TEP & UNS 10Q 6.30.2014


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2014
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                     to                     . 
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
 
 
 
 
 
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.
UNS Energy Corporation
Yes  x
 
No  ¨
 
 
 
 
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).
UNS Energy Corporation
Yes  x
 
    No  ¨
 
 
 
 
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):
UNS Energy Corporation
Large Accelerated Filer
 
x
 
Accelerated Filer
 
¨
 
Non-accelerated Filer
 
¨
 
Smaller Reporting Company
 
¨
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).
UNS Energy Corporation
Yes  ¨
 
    No  x
  
Tucson Electric Power Company
Yes  ¨
 
    No  x
  

As of July 18, 2014, 41,701,718 shares of UNS Energy Corporation Common Stock, no par value (the only class of Common Stock), were outstanding. As of July 18, 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.


ii



Table of Contents
PART I
 
 
 
 
 
 
 
 
 
PART II
 
 
 

iii




DEFINITIONS
The abbreviations and acronyms used in the second quarter 2014 Form 10-Q are defined below:
 
 
 
2010 TEP Reimbursement Agreement
 
Reimbursement Agreement, dated December 14, 2010, between TEP, as borrower, and a financial institution
2013 Covenants Agreement
 
A Lender Rate Mode Covenants Agreement between TEP and the purchaser of $100 million of unsecured tax-exempt bonds that were issued on behalf of TEP in November 2013 and sold in a private placement
ACC
 
Arizona Corporation Commission
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
Btu
 
British thermal unit(s)
Cooling Degree Days
 
An index used to measure the impact of weather on energy usage calculated by subtracting 75 from the average of the high and low daily temperatures
DSM
 
Demand Side Management
ECA
 
Environmental Compliance Adjustor
Entegra
 
a subsidiary of Entegra Power Group LLC
FERC
 
Federal Energy Regulatory Commission
Fortis
 
Fortis Inc., a corporation incorporated under the Corporations Act of Newfoundland and Labrador, Canada
Four Corners
 
Four Corners Generating Station
GBtu
 
Billion British thermal units
GWh
 
Gigawatt-hour(s)
Gila River Unit 3
 
Unit 3 of the Gila River Generating Station
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
kV
 
Kilo-volt
kWh
 
Kilowatt-hour(s)
LFCR
 
Lost Fixed Cost Recovery Mechanism
Millennium
 
Millennium Energy Holdings, Inc., a wholly-owned subsidiary of UNS Energy Corporation
MMBtu
 
Million British thermal units
MW
 
Megawatt(s)
MWh
 
Megawatt-hour(s)
Navajo
 
Navajo Generating Station
OATT
 
Open Access Transmission Tariff
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
PPFAC
 
Purchased Power and Fuel Adjustment Clause
REC
 
Renewable Energy Credit
Regional Haze Rules
 
Rules promulgated by the EPA to improve visibility at national parks and wilderness areas
Regulated Utilities
 
Tucson Electric Power Company (TEP); UNS Electric, Inc. (UNS Electric); and UNS Gas, Inc. (UNS Gas) collectively

iv



RES
 
Renewable Energy Standard
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
San Juan
 
San Juan Generating Station
SCR
 
Selective Catalytic Reduction
SJCC
 
San Juan Coal Company
SNCR
 
Selective Non-Catalytic Reduction
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
Sundt
 
H. Wilson Sundt Generating Station
Sundt Unit 4
 
Unit 4 of the H. Wilson Sundt Generating Station
TCA
 
Transmission Cost Adjustor
TEP
 
Tucson Electric Power Company, the principal subsidiary of UNS Energy Corporation
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 Electric and UNS 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
 


v

Table of Contents

PART I—FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended
 
 
Six Months Ended
June 30,
 
 
June 30,
2014
 
2013
 
 
2014
 
2013
(Unaudited)
 
 
(Unaudited)
Thousands of Dollars
 
 
Thousands of Dollars
(Except Per Share Amounts)
 
 
(Except Per Share Amounts)
 
 
 
 
Operating Revenues
 
 
 
$
302,975

 
$
285,419

 
Electric Retail Sales
$
527,545

 
$
506,279

33,309

 
30,654

 
Electric Wholesale Sales
76,730

 
65,052

21,911

 
20,013

 
Gas Retail Sales
60,481

 
71,002

28,411

 
29,131

 
Other Revenues
55,242

 
55,025

386,606

 
365,217

 
Total Operating Revenues
719,998

 
697,358

 
 
 
 
Operating Expenses
 
 
 
69,418

 
86,459

 
Fuel
137,253

 
168,148

84,060

 
57,796

 
Purchased Energy
153,843

 
121,955

6,142

 
4,521

 
Transmission and Other PPFAC Recoverable Costs
12,670

 
7,707

(12,517
)
 
2,074

 
Increase (Decrease) to Reflect PPFAC/PGA Recovery Treatment
(21,437
)
 
(3,294
)
147,103

 
150,850

 
Total Fuel and Purchased Energy
282,329

 
294,516

91,621

 
95,143

 
Operations and Maintenance
185,057

 
185,043

39,563

 
36,671

 
Depreciation
78,644

 
72,970

6,455

 
8,119

 
Amortization
12,631

 
16,408

14,942

 
13,631

 
Taxes Other Than Income Taxes
29,750

 
27,723

299,684

 
304,414

 
Total Operating Expenses
588,411

 
596,660

86,922

 
60,803

 
Operating Income
131,587

 
100,698

 
 
 
 
Other Income (Deductions)
 
 
 
169

 
19

 
Interest Income
249

 
28

2,538

 
1,734

 
Other Income
4,680

 
3,502

(958
)
 
(807
)
 
Other Expense
(1,688
)
 
(1,380
)
624

 
94

 
Appreciation in Fair Value of Investments
879

 
1,133

2,373

 
1,040

 
Total Other Income (Deductions)
4,120

 
3,283

 
 
 
 
Interest Expense
 
 
 
19,167

 
17,700

 
Long-Term Debt
37,055

 
35,954

3,925

 
6,249

 
Capital Leases
7,846

 
12,498

307

 
346

 
Other Interest Expense
790

 
(47
)
(1,295
)
 
(745
)
 
Interest Capitalized
(2,318
)
 
(1,420
)
22,104

 
23,550

 
Total Interest Expense
43,373

 
46,985

67,191

 
38,293

 
Income Before Income Taxes
92,334

 
56,996

24,837

 
3,675

 
Income Tax Expense
34,505

 
11,033

$
42,354

 
$
34,618

 
Net Income
$
57,829

 
$
45,963

 
 
 
 
Weighted-Average Shares of Common Stock Outstanding (000)
 
 
 
41,781

 
41,598

 
Basic
41,759

 
41,569

42,145

 
41,921

 
Diluted
42,115

 
41,898

 
 
 
 
Earnings Per Share
 
 
 
$
1.01

 
$
0.83

 
Basic
$
1.38

 
$
1.11

$
1.01

 
$
0.83

 
Diluted
$
1.37

 
$
1.10

$
0.480

 
$
0.435

 
Dividends Declared Per Share
$
0.960

 
$
0.870

See Notes to Condensed Consolidated Financial Statements.

1




UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Three Months Ended
 
 
Six Months Ended
June 30,
 
 
June 30,
2014
 
2013
 
 
2014
 
2013
(Unaudited)
 
 
(Unaudited)
Thousands of Dollars
 
 
Thousands of Dollars
 
 
 
 
Comprehensive Income
 
 
 
$
42,354

 
$
34,618

 
Net Income
$
57,829

 
$
45,963

 
 
 
 
Other Comprehensive Income
 
 
 
 
 
 
 
Net Changes in Fair Value of Cash Flow Hedges:
 
 
 
517

 
933

 
net of income tax expense of $335 and $610
 
 
 
 
 
 
 
net of income tax expense of $691 and $1,009
1,010

 
1,544

 
 
 
 
 
 
 
 
 
 
 
 
Supplemental Executive Retirement Plan (SERP) Benefit Amortization:
 
 
 
25

 
68

 
net of income tax expense of $15 and $43
 
 
 
 
 
 
 
net of income tax expense of $30 and $85
49

 
137

542

 
1,001

 
Total Other Comprehensive Income, Net of Tax
1,059

 
1,681

$
42,896

 
$
35,619

 
Total Comprehensive Income
$
58,888

 
$
47,644


See Notes to Condensed Consolidated Financial Statements.


2



UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Six Months Ended
 
June 30,
 
2014
 
2013
 
(Unaudited)
 
Thousands of Dollars
Cash Flows from Operating Activities
 
 
 
Cash Receipts from Electric Retail Sales
$
531,439

 
$
519,154

Cash Receipts from Electric Wholesale Sales
89,741

 
82,273

Cash Receipts from Gas Retail Sales
80,348

 
91,207

Cash Receipts from Operating Springerville Units 3 & 4
47,099

 
49,974

Cash Receipts from Gas Wholesale Sales
2,287

 
3,494

Income Tax Refunds Received
472

 

Interest Received
7

 
516

Other Cash Receipts
22,812

 
16,914

Purchased Energy Costs Paid
(152,982
)
 
(135,775
)
Payment of Operations and Maintenance Costs
(138,692
)
 
(121,272
)
Fuel Costs Paid
(135,128
)
 
(140,185
)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized
(86,695
)
 
(90,554
)
Wages Paid, Net of Amounts Capitalized
(72,237
)
 
(68,004
)
Interest Paid, Net of Amounts Capitalized
(31,446
)
 
(34,662
)
Capital Lease Interest Paid
(15,888
)
 
(18,630
)
Other Cash Payments
(3,380
)
 
(6,798
)
Net Cash Flows—Operating Activities
137,757

 
147,652

Cash Flows from Investing Activities
 
 
 
Capital Expenditures
(186,037
)
 
(155,685
)
Return of Investments in Springerville Lease Debt

 
9,104

Other, net
(4,345
)
 
(3,613
)
Net Cash Flows—Investing Activities
(190,382
)
 
(150,194
)
Cash Flows from Financing Activities
 
 
 
Proceeds from Borrowings Under Revolving Credit Facilities
151,000

 
114,000

Repayments of Borrowings Under Revolving Credit Facilities
(129,000
)
 
(48,000
)
Proceeds from Issuance of Long-Term Debt
149,168

 

Payments of Capital Lease Obligations
(83,204
)
 
(84,206
)
Common Stock Dividends Paid
(40,034
)
 
(36,079
)
Payment of Debt Issue/Retirement Costs
(1,641
)
 
(982
)
Proceeds from Stock Options Exercised
595

 

Other, net
543

 
3,584

Net Cash Flows—Financing Activities
47,427

 
(51,683
)
Net Increase (Decrease) in Cash and Cash Equivalents
(5,198
)
 
(54,225
)
Cash and Cash Equivalents, Beginning of Year
74,878

 
123,918

Cash and Cash Equivalents, End of Period
$
69,680

 
$
69,693


See Note 11 for supplemental cash flow information.

