compared with the first quarter of 2013 increased by 7.2%due in part to a 87.0%21.3% increasedecrease in Heating Degree Days. The increasedecrease in retail therm sales as well as a Base Rate increase implemented in May 2012, contributed to an increasea decrease in retail margin revenues of 2.6%, or less than $1 million, when compared with the third quarter of 2012.
UNS Gas supplies natural gas to some of its large transportation customers through an NSP. Approximately one half of the margin earned on these NSP sales is retained by UNS Gas, while the remainder benefits retail customers by reducing the gas commodity price through a credit to the PGA mechanism.
The table below includes UNS Gas’ therm sales and margin revenues for the first nine months of 2013 and 2012:
|
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, | | Increase (Decrease) |
| | 2013 | | 2012 | | Amount | | Percent(1) |
| Gas Retail Sales, Therms (in Millions): | | | | | | | |
| Residential | 49 |
| | 44 |
| | 5 |
| | 10.6 | % |
| Commercial | 21 |
| | 20 |
| | 1 |
| | 6.5 | % |
| All Other | 6 |
| | 5 |
| | 1 |
| | 12.4 | % |
| Total Gas Retail Sales | 76 |
| | 69 |
| | 7 |
| | 9.6 | % |
| Negotiated Sales Program (NSP) | 21 |
| | 26 |
| | (5 | ) | | (17.2 | )% |
| Total Gas Sales | 97 |
| | 95 |
| | 2 |
| | 2.3 | % |
| Retail Margin Revenues (in Millions): | | | | | | | |
| Residential | $ | 29 |
| | $ | 27 |
| | $ | 2 |
| | 8.6 | % |
| Commercial | 8 |
| | 7 |
| | 1 |
| | 8.1 | % |
| All Other | 2 |
| | 1 |
| | 1 |
| | 14.3 | % |
Total Retail Margin Revenues (Non-GAAP)(2) | 39 |
| | 35 |
| | 4 |
| | 8.8 | % |
| DSM Revenue | — |
| | 1 |
| | (1 | ) | | (14.3 | )% |
| Transport and NSP | 13 |
| | 12 |
| | 1 |
| | 7.4 | % |
| Retail Fuel Revenues | 39 |
| | 42 |
| | (3 | ) | | (6.5 | )% |
| Total Gas Revenues (GAAP) | $ | 91 |
| | $ | 90 |
| | $ | 1 |
| | 1.3 | % |
| Weather Data: | | | | | | | |
| Heating Degree Days | | | | | | | |
| Nine Months Ended September 30, | 2,769 |
| | 2,504 |
| | 265 |
| | 10.6 | % |
| 10-Year Average | 2,715 |
| | 2,728 |
| | NM |
| | NM |
|
| |
(1)
| Percent change calculated on un-rounded data and may not correspond exactly to data shown in table. |
| |
(2)
| Total Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Gas Revenues, which is determined in accordance with GAAP. Total Retail Margin Revenues excludes revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Total Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Total Retail Margin Revenues represents the portion of retail operating revenues available to cover the non-fuel operating expenses of our core utility business. |
Retail therm sales during the first nine months of 2013 increased by 9.6% due in part to a 10.6% increase in Heating Degree Days. The increase in retail therm sales, as well as a Base Rate increase implemented in May 2012, contributed to an increase in retail margin revenues of 8.8%19.0%, or $4 million, when compared with the same period infirst quarter of 20122013.
FACTORS AFFECTING RESULTS OF OPERATIONS
Competition
New technological developments and the implementation of the ACC’s Gas Energy Efficiency Standards (Gas EE Standards) may reduce energy consumption by UNS Gas’ retail customers. Customers of UNS Gas also have the ability to switch from gas to an alternate energy source that could reduce their reliance on services provided by UNS Gas.
Rates
2012 UNS Gas Rate Order
In April 2012, the ACC approved a Base Rate increase of $2.7 million as well as an LFCR mechanism to enable UNS Gas to recover lost fixed-cost revenues as a result of implementing the Gas EE Standards. The LFCR is expected to recover lost fixed-cost revenues of less than $0.1 million in 2014, based on estimated lost retail therm sales from May 2012 through December 2013.
The new rates became effective on May 1, 2012. The impact of the Base Rate increase on customers’ bills was offset by a temporary credit adjustment to the PGA. See Purchased Gas Adjustor, below, for more information.
Purchased Gas Adjustor
The PGA mechanism is intended to address the volatility of natural gas prices and allow UNS Gas to recover its actual commodity costs, including transportation, through a price adjustor. The difference between UNS Gas’ actual monthly gas and transportation costs and the rolling 12-month average cost of gas and transportation is deferred and recovered or returned to customers through the PGA mechanism.
The PGA mechanism has two components, the PGA factor and the PGA surcharge or credit. The PGA factor is a mechanism that calculates the twelve-month rolling weighted average gas cost and automatically adjusts monthly, subject to limitations on how much the price per therm may change in a 12-month period. The annual cap on the maximum increase in the PGA factor is 15 cents per therm in a 12-month period.
At any time UNS Gas’ PGA balancing account, called the PGA bank balance, is under-recovered, UNS Gas may request a PGA surcharge with the goal of collecting the amount deferred from customers over a period deemed appropriate by the ACC. When the PGA bank balance reaches an over-collected balance of $10 million on a billed-to-customer basis, UNS Gas is required to make a filing with the ACC to determine how the over-collected balance should be returned to customers.
In October 2013, the ACC approved an increase to the existing customer PGA credit from 4.5 cents per therm to 10 cents per therm in order to reduce the over-collected PGA bank balance. The new PGA credit will be effective for the period November 1, 2013 through April 30, 2014. At September 30, 2013, the PGA bank balance was over-collected by $17 million on a billed-to-customer basis.
Gas Energy Efficiency Standards
In 2010, the ACC approved Gas EE Standards which are designed to require UNS Gas and other affected utilities to implement cost-effective DSM programs. In 2012, the Gas EE Standards targeted total retail therm savings equal to 1.2% of 2011 sales; in 2013, the Gas EE Standards target total therm savings of 1.8% of 2012 retail therm sales. Targeted savings increase annually in subsequent years until they reach a cumulative annual reduction in retail therm sales of 6% by 2020. UNS Gas' programs, during 2011 and 2012, saved cumulative energy equal to approximately 0.35% of its 2011 retail therm sales.
Existing DSM programs, renewable energy technology that displaces gas and certain energy efficient building codes are acceptable means to meet the Gas EE Standards. The Gas EE Standards provide for the recovery of costs incurred to implement DSM programs. UNS Gas' DSM programs and rates charged to retail customers for these programs are subject to ACC approval.
In 2011, UNS Gas filed its 2011-2012 Gas Energy Efficiency implementation plan and subsequently filed an update in September 2011, which requested a waiver of the Gas EE Standards. In 2012, UNS Gas filed a request to amend its plan to include its 2013 Energy Efficiency plan and for a modified waiver of the Gas EE Standards. We cannot predict when the ACC will rule on the Energy Efficiency plan or the subsequent requests.