See Notes to Condensed Consolidated Financial Statements.

3




UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
 
June 30,
 
December 31,
 
2014
 
2013
 
(Unaudited)
 
Thousands of Dollars
ASSETS
 
Utility Plant
 
 
 
Plant in Service
$
5,392,666

 
$
5,192,122

Utility Plant Under Capital Leases
747,158

 
637,957

Construction Work in Progress
186,249

 
201,959

Total Utility Plant
6,326,073

 
6,032,038

Less Accumulated Depreciation and Amortization
(2,078,626
)
 
(1,982,524
)
Less Accumulated Amortization of Capital Lease Assets
(525,327
)
 
(514,677
)
Total Utility Plant—Net
3,722,120

 
3,534,837

Investments and Other Property
 
 
 
Investments in Lease Equity
36,122

 
36,194

Other
35,551

 
34,971

Total Investments and Other Property
71,673

 
71,165

Current Assets
 
 
 
Cash and Cash Equivalents
69,680

 
74,878

Accounts Receivable—Customer
114,276

 
104,596

Unbilled Accounts Receivable
67,637

 
52,403

Allowance for Doubtful Accounts
(7,001
)
 
(6,833
)
Materials and Supplies
92,771

 
88,085

Deferred Income Taxes—Current
86,401

 
66,906

Regulatory Assets—Current
69,322

 
52,763

Fuel Inventory
44,044

 
44,317

Derivative Instruments
9,850

 
5,629

Other
17,453

 
15,354

Total Current Assets
564,433

 
498,098

Regulatory and Other Assets
 
 
 
Regulatory Assets—Noncurrent
162,263

 
150,584

Derivative Instruments
1,528

 
1,180

Other Assets
26,575

 
24,430

Total Regulatory and Other Assets
190,366

 
176,194

Total Assets
$
4,548,592

 
$
4,280,294

See Notes to Condensed Consolidated Financial Statements.

 (Continued)

4




UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

 
June 30,
 
December 31,
 
2014
 
2013
 
(Unaudited)
 
Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
 
Capitalization
 
 
 
Common Stock Equity
$
1,149,578

 
$
1,130,784

Capital Lease Obligations
69,938

 
131,370

Long-Term Debt
1,677,323

 
1,507,070

Total Capitalization
2,896,839

 
2,769,224

Current Liabilities
 
 
 
Current Obligations Under Capital Leases
272,939

 
186,056

Borrowings Under Revolving Credit Facilities
23,000

 
22,000

Accounts Payable—Trade
104,720

 
117,503

Regulatory Liabilities—Current
54,384

 
53,935

Accrued Taxes Other than Income Taxes
47,601

 
43,880

Customer Deposits
28,066

 
30,671

Accrued Employee Expenses
23,202

 
28,148

Accrued Interest
29,637

 
27,786

Derivative Instruments
6,435

 
7,534

Other
22,536

 
17,775

Total Current Liabilities
612,520

 
535,288

Deferred Credits and Other Liabilities
 
 
 
Deferred Income Taxes—Noncurrent
528,636

 
488,887

Regulatory Liabilities—Noncurrent
326,388

 
302,482

Pension and Other Retiree Benefits
90,984

 
90,923

Derivative Instruments
5,976

 
7,100

Other
87,249

 
86,390

Total Deferred Credits and Other Liabilities
1,039,233

 
975,782

Commitments, Contingencies, and Environmental Matters (Note 6)

 

Total Capitalization and Other Liabilities
$
4,548,592

 
$
4,280,294

See Notes to Condensed Consolidated Financial Statements.
(Concluded)


5




UNS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
 
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
 
 
 
 
57,829

 
 
 
57,829

Other Comprehensive Income, net of tax
 
 

 

 
1,059

 
1,059

Dividends Declared

 
 
 
(40,372
)
 

 
(40,372
)
Shares Issued for Stock Options
20

 
594

 

 

 
594

Shares Issued under Performance Share Awards
101

 

 

 

 

Share-based Compensation
 
 
(316
)
 
 
 
 
 
(316
)
Balances at June 30, 2014
41,659

 
$
889,579

 
$
264,989

 
$
(4,990
)
 
$
1,149,578

* UNS Energy has 75 million authorized shares of Common Stock.
See Notes to Condensed Consolidated Financial Statements.



6



                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended
 
 
Six Months Ended
June 30,
 
 
June 30,
2014
 
2013
 
 
2014
 
2013
(Unaudited)
 
 
(Unaudited)
 Thousands of Dollars
 
 
Thousands of Dollars
 
 
 
 
Operating Revenues
 
 
 
$
257,790

 
$
243,635

 
Electric Retail Sales
$
443,805

 
$
428,515

32,555

 
29,542

 
Electric Wholesale Sales
74,639

 
63,940

31,273

 
31,086

 
Other Revenues
58,687

 
59,559

321,618

 
304,263

 
Total Operating Revenues
577,131

 
552,014

 
 
 
 
Operating Expenses
 
 
 
68,334

 
84,553

 
Fuel
135,964

 
165,351

52,906

 
28,410

 
Purchased Power
75,521

 
47,338

3,552

 
1,730

 
Transmission and Other PPFAC Recoverable Costs
7,461

 
2,595

(13,061
)
 
5,274

 
Increase (Decrease) to Reflect PPFAC Recovery Treatment
(14,791
)
 
2,914

111,731

 
119,967

 
Total Fuel and Purchased Energy
204,155

 
218,198

79,772

 
82,011

 
Operations and Maintenance
161,117

 
159,835

31,080

 
28,861

 
Depreciation
61,891

 
57,418

7,377

 
9,052

 
Amortization
14,476

 
18,275

12,005

 
10,939

 
Taxes Other Than Income Taxes
23,840

 
22,108

241,965

 
250,830

 
Total Operating Expenses
465,479

 
475,834

79,653

 
53,433

 
Operating Income
111,652

 
76,180

 
 
 
 
Other Income (Deductions)
 
 
 
165

 
12

 
Interest Income
174

 
8

2,187

 
1,270

 
Other Income
4,099

 
2,438

(2,694
)
 
(2,472
)
 
Other Expense
(4,809
)
 
(4,717
)
624

 
94

 
Appreciation in Fair Value of Investments
879

 
1,133

282

 
(1,096
)
 
Total Other Income (Deductions)
343

 
(1,138
)
 
 
 
 
Interest Expense
 
 
 
15,507

 
13,991

 
Long-Term Debt
29,747

 
28,564

3,925

 
6,249

 
Capital Leases
7,846

 
12,498

140

 
192

 
Other Interest Expense
453

 
(168
)
(1,104
)
 
(534
)
 
Interest Capitalized
(2,028
)
 
(1,027
)
18,468

 
19,898

 
Total Interest Expense
36,018

 
39,867

61,467

 
32,439

 
Income Before Income Taxes
75,977

 
35,175

22,742

 
1,652

 
Income Tax Expense
28,080

 
2,909

$
38,725

 
$
30,787

 
Net Income
$
47,897

 
$
32,266

See Notes to Condensed Consolidated Financial Statements.


7




TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
Three Months Ended
 
 
Six Months Ended
June 30,
 
 
June 30,
2014
 
2013
 
 
2014
 
2013
(Unaudited)
 
 
(Unaudited)
 Thousands of Dollars 
 
 
Thousands of Dollars
 
 
 
 
Comprehensive Income
 
 
 
$
38,725

 
$
30,787

 
Net Income
$
47,897

 
$
32,266

 
 
 
 
Other Comprehensive Income
 
 
 
 
 
 
 
Net Changes in Fair Value of Cash Flow Hedges:
 
 
 
494

 
878

 
net of income tax expense of $321 and $574
 
 
 
 
 
 
 
net of income tax expense of $667 and $952
975

 
1,456

 
 
 
 
 
 
 
 
 
 
 
 
SERP Benefit Amortization:
 
 
 
25

 
68

 
net of income tax expense of $15 and $43
 
 
 
 
 
 
 
net of income tax expense of $30 and $85
49

 
137

519

 
946

 
Total Other Comprehensive Income, Net of Tax
1,024

 
1,593

$
39,244

 
$
31,733

 
Total Comprehensive Income
$
48,921

 
$
33,859

See Notes to Condensed Consolidated Financial Statements.


8




TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Six Months Ended
 
June 30,
 
2014
 
2013
 
(Unaudited)
 
Thousands of Dollars
Cash Flows from Operating Activities
 
 
 
Cash Receipts from Electric Retail Sales
$
444,624

 
$
435,779

Cash Receipts from Electric Wholesale Sales
86,087

 
75,803

Cash Receipts from Operating Springerville Units 3 & 4
47,099

 
49,974

Reimbursement of Affiliate Charges
13,633

 
12,695

Cash Receipts from Gas Wholesale Sales
46

 
3,145

Income Tax Refunds Received
9

 

Interest Received
5

 
509

Other Cash Receipts
19,580

 
13,320

Payment of Operations and Maintenance Costs
(134,606
)
 
(117,133
)
Fuel Costs Paid
(134,374
)
 
(139,596
)
Taxes Other Than Income Taxes Paid, Net of Amounts Capitalized
(66,588
)
 
(68,574
)
Wages Paid, Net of Amounts Capitalized
(60,845
)
 
(57,483
)
Purchased Power Costs Paid
(59,088
)
 
(40,949
)
Interest Paid, Net of Amounts Capitalized
(24,588
)
 
(27,590
)
Capital Lease Interest Paid
(15,888
)
 
(18,630
)
Other Cash Payments
(2,064
)
 
(5,728
)
Net Cash Flows—Operating Activities
113,042

 
115,542

Cash Flows from Investing Activities
 
 
 
Capital Expenditures
(157,161
)
 
(118,210
)
Return of Investments in Springerville Lease Debt

 
9,104

Other, net
(3,460
)
 
(3,470
)
Net Cash Flows—Investing Activities
(160,621
)
 
(112,576
)
Cash Flows from Financing Activities
 
 
 
Proceeds from Borrowings Under Revolving Credit Facility
105,000

 
78,000

Repayments of Borrowings Under Revolving Credit Facility
(105,000
)
 
(48,000
)
Proceeds from Issuance of Long-Term Debt
149,168

 

Payments of Capital Lease Obligations
(83,204
)
 
(84,206
)
Payment of Debt Issue/Retirement Costs
(1,641
)
 
(982
)
Other, net
656

 
596

Net Cash Flows—Financing Activities
64,979

 
(54,592
)
Net Increase (Decrease) in Cash and Cash Equivalents
17,400

 
(51,626
)
Cash and Cash Equivalents, Beginning of Year
25,335

 
79,743

Cash and Cash Equivalents, End of Period
$
42,735

 
$
28,117

See Note 11 for supplemental cash flow information.
See Notes to Condensed Consolidated Financial Statements.

9




TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
 
 
June 30,
 
December 31,
 
2014
 
2013
 
(Unaudited)
 
Thousands of Dollars
ASSETS
 
 
 
Utility Plant
 
 
 
Plant in Service
$
4,644,399

 
$
4,467,667

Utility Plant Under Capital Leases
747,158

 
637,957

Construction Work in Progress
169,459

 
180,485

Total Utility Plant
5,561,016

 
5,286,109

Less Accumulated Depreciation and Amortization
(1,913,655
)
 
(1,826,977
)
Less Accumulated Amortization of Capital Lease Assets
(525,327
)
 
(514,677
)
Total Utility Plant—Net
3,122,034

 
2,944,455

Investments and Other Property
 
 
 
Investments in Lease Equity
36,122

 
36,194

Other
34,192

 
33,488

Total Investments and Other Property
70,314

 
69,682

Current Assets
 
 
 
Cash and Cash Equivalents
42,735

 
25,335

Accounts Receivable—Customer
96,513

 
80,211

Unbilled Accounts Receivable
56,252

 
34,369

Allowance for Doubtful Accounts
(4,977
)
 
(4,825
)
Accounts Receivable—Due from Affiliates
2,818

 
6,064

Materials and Supplies
79,409

 
75,200

Deferred Income Taxes—Current
91,585

 
70,722

Fuel Inventory
43,754

 
44,027

Regulatory Assets—Current
59,091

 
42,555

Derivative Instruments
4,289

 
2,137

Other
14,864

 
12,923

Total Current Assets
486,333

 
388,718

Regulatory and Other Assets
 
 
 
Regulatory Assets—Noncurrent
152,259

 
141,030

Derivative Instruments
493

 
167

Other Assets
21,093

 
19,233

Total Regulatory and Other Assets
173,845

 
160,430

Total Assets
$
3,852,526

 
$
3,563,285

See Notes to Condensed Consolidated Financial Statements.
(Continued)

10




TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
 
 
June 30,
 
December 31,
 
2014
 
2013
 
(Unaudited)
 
Thousands of Dollars
CAPITALIZATION AND OTHER LIABILITIES
 
 
 
Capitalization
 
 
 
Common Stock Equity
$
974,844

 
$
925,923

Capital Lease Obligations
69,938

 
131,370

Long-Term Debt
1,372,323

 
1,223,070

Total Capitalization
2,417,105

 
2,280,363

Current Liabilities
 
 
 
Current Obligations Under Capital Leases
272,939

 
186,056

Accounts Payable—Trade
89,162

 
88,556

Accounts Payable—Due to Affiliates
5,282

 
9,153

Accrued Taxes Other than Income Taxes
39,732

 
34,485

Accrued Employee Expenses
19,726

 
24,454

Regulatory Liabilities—Current
28,075

 
23,701

Accrued Interest
24,651

 
22,785

Customer Deposits
20,906

 
21,354

Derivative Instruments
4,261

 
5,531

Other
13,641

 
9,244

Total Current Liabilities
518,375

 
425,319

Deferred Credits and Other Liabilities
 
 
 
Deferred Income Taxes—Noncurrent
464,983

 
428,103

Regulatory Liabilities—Noncurrent
283,475

 
263,270

Pension and Other Retiree Benefits
84,724

 
84,936

Derivative Instruments
4,907

 
5,161

Other
78,957

 
76,133

Total Deferred Credits and Other Liabilities
917,046

 
857,603

Commitments, Contingencies, and Environmental Matters (Note 6)

 

Total Capitalization and Other Liabilities
$
3,852,526

 
$
3,563,285


See Notes to Condensed Consolidated Financial Statements.

(Concluded)


11




TUCSON ELECTRIC POWER COMPANY
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY
 
 
Common
Stock
 
Capital
Stock
Expense
 
Retained 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
 
 
 
 
47,897

 
 
 
47,897

Other Comprehensive Income, net of tax
 
 
 
 
 
 
1,024

 
1,024

Balances at June 30, 2014
$
888,971

 
$
(6,357
)
 
$
97,082

 
$
(4,852
)
 
$
974,844

See Notes to Condensed Consolidated Financial Statements.


12

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



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) (collectively Regulated Utilities). 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 2013 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 and TEP revised their December 31, 2013 balance sheets to correct an error in the classification of capital lease obligations and related deferred income taxes. The correction increased current capital lease obligations and decreased noncurrent capital lease obligations by $18 million and increased current deferred tax assets and noncurrent deferred tax liabilities by $7 million. We do not believe the misclassification was material to the previously issued financial statements.
RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
In 2014, we adopted accounting guidance that:
requires an entity to 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. The adoption of this guidance did not have a material impact on our disclosures, 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 entered into an Agreement and Plan of Merger (Merger), subject to shareholder and required regulatory approvals, to be acquired by Fortis Inc. (Fortis) for $60.25 per share of Common Stock in cash. Following the Merger, UNS Energy will continue as a wholly owned subsidiary of Fortis. The Boards of Directors of each of UNS Energy and Fortis have approved the Merger.
The following additional approvals have been received:
In March 2014, UNS Energy's shareholders approved the Merger;
In April 2014, the Federal Energy Regulatory Commission (FERC) approved the Merger;
In May 2014, the Committee on Foreign Investment in the United States concluded its review determining there are no unresolved national security concerns with respect to the Merger;
In June 2014, the United States Federal Trade Commission granted UNS Energy's request for early termination of the waiting period with respect to the Merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; and

13

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



In July 2014, the Federal Communications Commission approved UNS Energy’s FCC license transfer of control applications with respect to the Merger.
The final regulatory approval necessary to complete the Merger is approval by the Arizona Corporation Commission (ACC). In May 2014, UNS Energy, Fortis, ACC Staff, the Residential Utility Consumer Office, and other parties to the Merger proceedings entered into a settlement (Settlement) in which the parties agree that the Merger is in the public interest and recommend approval by the ACC, subject to certain conditions. Those conditions include, but are not limited to, the following:
UNS Energy shall provide credits on the Regulated Utilities retail customers' bills totaling $30 million over five years; $10 million in year one and $5 million annually in years two through five. The monthly bill credits will be applied each year from October through March. If the Merger closes by the end of September 2014, the bill credits will commence on October 1, 2014;
UNS Energy and the Regulated Utilities will adopt certain ring-fencing and corporate governance provisions;
Dividends paid from the Regulated Utilities to UNS Energy cannot exceed 60 percent of the Regulated Utilities’ respective annual net income for a period of five years or until such time that their respective equity capitalization reaches 50 percent of total capital (excluding any goodwill recorded) as accounted for in accordance with GAAP. The ratios used to determine the dividend restrictions will be calculated for each calendar year and reported to the ACC annually beginning on April 1, 2016. The dividend restrictions were contingent upon receiving necessary consents of the lenders in UNS Energy’s credit facility, which consents were obtained in June 2014; and
Fortis shall make an equity investment totaling $220 million through UNS Energy into the Regulated Utilities following closing of the Merger. However, if the Merger closes after September 30, 2014, the equity investment may be made into UNS Energy to retire debt.
The Settlement is subject to the review and approval of the ACC, which could approve, reject, or require modifications to the Settlement as a condition of approval of the Merger. Hearings before an ACC administrative law judge on the Settlement concluded on June 17, 2014. The Settlement requests that the ACC issue an order approving the Settlement no later than September 18, 2014.
The completion of the Merger is also subject to the absence of any injunction, order, or other law prohibiting the Merger.
If the Merger is approved by the ACC in September 2014 as requested by the parties to the Settlement Agreement, we expect the Merger to close by the end of September 2014. Upon completion of the Merger, UNS Energy expects to record approximately $19 million of merger-related expenses including investment banker fees, legal fees, and accelerated expenses for certain share-based compensation awards. TEP would record approximately $15 million as its allocated share of these merger-related expenses. See Note 9.

NOTE 3. REGULATORY MATTERS
The ACC and the FERC each regulate portions of the utility accounting practices and rates of the Regulated Utilities.
The ACC regulates rates charged to retail customers, the siting of generation and transmission facilities, the issuance of securities, transactions with affiliated parties, and other utility matters. The ACC also enacts other regulations and policies that can affect business decisions and accounting practices. The FERC regulates terms and prices of transmission services and wholesale electricity sales. The Merger with Fortis is subject to approval by the ACC. See Note 2. Additionally, the purchase of Gila River Generating Station Unit 3 (Gila River Unit 3) remains subject to FERC approval. See Note 7.
COST RECOVERY MECHANISMS
TEP Purchased Power and Fuel Adjustment Clause
In April 2014, the ACC approved a 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 0.14 cents per kWh for the period July 2013 through April 2014.
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 2013 TEP Rate Order required TEP to defer incremental fuel costs of $10 million from recovery under the PPFAC pending final resolution of an insurance claim by the San Juan Coal Company and distribution of insurance proceeds to San Juan participants. At June 30, 2014, TEP has received

14

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



insurance settlement proceeds of $8 million. The proceeds offset the deferred costs and are reflected in our cash flow statements as an other operating cash receipt. TEP expects to recover any remaining fuel costs, not reimbursed by insurance, through its PPFAC.
TEP Environmental Compliance Adjustor
The 2013 TEP Rate Order provided an Environmental Compliance Adjustor (ECA) to recover the return on and of qualified investments, to comply with environmental standards required by federal or other governmental agencies. The ECA rate of 0.0049 cents per kWh became effective on May 1, 2014. TEP expects to recognize ECA revenues of less than $1 million in 2014.
UNS Electric Transmission Cost Adjustor
The 2013 UNS Electric Rate Order provided a Transmission Cost Adjustor (TCA) that allows more timely recovery of transmission costs associated with serving retail customers. The TCA rate is adjusted annually based on information filed with the ACC each May. The TCA rate of 0.114 cents per kWh became effective in June 2014.
UNS Gas Purchased Gas Adjustor
In November of 2013, a Purchased Gas Adjustor (PGA) credit of 10 cents per therm became effective for UNS Gas. The credit expired in April 2014.
Energy Efficiency Standards
The Regulated Utilities are required to implement 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 half of 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.
Lost Fixed Cost Recovery Mechanism
The Lost Fixed Cost Recovery (LFCR) mechanism provides recovery of certain non-fuel costs that 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 filed their first LFCR reports with the ACC in May 2014. TEP requested recovery of approximately $5 million and UNS Electric requested recovery of approximately $1 million. The LFCR rates are expected to go into effect in August 2014 for TEP and in September 2014 for UNS Electric.
TEP and UNS Electric recorded LFCR revenues of $6 million and $2 million, respectively, in the first six months of 2014 related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013 and 2014. We recognize LFCR revenue when verifiable regardless of when the lost retail kWh sales occur. LFCR revenue is included in Electric Retail Sales in the income statements.