Fair Value Measurements
UNS Gas’ income statement exposure to risk is mitigated as UNS Gas reports the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability rather than in the income statement. See Note 11.12.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity Outlook
UNS Gas expects operating cash flows to fund all of its construction expenditures during 2013.2014. If natural gas prices rise and UNS Gas is not allowed to recover its projected gas costs or PGA bank balance on a timely basis, UNS Gas may require additional funding to meet operating and capital requirements in future periods. Sources of funding future capital expenditures could include existing cash balances, draws on the UNS Gas/Electric/UNS ElectricGas Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UNS Energy.
Cash Flows and Capital Expenditures
The table below provides summary cash flow information for UNS Gas:
| | | | Nine Months Ended September 30, | Three Months Ended March 31, |
| | 2013 | | 2012 | 2014 | | 2013 |
| | Millions of Dollars | Millions of Dollars |
| Cash Provided By (Used In): | | | | | | |
| Operating Activities | $ | 18 |
| | $ | 22 |
| $ | 2 |
| | $ | 13 |
|
| Investing Activities | (12 | ) | | (11 | ) | (4 | ) | | (4 | ) |
| Financing Activities | (10 | ) | | (20 | ) | (10 | ) | | (10 | ) |
| Net Increase/(Decrease) in Cash | (4 | ) | | (9 | ) | |
| Net Decrease in Cash | | (12 | ) | | (1 | ) |
| Beginning Cash | 31 |
| | 38 |
| 33 |
| | 31 |
|
| Ending Cash | $ | 27 |
| | $ | 29 |
| $ | 21 |
| | $ | 30 |
|
UNS Gas' operating cash flows during the first nine monthsquarter of 20132014 were $411 million lower than the same period last yearfirst quarter of 2013 due in part to the return of the over-collected PGA credit that was effective in April 2012balance to customers and higher volumes of gas purchased as a result of increased demand from a cold winter.lower retail therm sales.
UNS Gas/UNS Electric Revolver
The UNS Gas/UNS Electric Revolver consists of a $100 million unsecured revolving credit and revolving letter of credit facility. Either company can borrow up to a maximum of $70 million as long as the combined amount borrowed does not exceed $100 million. The UNS Gas/UNS Electric Revolver expires November 2016.
Electric/UNS Gas is only liable for UNS Gas’ borrowings, and similarly, UNS Electric is only liable for UNS Electric’s borrowings under the UNS Gas/UNS Electric Revolver. Credit Agreement
At September 30, 2013,March 31, 2014, UNS Gas had no outstanding borrowings or LOCs under the UNS Gas/Electric/UNS Gas Credit Agreement.
See UNS Electric, Revolver.
TheLiquidity and Capital Resources, UNS Gas/UNS Electric Revolver restricts additional indebtedness, liens, and mergers. It also requires each borrower not to exceed a maximum leverage ratio. Each borrower may pay dividends so long as it maintains compliance with the agreement. At September 30, 2013, Electric/UNS Gas and UNS Electric each were in compliance with the terms of the UNS Gas/UNS Electric Revolver.Credit Agreement.
Interest Rate Risk
UNS Gas is subject to interest rate risk resulting from changes in interest rates on its borrowings under its revolving credit facility. The interest paid on revolving credit borrowings is variable. If LIBOR or other benchmark interest rates increase, UNS Gas may be required to pay higher rates of interest on borrowings under its revolving credit facility. See Item 3. Quantitative and Qualitative Disclosures about Market Risk below..
Contractual Obligations
In 2013, UNS Gas entered into new forward energy commitments that settle through 2016 at fixed prices per MMBtu. UNS Gas’ minimum payment obligations for these purchasesThere are $2 million in 2014, $3 million in 2015, and $2 million in 2016.
UNS Gas also entered into revised gas transportation agreements and anticipates that its commitments will increase by $3 million in 2013, $9 million in each year 2014 through 2016, $10 million in 2017 and $56 million thereafter. See Note 4.
There have been no other significant changes in UNS Gas' contractual obligations or other commercial commitments from those reported in our 20122013 Annual Report on Form 10-K.10-K, other than the following changes in 2014:
UNS Gas entered into new forward energy commitments with minimum payment obligations of $1 million in 2015. See Note 6.
Dividends on Common Stock
UNS Gas paid dividends to UNS Energy, through UES, of $10 million duringin the first nine monthsquarters of 20132014 and $20 million during the first nine months of 2012.2013. UNS Gas’ ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.
The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas may pay dividends so long as (i)1) no default or event of default exists, (ii)and 2) it could incur additional debt under the debt incurrence test. At September 30, 2013March 31, 2014, UNS Gas was in compliance with the terms of its note purchase agreement and had sufficient additional debt under the debt incurrence test to pay dividends.
UNS ELECTRIC
RESULTS OF OPERATIONS
UNS Electric reported net income of $5 million in the third quarter of 2013 compared with net income of $6 million in the third quarter of 2012. In the first nine months of 2013, UNS Electric reported net income of $11 million compared with net income of $14 million in the same period last year. The decline in net income in both periods is related to the loss of an industrial customer during the fourth quarter of 2012 as well as lower mining sales volumes.
Like TEP, UNS Electric’s operations are typically seasonal in nature, with peak energy demand occurring in the summer months. The table below provides summary financial information for UNS Electric:
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2013 | | 2012 | | 2013 | | 2012 |
| | Millions of Dollars |
| Retail Electric Revenues | $ | 52 |
| | $ | 51 |
| | $ | 130 |
| | $ | 134 |
|
| Wholesale Electric Revenues | 2 |
| | 5 |
| | 4 |
| | 13 |
|
| Other Revenues | — |
| | — |
| | 1 |
| | 1 |
|
| Total Operating Revenues | 54 |
| | 56 |
| | 135 |
| | 148 |
|
| Purchased Energy Expense | 23 |
| | 24 |
| | 59 |
| | 61 |
|
| Fuel Expense | 3 |
| | 5 |
| | 7 |
| | 9 |
|
| Transmission Expense | 4 |
| | 3 |
| | 10 |
| | 8 |
|
| Increase (Decrease) to Reflect PPFAC Recovery | 1 |
| | (2 | ) | | (3 | ) | | 1 |
|
| O&M | 7 |
| | 8 |
| | 22 |
| | 23 |
|
| Depreciation and Amortization Expense | 5 |
| | 5 |
| | 14 |
| | 14 |
|
| Taxes Other Than Income Taxes | 1 |
| | 1 |
| | 4 |
| | 4 |
|
| Total Other Operating Expenses | 44 |
| | 44 |
| | 113 |
| | 120 |
|
| Operating Income | 10 |
| | 12 |
| | 22 |
| | 28 |
|
| Interest Expense | 2 |
| | 2 |
| | 5 |
| | 5 |
|
| Income Tax Expense | 3 |
| | 4 |
| | 6 |
| | 9 |
|
| Net Income | $ | 5 |
| | $ | 6 |
| | $ | 11 |
| | $ | 14 |
|
The table below shows UNS Electric’s kWh sales and revenues for the third quarters of 2013 and 2012:
|
| | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Increase (Decrease) |
| | 2013 | | 2012 | | Amount | | Percent(1) |
| Electric Retail Sales, kWh (in Millions): | | | | | | | |
| Residential | 287 |
| | 291 |
| | (4 | ) | | (1.2 | )% |
| Commercial | 171 |
| | 172 |
| | (1 | ) | | (0.3 | )% |
| Industrial | 50 |
| | 58 |
| | (8 | ) | | (14.5 | )% |
| Mining | 16 |
| | 20 |
| | (4 | ) | | (18.2 | )% |
| Public Authorities | — |
| | — |
| | — |
| | 9.5 | % |
| Total Electric Retail Sales | 524 |
| | 541 |
| | (17 | ) | | (3.0 | )% |
| | | | |
| Retail Margin Revenues (in Millions): | | | |
| Residential | $ | 11 |
| | $ | 11 |
| | $ | — |
| | (0.9 | )% |
| Commercial | 8 |
| | 8 |
| | — |
| | — | % |
| Industrial | 2 |
| | 2 |
| | — |
| | (17.4 | )% |
| Mining | 1 |
| | 2 |
| | (1 | ) | | (50.0 | )% |
| Public Authorities | — |
| | — |
| | — |
| | — |
|
Total Retail Margin Revenues (Non-GAAP)(2) | 22 |
| | 23 |
| | (1 | ) | | (5.8 | )% |
| Fuel and Purchased Power Revenues | 28 |
| | 25 |
| | 3 |
| | 13.0 | % |
| RES & DSM Revenues | 2 |
| | 3 |
| | (1 | ) | | (37.0 | )% |
| Total Retail Revenues (GAAP) | $ | 52 |
| | $ | 51 |
| | $ | 1 |
| | (100.0 | )% |
| Weather Data: | | | | | | | |
| Cooling Degree Days | | | | | | | |
| Three Months Ended September 30, | 1,840 |
| | 1,969 |
| | (129 | ) | | (6.6 | )% |
| 10-Year Average | 1,975 |
| | 1,972 |
| | NM |
| | NM |
|
| |
(1)
| Percent change calculated on un-rounded data and may not correspond exactly to data shown in table. |
| |
(2)
| Total Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Total Retail Margin Revenues exclude revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Total Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Total Retail Margin Revenues represents the portion of retail operating revenues available to cover the non-fuel operating expenses of our core utility business. |
Total retail kWh sales in the third quarter of 2013 decreased by 3.0% compared with the same period last year. Sales volumes to mining customers decreased by 18.2% in the third quarter of 2013 due to one of UNS Electric’s mining customers generating a portion of its own electricity. Industrial kWh sales decreased by 14.5% due to the loss of a customer in the fourth quarter of 2012. Total Retail Margin Revenues in the third quarter of 2013 were lower when compared to the third quarter of 2012 due in part to one of UNS Electric's mining customers generating a portion of its own electricity and the loss of an industrial customer in the fourth quarter of 2012. See Factors Affecting Results of Operations, Large Customers, below.
The table below shows UNS Electric’s kWh sales and revenues for the first nine months of 2013 and 2012:
|
| | | | | | | | | | | | | | |
| | Nine Months Ended September 30, | | Increase (Decrease) |
| | 2013 | | 2012 | | Amount | | Percent(1) |
| Electric Retail Sales, kWh (in Millions): | | | | | | | |
| Residential | 678 |
| | 666 |
| | 12 |
| | 1.9 | % |
| Commercial | 468 |
| | 470 |
| | (2 | ) | | (0.4 | )% |
| Industrial | 141 |
| | 167 |
| | (26 | ) | | (15.3 | )% |
| Mining | 46 |
| | 75 |
| | (29 | ) | | (39.4 | )% |
| Public Authorities | 1 |
| | 1 |
| | — |
| | 12.9 | % |
| Total Electric Retail Sales | 1,334 |
| | 1,379 |
| | (45 | ) | | (3.2 | )% |
| | | | |
| Retail Margin Revenues (in Millions): | | | |
| Residential | $ | 26 |
| | $ | 25 |
| | $ | 1 |
| | 1.6 | % |
| Commercial | 22 |
| | 22 |
| | — |
| | (0.5 | )% |
| Industrial | 6 |
| | 7 |
| | (1 | ) | | (15.9 | )% |
| Mining | 3 |
| | 5 |
| | (2 | ) | | (34.0 | )% |
| Public Authorities | — |
| | — |
| | — |
| | — |
|
Total Retail Margin Revenues (Non-GAAP)(2) | 57 |
| | 59 |
| | (2 | ) | | (4.0 | )% |
| Fuel and Purchased Power Revenues | 67 |
| | 67 |
| | — |
| | 0.9 | % |
| RES & DSM Revenues | 6 |
| | 8 |
| | (2 | ) | | (33.7 | )% |
| Total Retail Revenues (GAAP) | $ | 130 |
| | $ | 134 |
| | $ | (4 | ) | | (3.4 | )% |
| Weather Data: | | | | | | | |
| Cooling Degree Days | | | | | | | |
| Nine Months Ended September 30, | 3,144 |
| | 3,243 |
| | (99 | ) | | (3.1 | )% |
| 10-Year Average | 3,049 |
| | 3,073 |
| | NM |
| | NM |
|
| Heating Degree Days | | | | | | | |
| Nine Months Ended September 30, | 1,258 |
| | 1,117 |
| | 141 |
| | 12.6 | % |
| 10-Year Average | 1,239 |
| | 1,253 |
| | NM |
| | NM |
|
| |
(1)
| Percent change calculated on un-rounded data and may not correspond exactly to data shown in table. |
| |
(2)
| Total Retail Margin Revenues, a non-GAAP financial measure, should not be considered as an alternative to Total Retail Revenues, which is determined in accordance with GAAP. Total Retail Margin Revenues exclude revenues collected from retail customers that are directly offset by expenses recorded in other line items. We believe the change in Total Retail Margin Revenues between periods provides useful information to investors because it demonstrates the underlying revenue trend and performance of our core utility business. Total Retail Margin Revenues represents the portion of retail operating revenues available to cover the non-fuel operating expenses of our core utility business. |
Total retail kWh sales in the first nine months of 2013 decreased by 3.2% compared with the same period last year. Sales volumes to mining customers decreased by 39.4% in the first nine months of 2013 due to one of UNS Electric’s mining customers generating a portion of its own electricity. Industrial kWh sales decreased by 15.3% due to the loss of a customer in the fourth quarter of 2012. Total Retail Margin Revenues in the first nine months of 2013 were lower when compared to the same period last year due in part to one of UNS Electric's mining customers generating a portion of its own electricity and the loss of an industrial customer in the fourth quarter of 2012. See Factors Affecting Results of Operations, Large Customers, below.
FACTORS AFFECTING RESULTS OF OPERATIONS
2012 UNS Electric Rate Case
In December 2012, UNS Electric filed a rate case application with the ACC as required by the ACC in UNS Electric's 2010 Rate Order. UNS Electric's rate filing was based on a test year ended June 30, 2012.