NOTE 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 Electric, a regulated electric utility
(3)
UNS Gas, a regulated gas distribution utility

15

Table of Contents
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



We disclose selected financial data for our reportable segments in the following tables:
 
Reportable Segments
 
 
 
 
 
 
 
TEP
 
UNS Electric
 
UNS Gas
 
Other (2)
 
Reconciling
Adjustments
 
UNS
Energy
 
Millions of Dollars
Three Months Ended June 30, 2014
 
Operating Revenues-External
$
318

 
$
47

 
$
22

 
$

 
$

 
$
387

Operating Revenues-Intersegment(1)
4

 

 
1

 
4

 
(9
)
 

Income Before Income Taxes
61

 
6

 

 

 

 
67

Net Income
39

 
4

 

 
(1
)
 

 
42

 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30, 2013
 
 
 
 
 
 
 
 
 
 
 
Operating Revenues-External
$
300

 
$
44

 
$
21

 
$

 
$

 
$
365

Operating Revenues-Intersegment(1)
4

 

 
1

 
4

 
(9
)
 

Income Before Income Taxes
32

 
6

 

 

 

 
38

Net Income
31

 
4

 

 

 

 
35

 
Reportable Segments
 
 
 
 
 
 
 
TEP
 
UNS Electric
 
UNS Gas
 
Other (2)
 
Reconciling
Adjustments
 
UNS
Energy
 
Millions of Dollars
Six Months Ended June 30, 2014
 
 
 
 
 
 
 
 
 
 
 
Operating Revenues-External
$
569

 
87

 
64

 
$

 
$

 
$
720

Operating Revenues-Intersegment (1)
8

 
1

 
1

 
8

 
(18
)
 

Income Before Income Taxes
76

 
9

 
8

 
(1
)
 

 
92

Net Income
48

 
6

 
5

 
(1
)
 

 
58

 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2013
 
 
 
 
 
 
 
 
 
 
 
Operating Revenues-External
$
543

 
$
80

 
$
73

 
$
1

 
$

 
$
697

Operating Revenues-Intersegment (1)
9

 
1

 
1

 
8

 
(19
)
 

Income Before Income Taxes
35

 
9

 
13

 

 

 
57

Net Income
32

 
6

 
8

 

 

 
46

(1) 
Operating Revenues-Intersegment includes common costs (system, facilities, etc.) allocated to affiliates on a cost-causative basis and recorded as revenue by TEP, sales of power between TEP and UNS Electric at third-party market prices, 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.
(2) 
Other includes the 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.
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 recorded, in April of 2014, an increase to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases on its balance sheet in the amount of $109 million, which represented the present value of the total purchase commitment.

16

Table of Contents
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



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. No amounts have been recorded for these commitments from SRP and Tri-State at June 30, 2014.
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.
TEP CREDIT AGREEMENT
The TEP Credit Agreement consists of a $200 million revolving credit, revolving LOC facility and an $82 million LOC facility to support tax-exempt bonds. As of June 30, 2014, there is $184 million available under the revolving credit facility. The TEP Credit Agreement expires in November 2016. As of July 18, 2014, TEP had $134 million available under its revolving credit facility.
TEP provided, in the second quarter of 2014, a 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 is reduced by $15 million until the Gila River transaction closes and the LOC is terminated. See Note 7.
COVENANT COMPLIANCE
At June 30, 2014, we were in compliance with the terms of our loan and credit agreements.

NOTE 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 2013 Annual Report on Form 10-K, UNS Energy entered into the following long-term commitments through June 30, 2014:
 
UNS Energy Purchase Commitments
 
2014
 
2015
 
2016
 
2017
 
2018
 
Thereafter
 
Total
 
Millions of Dollars
Fuel, including Transportation
$

 
$
9

 
$
9

 
$
9

 
$
8

 
$
8

 
$
43

Purchased Power

 
23

 

 

 

 

 
23

Capital Lease Obligations(1)

 
120

 

 

 

 

 
120

   Total Purchase Commitments
$

 
$
152

 
$
9

 
$
9

 
$
8

 
$
8

 
$
186

TEP entered into the following long-term commitments:
 
TEP Purchase Commitments
 
2014
 
2015
 
2016
 
2017
 
2018
 
Thereafter
 
Total
 
Millions of Dollars
Fuel, Including Transportation
$

 
$
8

 
$
8

 
$
8

 
$
8

 
$
8

 
$
40

Purchased Power

 
15

 

 

 

 

 
15

Capital Lease Obligations(1)

 
120

 

 

 

 

 
120

   Total Purchase Commitments
$

 
$
143

 
$
8

 
$
8

 
$
8

 
$
8

 
$
175

(1) 
In April 2014, TEP entered into agreements to purchase certain Springerville Coal Handling Facilities leased interests. See Note 5.

17

Table of Contents
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



UNS ENERGY CONTINGENCIES
In May 2014, UNS Energy, Fortis, ACC Staff, the Residential Utility Consumer Office, and other parties to the Merger proceedings entered into a Settlement in which the Regulated Utilities agreed, contingent upon completion of the Merger, to provide credits on retail customers' bills totaling $30 million over five years. See Note 2.
TEP CONTINGENCIES
Planned Purchase of Gas-Fired Generation Facility
In 2013, TEP and UNS Electric entered into an 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 claims asserted by EarthJustice in the amended complaint. The joint participants have agreed to have the matter stayed until August 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. In December 2013, the coal supplier and Four Corners’ operating agent filed 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. The New Mexico Taxation and Revenue Department and APS started settlement negotiations in July 2014. 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 $44 million upon expiration of the coal supply agreements, which expire between 2017 and 2031. The reclamation liability (present value of future liability) recorded was $20 million at June 30, 2014 and $18 million at December 31, 2013.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



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.
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 and recovers the regulatory asset through the PPFAC as final mine reclamation costs are paid to the coal suppliers.
Discontinued Transmission Project
TEP and UNS Electric had initiated a project to jointly construct a 60-mile transmission line from Tucson, Arizona to Nogales, Arizona in response to an order by the ACC to UNS Electric to improve the reliability of electric service in Nogales. TEP and UNS Electric will 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. TEP and UNS Electric plan to keep the path approved in the line siting matter in contemplation of using a greater part of the route to serve future customers and to address reliability needs. 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. In 2012, TEP wrote off $5 million of the capitalized costs believed not probable of recovery and recorded a regulatory asset of $5 million for the balance deemed probable of recovery.
Performance 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. As of June 30, 2014, there have been no such payment defaults under any of the remote generating station agreements. TEP's joint participation agreements expire in 2016 through 2046.
UNS ELECTRIC CONTINGENCIES
Planned Purchase of Gas-Fired Generation Facility
In 2013, TEP and UNS Electric entered into an agreement to purchase a gas-fired generation facility. See Note 7.
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
In February 2012, the EPA issued final rules for the control of mercury emissions and other hazardous air pollutants from power plants. Based on the EPA's final Mercury and Air Toxics (MATS) rules, additional emission control equipment will be required by April 2015. TEP has received an extension until April 2016 to comply with the MATS rules at Springerville. The operator of Navajo has also received an extension until April 2016. TEP's share of the estimated costs to comply with the MATS rules include the following:
Estimated Mercury Emissions Control Costs:
Navajo
 
Four Corners
 
Springerville(1)
 
Millions of Dollars
Capital Expenditures
$
1

 
$
1

 
$
5

Annual O&M Expenses
1

 
1

 
1


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



(1)
Total capital expenditures and annual O&M expenses represent amounts for both Springerville Units 1 & 2, with estimated costs split equally between the two units. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributable to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2.
TEP expects Sundt and San Juan's current emission controls to be adequate to comply with the EPA's MATS rules.
Regional Haze Rules
The EPA's Regional Haze Rules require emission controls known as Best Available Retrofit Technology (BART) for certain industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving 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; 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 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. BART provisions of Regional Haze Rules requiring emission control upgrades do not apply to Springerville because the BART rules apply to plants built prior to Springerville. TEP cannot predict the ultimate outcome of these matters.
TEP's estimated costs involved in meeting these rules are:
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

(1)
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 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. Estimated costs for SNCR are reflected in the table above. The State of New Mexico has submitted this plan to the EPA and the EPA has proposed to approve the alternative state plan which would replace the existing FIP. TEP expects the EPA will reach a final decision in 2014. TEP owns 50% of San Juan Unit 2. At June 30, 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.
(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 2018. TEP owns 7% of Four Corners Units 4 and 5.
(4) In June 2014, the EPA issued a final rule that would require TEP to either (i) install SNCR and dry sorbent injection technology on Unit 4 by mid-2017 or (ii) eliminate the use of coal by the end of 2017 as a better-than-BART alternative. TEP is required to notify the EPA of its decision by March 2017. At June 30, 2014, the net book value of the Sundt coal handling facilities was $27 million. If the coal handling facilities are retired early, TEP expects to request ACC approval to recover, over a reasonable time period, all the remaining costs of the coal handling facilities.


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



NOTE 7. PLANNED PURCHASE OF GAS-FIRED GENERATION FACILITY
In December 2013, TEP and UNS Electric entered into a purchase agreement with a subsidiary of Entegra to purchase Gila River Unit 3 for $219 million, subject to certain closing adjustments. Gila River Unit 3, a gas-fired combined cycle unit with a nominal capacity rating of 550 MW, is located in Gila Bend, Arizona. TEP expects to purchase a 75% undivided interest in Gila River Unit 3 (413 MW) for approximately $164 million, and UNS Electric expects to purchase the remaining 25% undivided interest (137 MW) for approximately $55 million. TEP and UNS Electric expect the transaction to close in December 2014, subject to FERC approval and other closing conditions.
In December 2013, UNS Electric filed an application 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. The application is still pending before the ACC.
In June 2014, TEP provided a letter of credit (LOC) for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. The seller is 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 and UNS Electric or the failure of TEP and UNS Electric to close the transaction when the closing conditions have been satisfied. Upon the close of the transaction, the LOC will be canceled.