In September 2013, UNS Electric, the staff of the ACC, and certain other parties to UNS Electric's pending rate case proceeding entered into a settlement agreement (2013 UNS Electric Settlement Agreement). The 2013 UNS Electric Settlement Agreement requires the approval of the ACC before new rates can become effective.
The terms of the 2013 UNS Electric Settlement Agreement include, but are not limited to:
an increase in non-fuel retail Base Rates of approximately $3 million;
an Original Cost Rate Base (OCRB) of approximately $213 million and a Fair Value Rate Base (FVRB) of approximately $283 million;
a return on equity of 9.50% and a long-term cost of debt of 5.97% resulting in a weighted average cost of capital of 7.83%;
a 0.50% return on the fair value increment of rate base (the fair value increment of rate base represents the difference between OCRB and FVRB of approximately $70 million); and
a capital structure of 52.6% equity and 47.4% long-term debt.
The 2013 UNS Electric Settlement Agreement also includes the following cost recovery mechanisms:
an LFCR mechanism that would allow UNS Electric to recover certain non-fuel costs that would otherwise go unrecovered due to reduced kWh sales attributed to compliance with the ACC's Electric EE Standards and distributed generation requirements under the ACC's RES. The LFCR is not a full decoupling mechanism because it is not intended to recover lost fixed costs attributable to weather or economic conditions; and
a Transmission Cost Adjustment Mechanism (TCA) that would allow more timely recovery of transmission costs associated with serving retail customers at the level approved by FERC. UNS Electric's proposed Base Rates include a transmission component based on UNS Electric’s current FERC Open Access Transmission Tariff (OATT) rate. The OATT rates are adjusted annually and the TCA will be limited to the recovery (or refund) of costs associated with future changes in UNS Electric’s OATT rate.
Status of Rate Proceeding
Hearings before an ACC administrative law judge were completed in September 2013. The settlement agreement requested that new rates be effective by January 1, 2014. We cannot predict if the 2013 UNS Electric Settlement Agreement will be approved or modified by the ACC.
Gila River Generating Station Unit 3
In August 2013, TEP entered into exclusive negotiations with Entegra to purchase Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW. UNS Electric may purchase up to 150 MW of Gila River Unit 3, while TEP would purchase the remaining capacity. See Tucson Electric, Factors Affecting Results of Operations, Gila River Generating Station Unit 3, and Note 13 for more information.
Renewable Energy Standard and Tariff
In October 2013, the ACC approved UNS Electric's 2014 RES implementation plan. Under the plan, UNS Electric will collect approximately $6 million from customers during 2014 to fund: the above market cost of renewable energy purchases; incentives for customer installed distributed generation; a return on and of UNS Electric's investments in company-owned solar projects; and various other program costs. The plan includes approval for a UNS Electric investment of $5 in 2014 for company-owned solar projects. In accordance with the funding mechanism approved by the ACC, UNS Electric could earn approximately $1 million pre-tax in 2014 on company-owned solar investments. UNS Electric expects to meet the 2013 renewable energy target of 4.0% of retail kWh sales and the 2014 target of 4.5%.
Electric Energy Efficiency Standards
In 2010, the ACC approved Electric EE Standards. See Tucson Electric Power, Factors Affecting Results of Operations, Electric Energy Efficiency Standards, above for more information.
In June 2012, UNS Electric filed its 2013 Energy Efficiency implementation plan with the ACC. The proposal includes a request for a 2013 performance incentive of approximately $1 million. UNS Electric requested a waiver from complying with the 2013 Electric EE Standards. UNS Electric is unable to predict when the ACC will issue a final order in this matter.
Competition
See Tucson Electric Power, Factors Affecting Results of Operations, Competition, above.
Large Customers
One of UNS Electric's mining customers began generating a portion of its own electricity needs in 2011. Due to UNS Electric's retail rate structure and the customer's peak electric demand, the margin revenues from this customer in 2012 were near the same level as 2011. Another large retail customer closed its operations in UNS Electric's service territory in the fourth quarter of 2012. As a result of these two events, we estimate UNS Electric's non-residential retail margin revenues will be approximately $4 million lower in 2013 than in 2012.
Interest Rates
UNS Electric is subject to interest rate risk resulting from changes in interest rates on its borrowings under the UNS Gas/UNS Electric Revolver. The interest paid on revolving credit borrowings is variable. If LIBOR or other benchmark interest rates increase, UNS Electric may be required to pay higher rates of interest on borrowings under the UNS Gas/UNS Electric Revolver.
Fair Value Measurements
UNS Electric’s income statement exposure to risk is mitigated as UNS Electric reports the change in fair value of energy contract derivatives as a regulatory asset or a regulatory liability rather than in the income statement. See Note 11.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity Outlook
UNS Electric expects operating cash flows to fund a large portion of its construction expenditures during 2013. Additional sources of funding capital expenditures could include draws on the UNS Gas/UNS Electric Revolver, additional credit lines, the issuance of long-term debt, or capital contributions from UNS Energy.
Cash Flows and Capital Expenditures
The table below provides summary cash flow information for UNS Electric:
|
| | | | | | | |
| | Nine Months Ended September 30, |
| | 2013 | | 2012 |
| | Millions of Dollars |
| Cash Provided By (Used In): | | | |
| Operating Activities | $ | 28 |
| | $ | 39 |
|
| Investing Activities | (47 | ) | | (22 | ) |
| Financing Activities | 15 |
| | (10 | ) |
| Net Increase/(Decrease) in Cash | (4 | ) | | 7 |
|
| Beginning Cash | 8 |
| | 5 |
|
| Ending Cash | $ | 4 |
| | $ | 12 |
|
Operating Activities
Cash provided by operating activities decreased by $11 million in the first nine months of 2013 compared with the same period in 2012 due to: an $8 million decrease in cash receipts from electric sales (net of fuel and purchased energy costs paid) due in part to a lower PPFAC rate that was effective in June 2012, the loss of an industrial customer and lower mining sales; and a $4 million increase in income taxes paid (net of income tax refunds received) due primarily to true-up payments related to estimated income tax payments made in 2012.
Investing Activities
UNS Electric had capital expenditures of $45 million in the first nine months of 2013 compared with $24 million in the same period in 2012. The increase is related to a transmission line that is being constructed to increase reliability to UNS Electric's service territory in Nogales, Arizona. UNS Electric estimates total capital expenditures in 2013 of $52 million.
Financing Activities
Cash provided by financing activities at UNS Electric in the first nine months of 2013 increased by $25 million when compared with the same period in 2012. Financing activities in 2013 included $23 million of borrowings under the UNS Gas/UNS Electric Revolver (net of repayments) and a $2 million receipt related to a contribution in aid of construction from a large customer.
UNS Gas/UNS Electric Revolver
See UNS Gas, Liquidity and Capital Resources, UNS Gas/UNS Electric Revolver above for a description of UNS Electric’s unsecured revolving credit agreement.
UNS Electric expects to draw upon the UNS Gas/UNS Electric Revolver from time to time for seasonal working capital purposes, to fund a portion of its capital expenditures or to issue LOCs to provide credit enhancement for its energy procurement and hedging activities. At September 30, 2013, UNS Electric had $23 million of outstanding borrowings and less than $1 million of LOCs issued under the UNS Gas/UNS Electric Revolver.
Contractual Obligations
In 2013, UNS Electric entered into new forward purchase power commitments that will settle through 2015 at fixed prices per MWh. UNS Electric’s estimated minimum payment obligations for these purchases are $1 million in 2014 and $4 million in 2015.
Additionally, UNS Electric is contractually obligated to certain retail customers with solar installations to make RES PBI payments for environmental attributes, or RECs. In 2013, UNS Electric's total obligation for RES PBIs increased by approximately $1 million, from $6 million at December 31, 2012, to $7 million at September 30, 2013. PBIs are recoverable through the RES tariff. See Note 4.
There have been no other significant changes in UNS Electric’s contractual obligations or other commercial commitments from those reported in our 2012 Annual Report on Form 10-K.
Dividends on Common Stock
In the first nine months of 2013 and 2012, UNS Electric paid dividends of $10 million to UNS Energy, through UES. UNS Electric’s ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.
The note purchase agreement for UNS Electric contains restrictions on dividends. UNS Electric may pay dividends so long as (i) no default or event of default exists, and (ii) it could incur additional debt under the debt incurrence test. At September 30, 2013, UNS Electric was in compliance with the terms of its note purchase agreement and the terms of the UNS Gas/UNS Electric Revolver.
CRITICAL ACCOUNTING ESTIMATES
Plant Asset Depreciable Lives
The 2013 TEP Rate Order approved a change in depreciation rates for generation and distribution plant from an average of 3.32% to 3.00% , effective July 1, 2013. The change in depreciation rates will have the effect of reducing depreciation expense by approximately $11 million annually. The reduction in depreciation expense is primarily due to revised estimates of removal costs, net of estimated salvage value for interim and final retirements. See Note 2.
CRITICAL ACCOUNTING POLICIES
There have been no significant changes in our accounting policies from those disclosed in our 2013 Annual Report on Form 10-K.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
The FASBIn April 2014, the Financial Accounting Standards Board (FASB) issued guidancean accounting standards update that changes the threshold for the recognition, measurement,reporting discontinued operations and disclosure of certain obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. On adoption, an entity would recognize and disclose in the financial statements its obligation from a joint and several liability arrangement as the sum of the amount the entity agreed with its co-obligors that it will pay, and any additional amount the entity expects to pay on behalf of its co-obligors.adds new disclosures. This guidance will be effective in the first quarter of 2014.2015. We do not expectare evaluating the adoption of this guidanceimpact to have a material impact on our financial condition, results of operations, or cash flows.statements and disclosures.
The FASB issued guidance which permits an entity to designate the Federal Funds Rate (the interest rate at which depository institutions lend balances to each other overnight) as a benchmark interest rate for fair value and cash flow hedges. Prior to this guidance, only interest rates on direct treasury obligations of the U.S. Government and the LIBOR were considered benchmark interest rates in the U.S. This guidance is effective immediately, and can be applied prospectively for qualifying new or redesignated hedging relationships entered into on or after July 17, 2013. We have not entered into any new cash flow or fair value hedges since the effective date of this guidance. We do not expect this guidance to have a material impact on our financial condition, results of operations, or cash flows.
The FASB issued new guidance on the financial statement presentation of unrecognized tax benefits when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. We will be required to comply with the guidance on a prospective basis beginning in the first quarter of 2014. Although adoption of this new guidance may impact how such items are classified on our balance sheets, we do not expect such change to be material. In addition, there will be no changes in the presentations of our other financial statements.
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. UNS Energy and TEP are including the following cautionary statements to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or for UNS Energy or TEP in this Quarterly Report on Form 10-Q. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance and underlying assumptions, and other statements that are not statements of historical facts. Forward-looking statements may be identified by the use of words such as anticipates, estimates, expects, intends, plans, predicts, projects, and similar expressions. From time to time, we may publish or otherwise make available forward-looking statements of this nature. All such forward-looking statements, whether written or oral, and whether made by or on behalf of UNS Energy or TEP, are expressly qualified by these cautionary statements and any other cautionary statements which may accompany the forward-looking statements. In addition, UNS Energy and TEP disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.
Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed therein. We express our expectations, beliefs, and projections in good faith and believe them to have a reasonable basis. However, we make no assurances that management’s expectations, beliefs or projections will be achieved or accomplished. We have identified the following important factors that could cause actual results to differ materially from those discussed in our forward-looking statements. These may be in addition to other factors and matters discussed in: Part II, Item 1A. Risk Factors; Part I, Item 2. Management’s Discussion and Analysis;Analysis; and other parts of this report. These factors include: 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 our pension and other retiree 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; cyber attacks or challenges to our information security; and the performance of TEP's generating plants.
ITEM 3. – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
UNS Energy’s and TEP’s primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. We enter into interest rate swaps and financing transactions to manage changes in interest rates. Fluctuations in commodity prices and volumes and counterparty
credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms.
There have been no additional risks and no material changes to market risks disclosed in Part II, Item 7A3 in our Annual Report on Form 10-K for the year ended December 31, 2012, other than the following:2013.
Commodity Price Risk—TEP
See Part 1, Item 2. Management’s Discussion and Analysis, Tucson Electric Power, Factors Affecting Results53
ITEM 4. – CONTROLS AND PROCEDURES
UNS Energy’s and TEP’s Chief Executive Officer and Chief Financial Officer supervised and participated in UNS Energy’s and TEP’s evaluation of their disclosure controls and procedures as such term is defined under Rule 13a – 15(e) or Rule 15d – 15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of the end of the period covered by this report. Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in UNS Energy’s and TEP’s periodic reports filed or submitted under the Exchange Act, is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. These disclosure controls and procedures are also designed to ensure that information required to be disclosed by UNS Energy and TEP in the reports that they file or submit under the Exchange Act is accumulated and communicated to management, including the principal executive and principal financial officers, or person performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation performed, UNS Energy’s and TEP’s Chief Executive Officer and Chief Financial Officer concluded that UNS Energy’s and TEP’s disclosure controls and procedures are effective.
While UNS Energy and TEP continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting, there has been no change in UNS Energy’s or TEP’s internal control over financial reporting during the thirdfirst quarter of 20132014 that has materially affected, or is reasonably likely to materially affect, UNS Energy’s or TEP’s internal control over financial reporting.
PART II –- OTHER INFORMATION
ITEM 1. – LEGAL PROCEEDINGS
See the legal proceedings described in Item 3. – Legal Proceedings in our 20122013 Annual Report on Form 10-K and in Note 46 and in Item 2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, which descriptions in Note 46 and Item 2 are incorporated herein by reference.