NOTE 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 June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
Service Cost
$
2

 
$
3

 
$
1

 
$
1

Interest Cost
5

 
4

 

 
1

Expected Return on Plan Assets
(5
)
 
(5
)
 

 

Actuarial Loss Amortization
1

 
2

 

 

Net Periodic Benefit Cost
$
3

 
$
4

 
$
1

 
$
2


 
Pension Benefits
 
Other Retiree Benefits
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
Service Cost
$
5

 
$
6

 
$
2

 
$
2

Interest Cost
9

 
8

 
1

 
1

Expected Return on Plan Assets
(11
)
 
(10
)
 

 

Actuarial Loss Amortization
2

 
4

 

 

Net Periodic Benefit Cost
$
5

 
$
8

 
$
3

 
$
3



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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



NOTE 9. SHARE-BASED COMPENSATION PLANS
RESTRICTED STOCK UNITS
In May 2014, the UNS Energy Compensation Committee (Compensation Committee) granted 7,486 restricted stock units to non-employee directors at a grant date fair value, based on the grant date closing share price, of $60.11 per share. We recognize compensation expense equal to the fair value on the grant date over the one-year vesting period. We issue UNS Energy Common Stock (Common Stock) for the vested restricted stock units at the time elected by each of the non-employee directors based on certain eligibility requirements. These restricted stock units accrue dividend equivalents during and subsequent to the vesting period, which are distributed in shares of Common Stock at the same time as the related restricted stock units.
In February 2014, the Compensation Committee granted 16,910 restricted stock units to certain management employees at a grant date fair value, based on the grant date closing share price, of $60.39 per share. The restricted stock units vest on the third anniversary of grant and are distributed in shares of 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.
PERFORMANCE SHARES
In February 2014, the Compensation Committee granted 33,820 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 $57.47 per share. Those awards will be paid out in Common Stock based on UNS Energy’s compound annualized total shareholder return relative to the companies included in the Edison Electric Institute Utility Index for the three-year performance period ended December 31, 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 $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, 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 share-based compensation expense of less than $1 million for the three months ended June 30, 2014 and June 30, 2013. For the six months ended June 30, 2014, UNS Energy recorded share-based compensation expense of $2 million, $1 million of which related to TEP. For the six months ended June 30, 2013, UNS Energy and TEP recorded share-based compensation expense of $1 million.
At June 30, 2014, the total unrecognized compensation cost related to non-vested share-based compensation was $5 million, of which $4 million are allocable to TEP, which will be recorded as compensation expense over the remaining vesting periods through February 2017. The completion of the Merger would result in accelerated vesting and expense recognition for these awards. See Note 2. At June 30, 2014, less than 0.5 million shares were awarded but not yet issued, including target performance shares, under the share-based compensation plans.


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



NOTE 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 were exercised or converted into Common Stock. We excluded anti-dilutive contingently issuable shares from the calculation of diluted EPS.
The following table illustrates the effect of dilutive securities on net income and weighted average Common Stock outstanding:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Thousands of Dollars
Numerator: Net Income
$
42,354

 
$
34,618

 
$
57,829

 
$
45,963

 
 
 
 
 
 
 
 
 
Thousands of Shares
Denominator:
 
 
 
 
 
Weighted Average Shares of Common Stock Outstanding:
 
 
 
 
 
 
 
Common Shares Issued
41,659

 
41,427

 
41,639

 
41,404

Fully Vested Deferred Stock Units
122

 
171

 
120

 
165

Total Weighted Average Common Stock Outstanding — Basic
41,781

 
41,598

 
41,759

 
41,569

Effect of Dilutive Securities:
 
 
 
 
 
 
 
Options and Stock Issuable Under Share-Based Compensation Plans
364

 
323

 
356

 
329

Total Weighted Average Common Stock Outstanding — Diluted
42,145

 
41,921

 
42,115

 
41,898

For the six months ended June 30, 2013, we excluded 12,000 contingently issuable shares from our diluted EPS computation as their effect would be anti-dilutive.
 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



NOTE 11. SUPPLEMENTAL CASH FLOW INFORMATION
A reconciliation of Net Income to Net Cash Flows from Operating Activities follows:
 
UNS Energy
 
Six Months Ended June 30,
 
2014
 
2013
 
Thousands of Dollars
Net Income
$
57,829

 
$
45,963

Adjustments to Reconcile Net Income
 
 
 
       To Net Cash Flows from Operating Activities
 
 
 
Depreciation Expense
78,644

 
72,970

Amortization Expense
12,631

 
16,408

Depreciation and Amortization Recorded to Fuel and O&M Expense
3,977

 
3,516

Amortization of Deferred Debt-Related Costs included in Interest Expense
1,584

 
1,515

Provision for Retail Customer Bad Debts
1,194

 
936

Use of Renewable Energy Credits for Compliance
11,313

 
8,106

Deferred Income Taxes
36,320

 
36,644

Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset

 
(11,039
)
Pension and Retiree Expense
7,884

 
11,391

Pension and Retiree Funding
(5,974
)
 
(8,924
)
Share-Based Compensation Expense
1,859

 
1,390

Allowance for Equity Funds Used During Construction
(4,038
)
 
(2,463
)
LFCR Revenue
(7,654
)
 

Decrease to Reflect PPFAC/PGA Recovery
(21,437
)
 
(3,294
)
PPFAC Reduction - 2013 TEP Rate Order

 
3,000

Changes in Assets and Liabilities which Provided (Used)
 
 
 
Cash Exclusive of Changes Shown Separately
 
 
 
Accounts Receivable
(22,766
)
 
(20,706
)
Materials and Fuel Inventory
(4,413
)
 
8,777

Accounts Payable
(5,875
)
 
(9,576
)
Income Taxes
(88
)
 
(15,980
)
Interest Accrued
1,305

 
(6,885
)
Taxes Other Than Income Taxes
3,721

 
490

Other
(8,259
)
 
15,413

Net Cash Flows – Operating Activities
$
137,757

 
$
147,652



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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



 
TEP
 
Six Months Ended June 30,
 
2014
 
2013
 
Thousands of Dollars
Net Income
$
47,897

 
$
32,266

Adjustments to Reconcile Net Income
 
 
 
To Net Cash Flows from Operating Activities
 
 
 
Depreciation Expense
61,891

 
57,418

Amortization Expense
14,476

 
18,275

Depreciation and Amortization Recorded to Fuel and O&M Expense
3,406

 
2,987

Amortization of Deferred Debt-Related Costs Included in Interest Expense
1,285

 
1,216

Provision for Retail Customer Bad Debts
833

 
711

Use of Renewable Energy Credits for Compliance
9,884

 
7,414

Deferred Income Taxes
29,641

 
24,883

Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset

 
(10,751
)
Pension and Retiree Expense
6,824

 
9,939

Pension and Retiree Funding
(5,522
)
 
(8,493
)
Share-Based Compensation Expense
1,496

 
1,108

Allowance for Equity Funds Used During Construction
(3,524
)
 
(1,763
)
LFCR Revenue
(6,121
)
 

Increase (Decrease) to Reflect PPFAC Recovery
(14,791
)
 
2,914

PPFAC Reduction - 2013 TEP Rate Order

 
3,000

Changes in Assets and Liabilities which Provided (Used)
 
 
 
Cash Exclusive of Changes Shown Separately
 
 
 
Accounts Receivable
(35,498
)
 
(30,452
)
Materials and Fuel Inventory
(3,936
)
 
8,923

Accounts Payable
6,019

 
(11
)
Income Taxes
(6
)
 
(10,798
)
Interest Accrued
1,320

 
(6,886
)
Taxes Other Than Income Taxes
5,247

 
2,295

Other
(7,779
)
 
11,347

Net Cash Flows – Operating Activities
$
113,042

 
$
115,542

NON-CASH TRANSACTIONS
In April 2014, TEP recorded an increase of $109 million to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases due to TEP's commitment to purchase lease interests in April 2015. See Note 5.
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.

NOTE 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. Transfers between levels are recorded at the end of a reporting period. There were no transfers between levels in the periods presented.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



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
 
June 30, 2014
 
Millions of Dollars
Assets
 
 
 
Cash Equivalents(1)
$
13

 
$
13

 
$

 
$

 
$

 
$
13

Restricted Cash(1)
2

 
2

 

 

 

 
2

Rabbi Trust Investments(2)
23

 

 
23

 

 

 
23

Energy Contracts - Regulatory Recovery(3)
11

 

 
5

 
6

 
(3
)
 
8

Total Assets
49

 
15

 
28

 
6

 
(3
)
 
46

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Energy Contracts - Regulatory Recovery(3)
(5
)
 

 
(1
)
 
(4
)
 
3

 
(2
)
Energy Contracts - Cash Flow Hedge(3)
(1
)
 

 

 
(1
)
 

 
(1
)
Interest Rate Swaps(4)
(6
)
 

 
(6
)
 

 

 
(6
)
Total Liabilities
(12
)
 

 
(7
)
 
(5
)
 
3

 
(9
)
Net Total Assets (Liabilities)
$
37

 
$
15

 
$
21

 
$
1

 
$

 
$
37

 
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


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



 
TEP
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Counterparty Netting of Energy Contracts Not Offset on the Balance Sheets(5)
 
Net Amount
 
June 30, 2014
 
Millions of Dollars
Assets
 
 
 
Cash Equivalents(1)
$

 
$

 
$

 
$

 
$

 
$

Restricted Cash(1)
2

 
2

 

 

 

 
2

Rabbi Trust Investments(2)
23

 

 
23

 

 

 
23

Energy Contracts - Regulatory Recovery(3)
5

 

 
2

 
3

 
(2
)
 
3

Total Assets
30

 
2

 
25

 
3

 
(2
)
 
28

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Energy Contracts - Regulatory Recovery(3)
(3
)
 

 
(1
)
 
(2
)
 
2

 
(1
)
Energy Contracts - Cash Flow Hedge(3)
(1
)
 

 

 
(1
)
 

 
(1
)
Interest Rate Swaps(4)
(6
)
 

 
(6
)
 

 

 
(6
)
Total Liabilities
(10
)
 

 
(7
)
 
(3
)
 
2

 
(8
)
Net Total Assets (Liabilities)
$
20

 
$
2

 
$
18

 
$

 
$

 
$
20

 
TEP
 
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)
$

 
$

 
$

 
$

 
$

 
$

Restricted Cash(1)
2

 
2

 

 

 

 
2

Rabbi Trust Investments(2)
22

 

 
22

 

 

 
22

Energy Contracts - Regulatory Recovery(3)
2

 

 
1

 
1

 
(1
)
 
1

Total Assets
26

 
2

 
23

 
1

 
(1
)
 
25

Liabilities
 
 
 
 
 
 
 
 
 
 
 
Energy Contracts - Regulatory Recovery(3)
(2
)
 

 

 
(2
)
 
1

 
(1
)
Energy Contracts - Cash Flow Hedge(3)
(1
)
 

 

 
(1
)
 

 
(1
)
Interest Rate Swaps(4)
(7
)
 

 
(7
)
 

 

 
(7
)
Total Liabilities
(10
)
 

 
(7
)
 
(3
)
 
1

 
(9
)
Net Total Assets (Liabilities)
$
16

 
$
2

 
$
16

 
$
(2
)
 
$

 
$
16

(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) entered into to reduce exposure to energy price risk. These contracts are included in Derivative Instruments on the balance sheets. The valuation techniques are described below.
(4)
Interest Rate Swaps are valued based on the 3-month or 6-month London Interbank Offered Rate (LIBOR) 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.