Springerville Unit 1 AppraisalShareholder Lawsuits
Springerville Unit 1 is leased by TEP under leases which expireFive putative shareholder class action lawsuits challenging the merger have been filed, four in 2015the Superior Court of Pima County, Arizona: (i) Phillip Malenovshy v. UNS Energy Corporation, et al. (Case No. C20136942); (ii) Paul Parshall v. UNS Energy Corporation, et al. (Case No. C20136943); (iii) Hillary Kramer v. Paul J. Bonavia, et al. (Case No. C2014-0026); and which provide TEP with an option to purchase the lease interests upon the lease expiration at fair market value. In December 2011, TEP(iv) Vandermeer Trust U/A DTD 03/11/1997 v. UNS Energy Corporation, et al. (Case No. C2014-0107); and the owner participants of the Springerville Unit 1 Leases completed a formal appraisal procedure with three appraisersone in accordance with the lease agreements to determine the fair market value purchase price. The lease agreements provide that the purchase price determined through the appraisal procedure will be final and binding upon the parties. The aggregate purchase price for the owner participants' lease interests was determined to be $159 million.
On April 26, 2012, TEP filed a petition to confirm the appraisalfederal court in the United States District Court for the District of Arizona. In the proceeding, the owner participants alleged that the appraisal process failed to yield a legitimate purchase price for
the leased interests. In January 2013, the Federal District Court denied TEP's petition on the grounds that the Court lacks
jurisdiction in the matter. In February 2013, TEP appealed the matter to the U.S. Court of Appeals for the Ninth Circuit.
On August 29, 2013, TEP notified certain owner participants and their lessors of TEP's election to purchase their undivided ownership interests in Springerville Unit 1, at the appraised value upon the expiration of the lease term in January 2015. Because the owner participants whose leased interests TEP elected to purchase have agreed to sell their interests for amounts equal to the appraised value, TEP dismissed its legal action related to the confirmation of the appraised value. SeeArizona: Part 1,Item 2. - Management's Discussion and Analysis, Tucson Electric Power Company, Factors Affecting Results of Operations, Coal-Fired Generating Resources, Springerville Unit 1Milton Pfeiffer v. Paul J. Bonavia, et al. , for more information.(Case No. 4:13-CV-02619-JGZ).
Right of Way Matters
TEP previously reported it was a defendant in a class action filed in February 2009 in the United States District Court in Albuquerque, New Mexico by members of the Navajo Nation. The plaintiffs alleged,lawsuits generally allege, among other things, that the rightsdirectors of wayUNS Energy breached their fiduciary duties to shareholders of UNS Energy purportedly by agreeing to a transaction pursuant to an inadequate process and for defendants’ transmission lines on Navajo lands were improperly granted andfailing to obtain the highest value for UNS Energy shareholders. The lawsuits allege that the compensation paidFortis entities also aided and abetted the directors of UNS Energy in the alleged breach of their fiduciary duties.
The lawsuits seek, in general, and among other things, (i) injunctive relief enjoining the transactions contemplated by the merger agreement, (ii) rescission or an award of rescissory damages in the event a merger is consummated, (iii) an award of plaintiffs’ costs including reasonable attorneys’ and experts’ fees, (iv) an accounting by the defendants to plaintiffs for all damages caused by the defendants, and (v) such rightsfurther relief as the court deems just and proper.
On March 13, 2014, plaintiffs Malenovshy and Parshall voluntarily dismissed their cases.
On March 18, 2014, solely to avoid the costs, risks and uncertainties inherent in litigation, UNS Energy and the other named defendants signed a memorandum of way was inadequate. Theunderstanding (“MOU”) with the remaining plaintiffs were requesting,in the consolidated shareholder class action lawsuits filed in the Superior Court of Pima County, Arizona. This MOU provides, among other things, that the transmission lines on these landsparties will seek to enter into a stipulation of settlement which provides for the release of all asserted claims. The asserted claims will not be removed. In March 2010,released until such stipulation of settlement is approved by the court. There can be no assurance that the court enteredwill approve such settlement. Additionally, as part of the MOU, UNS Energy and Fortis agreed to make certain additional disclosures related to the proposed merger, which are set forth in a final judgment dismissing the case. The plaintiffsForm 8-K filed a Notice of Appeal with the BureauSEC on March 19, 2014. Finally, in connection with the proposed settlement, counsel for plaintiffs intend to seek an award of Indian Affairs (BIA)attorneys’ fees and expenses, subject to court approval. Nothing in May 2010, appealingthis Report on Form 10-Q, the BIA’s decision to grant the rightsMOU or any stipulation of way that were the subjectsettlement shall be deemed an admission of the now-dismissed complaint. In June 2010,legal necessity or materiality under applicable laws of any of the BIA found that the Notice of Appeal failed to meet the minimum filing requirements. In September 2010, the plaintiffs filed new Notices of Appeal concerning the same rights of way. In August 2013, the Interior Board of Indian Appealsdisclosure set forth herein.
On April 15, 2014, plaintiff Pfeiffer voluntarily dismissed the plaintiffs’ appeal for failure to meet procedural requirements. TEP cannot predict if the plaintiffs will again attempt to appeal the BIA’s decision to grant the rights of way.his case.
ITEM 1A. – RISK FACTORS
The business and financial results of UNS Energy and TEP are subject to numerous risks and uncertainties. There are no significant changes to the risks and uncertainties reported in our 20122013 Annual Report on Form 10-K and our 2013 Form 10-Q for the quarterly period ended June 30, 2013.10-K.
ITEM 5. – OTHER INFORMATION
RATIO OF EARNINGS TO FIXED CHARGES
The following table reflects the ratio of earnings to fixed charges for UNS Energy and TEP:
| | | | Nine Months Ended September 30, 2013 | | Twelve Months Ended September 30, 2013 | Three Months Ended March 31, 2014 | | Twelve Months Ended March 31, 2014 |
| UNS Energy | 3.180 |
| | 2.701 |
| 1.901 |
| | 2.815 |
|
| TEP | 3.147 |
| | 2.556 |
| 1.561 |
| | 2.789 |
|
For purposes of this computation, earnings are defined as pre-tax earnings plus interest expense and amortization of debt discount and expense. Fixed charges are interest expense, including amortization of debt discount and expense.
ENVIRONMENTAL MATTERS
See Note 6.
Hazardous Air Pollutant Requirements
The table below provides a summaryClean Air Act requires the EPA to develop emission limit standards for hazardous air pollutants that reflect the maximum achievable control technology. In February 2012, the EPA issued final rules to set the standards for the control of mercury emissions and other hazardous air pollutants from power plants (MATS rules).
Navajo
Based on the MATS rules, Navajo may require mercury and particulate matter emission control equipment by April 2016. TEP’s share of the estimated impactcapital cost of pendingthis equipment is less than $1 million for mercury control and about $43 million if the installation of baghouses to control particulates is necessary. The operator of Navajo is currently analyzing the need for baghouses under various regulatory scenarios, which will be affected by final Best Available Retrofit Technology (BART) rules when issued. TEP expects its share of the annual operating costs for mercury control and baghouses to be less than $1 million each.
San Juan
TEP expects San Juan’s current emission controls to be adequate to comply with the MATS rules.
Four Corners
Based on the MATS rules, Four Corners may require mercury emission control equipment by April 2015. TEP's share of the estimated capital cost of this equipment is less than $1 million. TEP expects its share of the annual operating cost of the mercury emission control equipment to be less than $1 million.
Springerville Generating Station
Based on the MATS rules, Springerville Generating Station (Springerville) may require mercury emission control equipment by April 2015. The estimated capital cost of this equipment for Springerville Units 1 and 2 is about $5 million. TEP expects the annual operating cost of the mercury emission control equipment to be about $3 million. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases by early 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental regulationscosts attributed to Springerville Unit 1.
Sundt Generating Station
TEP expects the MATS rules will have little effect on TEP's annual O&M expensecapital expenditures at Sundt.
Regional Haze Rules
The EPA's Regional Haze Rules require emission controls known as BART for certain industrial facilities emitting air pollutants that reduce visibility in national parks and
capital expenditures. See Note 4wilderness areas. The rules call for more information. |
| | | | | | | | | | | |
| Generating Facility | |
Estimated Annual O&M Expense | |
Estimated Capital Expenditures | |
Regulation (Compliance Date) | Upgrades |
| | | Millions of Dollars | | | |
| Springerville Units 1 & 2 | | $ | 3 |
| | $ | 5 |
| | MATS (2015) | Mercury Controls |
| San Juan Unit 1 | | 1 |
| | 35 |
| | Regional Haze/BART (2016) | SNCRs |
| Navajo Units 1-3 | | 3 |
| | 86 |
| | MATS (2015) Regional Haze/BART (2030) | Mercury Controls; SCRs; Baghouses |
| Four Corners Units 4 & 5 | | 3 |
| | 36 |
| | MATS (2015) Regional Haze/BART (2018) | Mercury Controls; SCRs |
Navajo Indian Reservation, they are not subject to state oversight; the EPA oversees regional haze planning for these power plants.
Complying with the EPA’s BART findings, and with other future environmental rules, may make it economically impractical to continue operating the Navajo, San Juan, and Four Corners power plants or for individual owners to continue to participate in these power plants. TEP cannot predict the ultimate outcome of these matters.
Navajo
In January 2013, the EPA proposed a BART determination that would require the installation of Selective Catalytic Reduction (SCR) technology on all three units at Navajo by 2023. In July 2013, SRP, along with other stakeholders including impacted government agencies, environmental organizations, and tribal representatives, submitted an agreement to the EPA that would achieve greater NOx emission reductions than the EPA's proposed BART rule. In September 2013, the EPA issued a supplemental proposal incorporating the provisions of the agreement as a better-than-BART alternative.
Among other things, the agreement calls for the shut-down of one unit or an equivalent reduction in emissions by 2020. The table below providesshutdown of one unit will not impact the total amount of energy delivered to TEP from Navajo. Additionally, the remaining Navajo participants would be required to install SCR or an equivalent technology on the remaining two units by 2030. As part of the agreement, the current owners have committed to cease their operation of conventional coal-fired generation at Navajo no later than December 2044. The Navajo Nation can continue operation after 2044 at its election. If SCR technology is ultimately implemented at Navajo, TEP estimates its share of the capital cost will be $42 million. Also, the installation of SCR technology at Navajo could increase the power plant's particulate emissions which may require that baghouses be installed. TEP estimates that its share of the capital expenditure for baghouses would be about $43 million. TEP's ownership interestshare of annual operating costs for SCR and baghouses is estimated at less than $1 million each. The EPA could issue their decision as early as 2014.
San Juan
In August 2011, the EPA issued a Federal Implementation Plan (FIP) establishing new emission limits for air pollutants at San Juan. These requirements are more stringent than those proposed by the State of New Mexico. The FIP requires the installation of SCR technology with sorbent injection on all four units to reduce NOx and control sulfuric acid emissions by September 2016. TEP estimates its share of the cost to install SCR technology with sorbent injection to be between $180 million and $200 million. TEP expects its share of the annual operating costs for SCR technology to be approximately $6 million.
In 2011, PNM filed a petition for review of, and a motion to stay, the FIP with the United States Court of Appeals for the Tenth Circuit (Tenth Circuit). In addition, the operator filed a request for reconsideration of the rule with the EPA and a request to stay the effectiveness of the rule pending the EPA's reconsideration and review by the Tenth Circuit. The State of New Mexico filed similar motions with the Tenth Circuit and the EPA. Several environmental groups were granted permission to join in opposition to PNM's petition to review in the Tenth Circuit. In addition, WildEarth Guardians filed a separate appeal against the EPA challenging the FIP's five-year implementation schedule. PNM was granted permission to join in opposition to that appeal. In March 2012, the Tenth Circuit denied PNM's and the State of New Mexico's motion for stay. Oral argument on the appeal was heard in October 2012.
In February 2013, the State of New Mexico, the EPA, and PNM signed a non-binding agreement (Settlement Agreement) that outlines an alternative to the FIP. The terms of the Settlement Agreement include: the retirement of San Juan Units 2 and 3 by December 31, 2017; the replacement by PNM of those units with non-coal generation sources; and the installation of SNCR on San Juan Units 1 and 4 by January 2016 or later depending on the timing of EPA approvals. The New Mexico Environmental Department (NMED) prepared a revision to the regional haze State Implementation Plan (SIP) incorporating the provisions of the Settlement Agreement, and in September 2013, the New Mexico Environmental Improvement Board approved the SIP revision. The SIP revision now awaits final EPA approval. The EPA is expected to issue a final BART determination in 2014. TEP estimates its share of the cost to install SNCR technology on San Juan Unit 1 would be approximately $35 million. TEP's share of incremental annual operating costs for SNCR is estimated at $1 million. TEP owns 340 MW, or 50%, of San Juan Units 1 and 2. If San Juan Unit 2 is retired, TEP's coal-fired generating facilities:capacity would be reduced by 170 MW.
In connection with the implementation of the SIP revision and the retirement of San Juan Units 2 and 3, some of the San Juan owner participants (Participants) have expressed a desire to exit their ownership in the plant. As a result, the Participants are attempting to negotiate a restructuring of the ownership in San Juan, as well as addressing the obligations of the exiting Participants for plant decommissioning, mine reclamation, environmental matters, and certain ongoing operating costs, among other items. The Participants have engaged a mediator to assist in facilitating the resolution of these matters among the owners. The owners of the affected units also may seek approvals of their utility commissions or governing boards. We are unable to predict the outcome of the negotiations and mediation.
|
| | | | | |
| | Unit | Net Capability | Operating | TEP's Share |
| Generating Facility | No. | MW | Agent | % | MW |
Springerville Station(1) | 1 | 401 | TEP | 100.0 | 401 |
| Springerville Station | 2 | 403 | TEP | 100.0 | 403 |
| San Juan Station | 1 | 340 | PNM | 50.0 | 170 |
| San Juan Station | 2 | 340 | PNM | 50.0 | 170 |
| Navajo Station | 1 | 750 | SRP | 7.5 | 56 |
| Navajo Station | 2 | 750 | SRP | 7.5 | 56 |
| Navajo Station | 3 | 750 | SRP | 7.5 | 56 |
| Four Corners Station | 4 | 784 | APS | 7.0 | 55 |
| Four Corners Station | 5 | 784 | APS | 7.0 | 55 |
Sundt Station(2) | 4 | 120 | TEP | 100.0 | 120 |
On October 17, 2013, the Tenth Circuit ruled on a motion filed by PNM for abatement of the pending petitions for review and seeking deferral of briefing on a simultaneously-filed motion to stay the FIP. The Tenth Circuit placed the pending petitions for review in abeyance and set a schedule for the parties to file status reports. The court ruled that, if at any time the Settlement Agreement is not implemented as contemplated, any party to the litigation may file a motion seeking to lift the abatement.