27

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



DERIVATIVE INSTRUMENTS
We enter into various derivative and non-derivative contracts to reduce our exposure to energy price risk associated with our gas and purchased power requirements. 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.
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. In the first half of 2013, we also used this pricing model to value our power 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 price curves monthly.
Cash Flow Hedges
We enter into interest rate swaps to mitigate the exposure to volatility in variable interest rates on debt. The 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. The 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 14. The loss expected to be reclassified to earnings within the next twelve months is estimated to be $3 million for UNS Energy and 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 June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities
$
1

 
$
(9
)
 
$
2

 
$
(3
)
 
UNS Energy
 
TEP
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
Unrealized Net Gain (Loss) Recorded to Regulatory Assets/Liabilities
$
5

 
$

 
$
2

 
$
(1
)

28

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



Realized gains and losses on settled contracts are fully recoverable through the PPFAC or PGA. At June 30, 2014, UNS Energy and TEP have energy contracts that will settle through the second quarter of 2017.
Derivative Volumes
The volumes associated with our energy contracts were as follows:
 
UNS Energy
 
TEP
 
June 30, 2014
 
December 31, 2013
 
June 30, 2014
 
December 31, 2013
Power Contracts GWh
1,933

 
1,583

 
976

 
779

Gas Contracts GBtu
63,546

 
33,371

 
27,176

 
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 
 
 
 
 
 
 
 
 
 
June 30, 2014
 
 
 
Range of
 
Valuation Approach
 
Assets
 
Liabilities
 
Unobservable Inputs
 
Unobservable Input
 
 
 
Millions of Dollars
 
 
 
 
 
 
Forward Contracts(1)
Market approach
 
$
4

 
$
(4
)
 
Market price per MWh
 
$
23.90

-
$
57.90


 
 
 
 
 
 
 
 
 
 
 
Option Contracts(2)
Option model
 
2

 
(1
)
 
Market price per MMbtu
 
$
3.87

-
$
4.57


 
 
 
 
 
 
Gas volatility
 
21.01
%
-
32.10
%
Level 3 Energy Contracts
 
 
$
6

 
$
(5
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fair Value at 
 
 
 
 
 
 
 
 
 
December 31, 2013
 
 
 
Range of
 
Valuation Approach
 
Assets
 
Liabilities
 
Unobservable Inputs
 
Unobservable Input
 
 
 
Millions of Dollars
 
 
 
 
 
 
Forward Contracts(3)
Market approach
 
$
1

 
$
(4
)
 
Market price per MWh
 
$
26.54

-
$
51.75

 
 
 
 
 
 
 
 
 
 
 
 
Option Contracts(4)
Option model
 
3

 
(2
)
 
Market price per MMbtu
 
$
3.87

-
$
4.32

 
 
 
 
 
 
 
Gas volatility
 
25.05
%
-
35.07
%
Level 3 Energy Contracts
 
 
$
4

 
$
(6
)
 
 
 
 
 
 
 
(1) 
TEP comprises $2 million of the forward contract assets and $2 million of the forward contract liabilities at June 30, 2014.
(2) 
TEP comprises $1 million of the option contract assets and $1 million of the option contract liabilities at June 30, 2014.
(3) 
TEP comprises $1 million of the forward contract assets and $3 million of the forward contract liabilities at December 31, 2013.
(4) 
TEP comprises less than $1 million of the option contract assets at December 31, 2013.
Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude of the change and the direction of the change for each input. The impact of changes to fair value, including changes from unobservable inputs, are subject to recovery or refund through the PPFAC or PGA mechanisms and are reported as a regulatory asset or regulatory liability, or as a component of other comprehensive income, rather than in the income statement.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



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:
 
UNS Energy
 
TEP
 
Three Months Ended June 30, 2014
 
Millions of Dollars
Balances at March 31, 2014
$

 
$
(2
)
Realized/Unrealized Gains/(Losses) Recorded to:
 
 
 
Net Regulatory Assets/Liabilities – Derivative Instruments
3

 
2

Settlements
(2
)
 

Balances at June 30, 2014
$
1

 
$

 
 
 
 
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period
$
3

 
$
3

 
UNS Energy
 
TEP
 
Six Months Ended June 30, 2014
 
Millions of Dollars
Balances at December 31, 2013
$
(2
)
 
$
(2
)
Realized/Unrealized Gains/(Losses) Recorded to:
 
 
 
Net Regulatory Assets/Liabilities – Derivative Instruments
5

 
1

Settlements
(2
)
 
1

Balances at June 30, 2014
$
1

 
$

 
 
 
 
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period
$
2

 
$
1

 
UNS Energy
 
TEP
 
Three Months Ended June 30, 2013
 
Millions of Dollars
Balances at March 31, 2013
$
(3
)
 
$
(1
)
Realized/Unrealized Gains/(Losses) Recorded to:
 
 
 
Net Regulatory Assets/Liabilities – Derivative Instruments
(2
)
 

Settlements

 

Balances at June 30, 2013
$
(5
)
 
$
(1
)
 
 
 
 
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period
$
(4
)
 
$

 
UNS Energy
 
TEP
 
Six Months Ended June 30, 2013
 
Millions of Dollars
Balances at December 31, 2012
$
(5
)
 
$

Realized/Unrealized Gains/(Losses) Recorded to:
 
 
 
Net Regulatory Assets/Liabilities – Derivative Instruments
(2
)
 
(1
)
Settlements
2

 

Balances at June 30, 2013
$
(5
)
 
$
(1
)
 
 
 
 
Total Gains/(Losses) Attributable to the Change in Unrealized Gains/(Losses) Relating to Assets/Liabilities Still Held at the End of the Period
$
(3
)
 
$
(1
)

30

Table of Contents
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



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 the Regulated Utilities; 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.
Material adverse changes could trigger credit risk-related contingent features. At June 30, 2014, the 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 $25 million for UNS Energy and $19 million for TEP. The additional collateral to be posted if credit-risk contingent features were triggered would be $25 million for UNS Energy and $19 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 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.
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:
 
 
 
June 30, 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
 
$
1,677

 
$
1,771

 
$
1,507

 
$
1,521

TEP
Level 2
 
1,372

 
1,435

 
1,223

 
1,214



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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



NOTE 13. 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 June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
Federal Income Tax Expense at Statutory Rate
$
24

 
$
14

 
$
22

 
$
12

State Income Tax Expense, Net of Federal Deduction
3

 
2

 
3

 
2

Federal/State Tax Credits
(2
)
 

 
(2
)
 

Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset

 
(11
)
 

 
(11
)
Other

 
(1
)
 

 
(1
)
Total Federal and State Income Tax Expense
$
25

 
$
4

 
$
23

 
$
2

 
UNS Energy
 
TEP
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
Federal Income Tax Expense at Statutory Rate
$
32

 
$
20

 
$
27

 
$
12

State Income Tax Expense, Net of Federal Deduction
4

 
3

 
3

 
2

Federal/State Tax Credits
(2
)
 

 
(2
)
 

Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset

 
(11
)
 

 
(11
)
Other
1

 
(1
)
 

 

Total Federal and State Income Tax Expense
$
35

 
$
11

 
$
28

 
$
3

Investment Tax Credit Basis Adjustment - Creation of Regulatory Asset
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.


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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



NOTE 14. RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME BY COMPONENT
The reclassifications from Accumulated Other Comprehensive Income (AOCI) by component are as follows:
 
 
UNS Energy
 
 
Details About Accumulated Other Comprehensive Income Components
 
Amount Reclassified from Other Comprehensive Income
 
Affected Line Item in the Income Statement
 
 
Three Months Ended June 30,
 
 
 
 
2014
 
2013
 
 
 
 
Thousands of Dollars
 
 
Realized Losses on Cash Flow Hedges
 
 
 
 
 
 
Interest Rate Swaps - Debt
 
$
(349
)
 
$
(346
)
 
Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases
 
(602
)
 
(604
)
 
Interest Expense Capital Leases
Commodity Contracts
 
(143
)
 
(191
)
 
Purchased Energy/Purchased Power
Tax Benefit
 
430

 
451

 
 
Realized Losses on Cash Flow Hedges, Net of Taxes
 
(664
)
 
(690
)
 
 
 
 
 
 
 
 
 
Amortization of SERP
 
 
 
 
 
 
Prior Service Cost and Net Loss
 
(40
)
 
(111
)
 
Operations and Maintenance
Tax Benefit
 
15

 
43

 
 
Amortization, Net of Taxes
 
(25
)
 
(68
)
 
 
 
 
 
 
 
 
 
Total Reclassifications from Other Comprehensive Income for the Period
 
$
(689
)
 
$
(758
)
 
 
 
 
UNS Energy
 
 
Details About Accumulated Other Comprehensive Income Components

Amount Reclassified from Other Comprehensive Income

Affected Line Item in the Income Statement


Six Months Ended June 30,


 
 
2014
 
2013
 
 


Thousands of Dollars


Realized Losses on Cash Flow Hedges






Interest Rate Swaps - Debt

$
(702
)
 
$
(676
)

Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases

(1,198
)
 
(1,208
)

Interest Expense Capital Leases
Commodity Contracts

(143
)
 
(191
)

Purchased Energy/Purchased Power
Tax Benefit

734

 
820



Realized Losses on Cash Flow Hedges, Net of Taxes

(1,309
)
 
(1,255
)




 
 
 


Amortization of SERP

 
 
 


Prior Service Cost and Net Loss

(79
)
 
(222
)

Operations and Maintenance
Tax Benefit

30

 
85



Amortization, Net of Taxes

(49
)
 
(137
)




 
 
 


Total Reclassifications from Other Comprehensive Income for the Period

$
(1,358
)
 