(1) AsAt March 31, 2014, the book value of September 30,TEP's share of San Juan Unit 2 was$112 million. If Unit 2 is retired early, we expect to request ACC approval to recover, over a reasonable time period, all costs associated with the early closure of the unit. TEP cannot predict the ultimate outcome of this matter.
Four Corners
In 2012, the EPA finalized the regional haze FIP for Four Corners. The final FIP requires SCR technology to be installed on all five units by 2017. In December 2013, TEP owned a 14% undivided interestAPS (the operator) decided to shut down Units 1, 2, and leased3 and install SCRs on Units 4 and 5. Under this scenario, the remaining 86%. See Part I - Item 2.Tucson Electric Power, Factors Affecting Resultsinstallation of Operations, Coal-Fired Generation Resources,SCR technology can be delayed until July 2018. TEP's estimated share of the capital costs to install SCR technology on Units 4 and 5 is approximately $35 million. TEP's share of incremental annual operating costs for SCR is estimated at $2 million.
Springerville
The BART provisions of the Regional Haze Rules requiring emission control upgrades do not apply to Springerville UnitUnits 1, for more information. and 2 since they were constructed in the 1980s which is after the time frame as designated by the rules. Other provisions of the Regional Haze Rules requiring further emission reduction are not likely to impact Springerville operations until after 2018.
(2) Sundt
In July 2013, the EPA rejected the Arizona state implementation plan determination that Sundt Unit 4 is not subject to the BART provisions of the Regional Haze Rule and developed a dual fuel unittimeline to issue a federal implementation plan for emissions sources including Sundt Unit 4. While TEP does not agree that can be operated with coal or natural gas. The net generating capability when Sundt Unit 4 is operated with natural gassubject to BART, it submitted a better-than-BART proposal in November 2013 which called for the elimination of coal as a fuel source at Sundt by the end of 2017. In January 2014, the EPA issued a BART proposal that would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection if Sundt Unit 4 continues to use coal as a fuel source, or (ii) permanently eliminate coal as a fuel source as a better-than-BART alternative by the end of 2017. TEP estimates that the cost to install SNCR and DSI would be approximately $12 million, and the incremental annual operating costs would be $5 million to $6 million. Under the proposal, TEP would be required to notify the EPA of its decision by July 31, 2015. The EPA is 156 MW.expected to issue a final BART determination by July 2014. At March 31, 2014, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, we expect to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.
Greenhouse Gas Regulation
In June 2013, President Obama directed the EPA to move forward with carbon emission regulations to limit carbon emissions fromfor both new and existing fossil-fueled power plants.
In September 2013.January 2014, the EPA issuedpublished a re-proposed rule for new power plants. UNS Energy does not anticipate that a final rule related to new fossil-fueled power plant sources will have a significant impact on operations.
Additionally,For existing power plants, the President ordered the EPA to:
propose carbon emission standards for existing power plants by June 1, 2014;
finalize those standards by June 1, 2015; and
require states to submit their implementation plans to meet the standards by June 30, 2016.
UNS Energy will continue to work with regulatory agencies (both federal and state)state regulatory agencies to promote compliance flexibility in the rules impacting existing fossil-fuel fired power plants. We cannot predict the ultimate outcome of these matters.
ITEM 6. – EXHIBITS
See Exhibit Index.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.
|
| | | |
| | | | |
| | | | UNS ENERGY CORPORATION |
| | | | (Registrant) |
| | | | |
| Date: | November 6, 2013April 28, 2014 | | /s/ Kevin P. Larson |
| | | | Kevin P. Larson |
| | | | Senior Vice President and Chief |
| | | | Financial Officer |
| | | | |
| | | | TUCSON ELECTRIC POWER COMPANY |
| | | | (Registrant) |
| | | | |
| Date: | November 6, 2013April 28, 2014 | | /s/ Kevin P. Larson |
| | | | Kevin P. Larson |
| | | | Senior Vice President and Chief |
| | | | Financial Officer |
EXHIBIT INDEX
|
| | | | | | |
| | |
| 12(a) | | — | | Computation of Ratio of Earnings to Fixed Charges – UNS Energy. |
| | | | |
| 12(b) | | — | | Computation of Ratio of Earnings to Fixed Charges – TEP. |
| | | | |
15(a) | — | | Letter regarding unaudited interim financial information – UNS Energy. |
| | | |
15(b) | — | | Letter regarding unaudited interim financial information – TEP. |
| | | |
| 31(a) | | — | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – UNS Energy, by Paul J. Bonavia. |
| | | | |
| 31(b) | | — | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – UNS Energy, by Kevin P. Larson. |
| | | | |
| 31(c) | | — | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – TEP, by Paul J. Bonavia. |
| | | | |
| 31(d) | | — | | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – TEP, by Kevin P. Larson. |
| | | | |
| **32(a) | | — | | Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) –- UNS Energy. |
| | | |
| **32(b) | | — | | Statements of Corporate Officers (pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) –- TEP. |
| | | | |
| 101 | | — | | The following materials from UNS Energy’s and TEP’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013, formatted in XBRL (Extensible Business Reporting Language): |
| | | | |
101 | — | | The following materials from UNS Energy Corporation’s and Tucson Electric Power Company’s Quarterly Report on Form 10-Q for the three and nine-month periods ended September 30, 2013, formatted in XBRL (Extensible Business Reporting Language): |
| |
| (a) | UNS Energy Corporation’sEnergy’s and Tucson Electric Power Company’sTEP’s (i) Condensed Consolidated Statements of Income, (ii) Condensed Consolidated Statements of Comprehensive Income (iii) Condensed Consolidated Statements of Cash Flows, (iv) Condensed Consolidated Balance Sheets, (v) Condensed Consolidated StatementStatements of Capitalization, (vi) Consolidated Statements of Changes in Stockholders’ Equity; and |
| | | |
| | | | (b) | Notes to Consolidated Financial Statements. |
|
| |
(b)(*) | Notes to Condensed Consolidated Financial Statements.Previously filed as indicated and incorporated herein by reference. |
* Previously filed as indicated and incorporated herein by reference.
** Not filed |
| |
| ** | Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended. |