$
(1,392
)



33

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)



 
 
TEP
 
 
Details About Accumulated Other Comprehensive Income Components
 
Amount Reclassified from Other Comprehensive Income
 
Affected Line Item in the Income Statement
 
 
Three Months Ended June 30,
 
 
 
 
2014
 
2013
 
 
 
 
Thousands of Dollars
 
 
Realized Losses on Cash Flow Hedges
 
 
 
 
 
 
Interest Rate Swaps - Debt
 
$
(293
)
 
$
(293
)
 
Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases
 
(602
)
 
(604
)
 
Interest Expense Capital Leases
Commodity Contracts
 
(143
)
 
(191
)
 
Purchased Energy/Purchased Power
Tax Benefit
 
408

 
429

 
 
Realized Losses on Cash Flow Hedges, Net of Taxes
 
(630
)
 
(659
)
 
 
 
 
 
 
 
 
 
Amortization of SERP
 
 
 
 
 
 
Prior Service Cost and Net Loss
 
(40
)
 
(111
)
 
Other Expense
Tax Benefit
 
15

 
43

 
 
Amortization, Net of Taxes
 
(25
)
 
(68
)
 
 
 
 
 
 
 
 
 
Total Reclassifications from Other Comprehensive Income for the Period
 
$
(655
)
 
$
(727
)
 
 
 
 
TEP
 
 
Details About Accumulated Other Comprehensive Income Components
 
Amount Reclassified from Other Comprehensive Income
 
Affected Line Item in the Income Statement
 
 
Six Months Ended June 30,
 
 
 
 
2014
 
2013
 
 
 
 
Thousands of Dollars
 
 
Realized Losses on Cash Flow Hedges
 
 
 
 
 
 
Interest Rate Swaps - Debt
 
$
(591
)
 
$
(575
)
 
Interest Expense Long-Term Debt
Interest Rate Swaps - Capital Leases
 
(1,198
)
 
(1,208
)
 
Interest Expense Capital Leases
Commodity Contracts
 
(143
)
 
(191
)
 
Purchased Energy/Purchased Power
Tax Benefit
 
692

 
781

 
 
Realized Losses on Cash Flow Hedges, Net of Taxes
 
(1,240
)
 
(1,193
)
 
 
 
 
 
 
 
 
 
Amortization of SERP
 
 
 
 
 
 
Prior Service Cost and Net Loss
 
(79
)
 
(222
)
 
Other Expense
Tax Benefit
 
30

 
85

 
 
Amortization, Net of Taxes
 
(49
)
 
(137
)
 
 
 
 
 
 
 
 
 
Total Reclassifications from Other Comprehensive Income for the Period
 
$
(1,289
)
 
$
(1,330
)
 
 


34

Table of Contents
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Concluded)

NOTE 15. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In April 2014, the Financial Accounting Standards Board (FASB) issued an accounting standards update that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. This guidance will be effective in the first quarter of 2015. We do not expect the adoption of this guidance to have an impact on the presentation of our financial statements or our disclosures.
In May 2014, the FASB issued an accounting standards update that will eliminate the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. We will be required to adopt the new guidance retrospectively for annual and interim periods beginning January 1, 2017; early adoption is not permitted. We are evaluating the impact to our financial statements and disclosures.


35

Table of Contents

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 second quarter and first six months of 2014 compared with the same periods of 2013;
factors affecting our results and outlook;
liquidity, capital needs, capital resources, and contractual obligations;
dividends; and
critical accounting estimates.

UNS ENERGY CORPORATION
OVERVIEW OF CONSOLIDATED BUSINESS
UNS Energy is a utility services holding company engaged, through its 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, UniSource Energy Services, Inc. (UES), Millennium Energy Holdings, Inc. (Millennium), and UniSource Energy Development Company (UED).
TEP is a regulated utility and UNS Energy’s largest operating subsidiary, representing approximately 85% of UNS Energy’s total assets at June 30, 2014. TEP generates, transmits and distributes electricity to approximately 414,000 retail electric customers in a 1,155 square mile area in southeastern Arizona. 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 SRP.
UES holds the common stock of two regulated utilities, UNS Electric and UNS Gas. UNS Electric is a regulated utility which generates, transmits and distributes electricity to approximately 93,000 retail customers in Mohave and Santa Cruz 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.
UED and Millennium’s investments in unregulated businesses represent less than 1% of UNS Energy’s assets as of June 30, 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) with Fortis Inc. (Fortis). The Boards of Directors of each of UNS Energy and Fortis 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.
Approvals Received
The following approvals have been received:
In March 2014, UNS Energy's shareholders approved the Merger;
In April 2014, the FERC approved the Merger;

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Table of Contents

In May 2014, the Committee on Foreign Investment in the United States concluded its review determining there are no unresolved national security concerns with respect to the Merger;
In June 2014, the United States Federal Trade Commission granted UNS Energy's request for early termination of the waiting period with respect to the Merger under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended; and
In July 2014, the Federal Communications Commission approved UNS Energy’s FCC license transfer of control applications with respect to the Merger.
Pending ACC Approval
The final regulatory approval necessary to complete the Merger is approval by the ACC. In January 2014, UNS Energy and Fortis filed an application and supporting testimony with the ACC requesting approval of the Merger.
On May 16, 2014, UNS Energy, Fortis, ACC Staff, the Residential Utility Consumer Office, and other parties to the Merger proceedings entered into a settlement (Settlement) in which the parties agree that the Merger is in the public interest and recommend approval by the ACC, subject to certain conditions. Those conditions include, but are not limited to, the following:
UNS Energy shall provide credits on the Regulated Utilities retail customers' bills totaling $30 million over five years; $10 million in year one and $5 million annually in years two through five. The monthly bill credits will be applied each year from October through March. If the Merger closes by the end of September 2014, the bill credits will commence on October 1, 2014;
UNS Energy and the Regulated Utilities will adopt certain ring-fencing and corporate governance provisions;
Dividends paid from the Regulated Utilities to UNS Energy cannot exceed 60 percent of the Regulated Utilities’ respective annual net income for a period of five years or until such time that their respective equity capitalization reaches 50 percent of total capital (excluding any goodwill recorded) as accounted for in accordance with GAAP. The ratios used to determine the dividend restrictions will be calculated for each calendar year and reported to the ACC annually beginning on April 1, 2016. The dividend restrictions were contingent upon receiving necessary consents of the lenders in UNS Energy’s credit facility, which consents were obtained in June 2014; and
Fortis shall make an equity investment totaling $220 million through UNS Energy into the Regulated Utilities following closing of the Merger. However, if the Merger closes after September 30, 2014, the equity investment may be made into UNS Energy to retire debt.
The Settlement also requests that the ACC issue an order approving the Settlement no later than September 18, 2014. Hearings before an ACC administrative law judge on the Settlement concluded on June 17, 2014. The Settlement is subject to the review and approval of the ACC, which could approve, reject, or require modifications to the Settlement as a condition of approval of the Merger.
The completion of the Merger is also subject to the absence of any injunction, order, or other law prohibiting the Merger.
If the Merger is approved by the ACC in September 2014 as requested by the parties to the Settlement, we expect the Merger to close by the end of September 2014. Upon completion of the Merger, UNS Energy expects to record approximately $19 million of merger-related expenses including investment banker fees, legal fees, and accelerated expenses for certain share-based compensation awards. TEP would record approximately $15 million as its allocated share of these merger-related expenses. See Note 2 and Note 9.
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.
Completing 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 generation portfolio. 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.

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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.
Developing strategic responses to Arizona’s requirements for renewable energy, distributed generation, and energy efficiency that protect the financial stability of our business while providing benefits for 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 June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
TEP
$
39

 
$
31

 
$
48

 
$
32

UNS Electric
4

 
4

 
6

 
6

UNS Gas

 

 
5

 
8

Other Non-Reportable Segments and Adjustments (1)
(1
)
 

 
(1
)
 

Consolidated Net Income
$
42

 
$
35

 
$
58

 
$
46

(1) 
Includes: UNS Energy parent company expenses; Millennium; UED; and inter-company eliminations.
Executive Overview
Second quarter of 2014 compared with the second quarter of 2013
TEP
TEP reported net income of $39 million in the second quarter of 2014 compared with net income of $31 million in the same period last year. TEP's net income in the second quarter of 2013 included an income tax benefit of $11 million and a $3 million pre-tax charge recorded to fuel expense related to a credit to customers, both resulting from the 2013 TEP Rate Order.
TEP's pre-tax retail margin revenues increased by $22 million due to a Base Rate increase effective July 1, 2013, including $1 million of LFCR revenues related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013 (See Tucson Electric Power, Factors Affecting Results of Operations, 2013 TEP Rate Order and Note 3).
See Tucson Electric Power, Results of Operations.
UNS Electric
UNS Electric reported net income of $4 million in the second quarters of both 2014 and 2013. See UNS Electric, Results of Operations.
UNS Gas
UNS Gas reported no net income or loss in the second quarters of both 2014 and 2013. See UNS Gas, Results of Operations.

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Six months ended June 30, 2014 compared with the six months ended June 30, 2013
TEP
TEP reported net income of $48 million in the first six months of 2014 compared with net income of $32 million in the same period last year. TEP's net income in the first six months of 2013 included an income tax benefit of $11 million and $3 million recorded to fuel expense related to a credit to customers, both resulting from the 2013 TEP Rate Order.
TEP's pre-tax retail margin revenues increased by $34 million due to a Base Rate increase effective July 1, 2013, including $6 million of LFCR revenues related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013 and 2014 (See Tucson Electric Power, Factors Affecting Results of Operations, 2013 TEP Rate Order and Note 3).
See Tucson Electric Power, Results of Operations.
UNS Electric
UNS Electric reported net income of $6 million in both the first six months of 2014 and 2013. See UNS Electric, Results of Operations.
UNS Gas
UNS Gas reported net income of $5 million in the first six months of 2014 compared with net income of $8 million in the same period last year. The decrease in net income is due primarily to lower sales volumes resulting from mild winter weather, which contributed to a decline in retail margin revenues. See UNS Gas, Results of Operations.
Operations and Maintenance Expense
The table below summarizes the items included in UNS Energy’s Operations and Maintenance (O&M) expense. Base O&M in the first six months of 2014 includes merger-related expenses of $1 million.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
UNS Energy Base O&M (Non-GAAP)(1) 
$
68

 
$
71

 
$
141

 
$
141

Reimbursed Expenses Related to Springerville Units 3 and 4
17

 
16

 
31

 
30

Expenses Related to Customer-Funded Renewable Energy and DSM Programs(2)
7

 
8

 
13

 
14

Total UNS Energy O&M (GAAP)
$
92

 
$
95

 
$
185

 
$
185

(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.


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LIQUIDITY AND CAPITAL RESOURCES
UNS Energy Consolidated Liquidity
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 June 30, 2014
Cash and  Cash
Equivalents
 
Borrowings and LOCs issued under
Revolving Credit
Facility
 
Amount Available
under Revolving
Credit Facility
 
Millions of Dollars
UNS Energy Stand-Alone
$
2

 
$
75

 
$
50

TEP
43

 
16

 
184

UNS Electric(1)
4

 
23

 
47

UNS Gas(1)
18

 

 
70

Other(2)
3

 
N/A

 
N/A

Total
$
70

 
 
 
 
(1) 
Either UNS Gas or UNS Electric may borrow up to a maximum of $70 million; the total combined amount borrowed by both companies cannot exceed $100 million.
(2) 
Includes cash and cash equivalents at Millennium and UED.
In the second quarter of 2014, TEP provided a 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 is reduced by $15 million until the Gila River transaction closes and the LOC is terminated. See Tucson Electric Power, Factors Affecting Results of Operations, Gila River Generating Station Unit 3.
In July 2014, TEP made additional borrowings under its revolving credit facility to help fund scheduled capital lease payments. As of July 18, 2014, TEP had $134 million available under its revolving credit facility.
Dividends from UNS Energy’s subsidiaries represent the parent company’s main source of liquidity.
Dividends from Subsidiaries
UNS Energy received $10 million of dividends from UNS Gas in the first six months of 2014 and 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 June 30, 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 Electric/UNS Gas Revolver may be used for revolving borrowings as well as to issue LOCs. TEP, UNS Electric, and UNS Gas 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.

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UNS Energy Consolidated Cash Flows
 
Six Months Ended June 30,
 
2014
 
2013
 
Millions of Dollars
Operating Activities
$
138

 
$
148

Investing Activities
(190
)
 
(150
)
Financing Activities
47

 
(52
)
Net Increase (Decrease) in Cash
(5
)
 
(54
)
Beginning Cash
75

 
124

Ending Cash
$
70

 
$
70

UNS Energy’s operating cash flows are generated primarily by retail and wholesale energy sales at the Regulated Utilities, 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. The Regulated Utilities 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 Electric, and UNS Gas 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 six months of 2014, net cash flows from operating activities were $10 million lower than they were in the same period last year. The following items affected the year-over-year change in operating cash flows: a $13 million decrease in operating cash flows at UNS Gas due to lower retail therm sales and the return of the over-collected PGA balance to customers; and a $22 million increase in payments of operations and maintenance costs and wages paid due to generation maintenance, customer incentives related to renewable programs, and Merger costs; partially offset by a $7 million increase in cash receipts from retail and wholesale sales, net of fuel and purchased power, at TEP and UNS Electric due primarily to Base Rate increases; a $6 million increase in cash receipts due to insurance proceeds related to the San Juan mine fire; a $3 million decrease in interest paid, net of amounts capitalized, due to the replacement of higher cost debt with lower cost debt in 2013; a $3 million decrease in interest paid on capital lease obligations due to a decline in the balance of capital lease obligations; and a $4 million decrease in taxes paid, net of amounts capitalized, due to a decrease in sales tax rates effective in June 2013.
Investing Activities
Net cash flows used for investing activities increased $40 million in the first six months of 2014 compared with the same period last year due in part to a $30 million increase in capital expenditures and a $9 million decrease in the return of investment in Springerville lease debt. The increase in capital expenditures is due in part to maintenance on our generating facilities and the construction of new solar projects.
Financing Activities
Net cash flows from financing activities were $99 million higher in the first six months of 2014 when compared with the same period last year due to: the issuance of $150 million of long-term debt by TEP in March 2014; partially offset by a $44 million decrease in borrowings (net of repayments) under the revolving credit facilities; and a $4 million increase in dividends paid on Common Stock.
UNS Credit Agreement
The UNS Credit Agreement, which expires in November 2016, consists of a $125 million revolving credit and LOC facility. At June 30, 2014, there was $75 million outstanding at a weighted-average interest rate of 1.40%. 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.

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If the Merger is approved by the ACC, dividends paid from the Regulated Utilities to UNS Energy cannot exceed 60 percent of the Regulated Utilities’ respective annual net income for a period of five years or until such time that their respective equity capitalization reaches 50 percent of total capital (excluding any goodwill recorded) as accounted for in accordance with U.S. Generally Accepted Accounting Principles.
The dividend restrictions were contingent upon receiving necessary consents of the lenders in UNS Energy’s credit facility, which consents were obtained in June 2014.
At June 30, 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.
Contractual Obligations
There are no changes in our 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:
In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. See Note 5.
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. 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 $23 million in 2015. See Note 6.
We entered into new forward energy commitments with minimum payment obligations of $9 million in 2015 through 2017 and $8 million in each of 2018 and 2019. See Note 6.
Dividends on Common Stock
In first six months of 2014, UNS Energy paid dividends on Common Stock of $40 million. The following table shows the dividends declared to UNS Energy shareholders for 2014:
Declaration Date
Record Date
 
Payment Date
 
Dividend Amount Per
Share  of Common Stock
February 24, 2014
March 13, 2014
 
March 25, 2014
 
$
0.48

May 1, 2014
June 6, 2014
 
June 26, 2014
 
$
0.48

The Merger permits UNS Energy to pay quarterly dividends of up to $0.48 per share of common stock during 2014. The Merger also permits a stub period dividend to shareholders of record at the close of the Merger equal to the product of (i) the number of days from the record date of the most recent dividend payment and the effective time of the close of the Merger and (ii) the daily dividend rate. The daily dividend rate is determined by dividing the amount of the last quarterly dividend by 91. If the Merger is completed, UNS Energy's board of directors may declare a stub period dividend.
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 between 2010 and 2013 eligible for 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 and have created net operating loss carryforwards that can be used to offset future taxable income.  As a result, UNS Energy and TEP do not expect to pay any federal or state income taxes through 2017.  However, if the Merger is approved, UNS Energy and TEP will be limited in the

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amount of net operating loss carryforward that can be used annually, which is expected to result in Federal tax payments in 2015.

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.
Second quarter of 2014 compared with the second quarter of 2013
TEP reported net income of $39 million in the second quarter of 2014 compared with net income of $31 million in the second quarter of 2013. The following factors affected the change in TEP’s pre-tax results in the second quarter of 2014:
a $22 million increase in Retail Margin Revenues due to a Base Rate increase that was effective on July 1, 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 decrease in Base O&M due in part to certain costs now being recovered through fuel and purchased power expense as a result of the 2013 TEP Rate Order; and
a $1 million decrease in interest expense due to a reduction in the balance of capital lease obligations; partially offset by
a $1 million increase in taxes other than income taxes due in part to an increase in property tax rates and higher asset balances.
TEP's results in the second quarter of 2013 include: an $11 million tax benefit related to a regulatory asset recorded in June 2013 to recover previously recorded income tax expense through future rates (See Note 13); and a pre-tax charge of $3 million recorded in June 2013 to fuel and purchased energy expense. Both items were a result of the 2013 TEP Rate Order.
Six months ended June 30, 2014 compared with the six months ended June 30, 2013
TEP reported net income of $48 million in the first six months of 2014 compared with net income of $32 million in the first six months of 2013. The following factors affected TEP’s pre-tax results in the first six months of 2014:
a $34 million increase in Retail Margin Revenues due to a Base Rate increase that was effective on July 1, 2013, which includes $6 million of LFCR revenues recorded in the first six months of 2014 related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2014 and 2013. See Factors Affecting Results of Operations, 2013 TEP Rate Order, below, and Note 3;
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; and
a $4 million decrease in interest expense due to a reduction in the balance of capital lease obligations; partially offset by
a $2 million increase in taxes other than income taxes due in part to an increase in property tax rates and higher asset balances.
TEP's results in the first six months of 2013 include: an $11 million tax benefit related to a regulatory asset recorded in June 2013 to recover previously recorded income tax expense through future rates (See Note 13); and a pre-tax charge of $3 million recorded in June 2013 to fuel and purchased energy expense. Both items were a result of the 2013 TEP Rate Order.

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Utility Sales and Revenues
The table below provides a summary of TEP’s retail kWh sales, revenues, and weather data during the second quarters of 2014 and 2013:
 
Three Months Ended June 30,
 
Increase (Decrease)
 
2014
 
2013
 
Amount
 
Percent(1)
Energy Sales, kWh (in Millions):
 
 
 
 
 
 
 
Electric Retail Sales:
 
 
 
 
 
 
 
Residential
986

 
1,002

 
(16
)
 
(1.6
)%
Commercial(2)
585

 
599

 
(14
)
 
(2.3
)%
Industrial
526

 
543

 
(17
)
 
(3.1
)%
Mining
284

 
258

 
26

 
10.1
 %
Other(2)
8

 
8

 

 
 %
Total Electric Retail Sales
2,389

 
2,410

 
(21
)
 
(0.9
)%
Retail Margin Revenues (in Millions):
 
 
 
 
 
 
 
Residential
$
74

 
$
65

 
$
9

 
13.8
 %
Commercial(2)
53

 
47

 
6

 
12.8
 %
Industrial
28

 
24

 
4

 
16.7
 %
Mining
10

 
8

 
2

 
25.0
 %
Other(2)
1

 
1

 

 
 %
Total by Customer Class
166

 
145

 
21

 
14.5
 %
LFCR Revenues
1

 

 
1

 
NM

Total Retail Margin Revenues (Non-GAAP)(3)
167

 
145

 
22

 
15.2
 %
Fuel and Purchased Power Revenues
79

 
87

 
(8
)
 
(9.2
)%
RES, DSM, and ECA Revenues
12

 
12

 

 
 %
Total Retail Revenues (GAAP)
$
258

 
$
244

 
$
14

 
5.7
 %
Average Retail Margin Rate (Cents / kWh):(1)
 
 
 
 
 
 
 
Residential
7.51

 
6.54

 
0.97

 
14.8
 %
Commercial(2)
9.06

 
7.85

 
1.21

 
15.4
 %
Industrial
5.32

 
4.44

 
0.88

 
19.8
 %
Mining
3.52

 
3.09

 
0.43

 
13.9
 %
Other(2)
12.50

 
12.50

 

 
 %
Total Average by Customer Class
6.95

 
6.02

 
0.93

 
15.4
 %
Average LFCR Revenues
0.04

 

 
0.04

 
NM

Average Retail Margin Revenues
6.99

 
6.03

 
0.96

 
15.9
 %
Average Fuel and Purchased Power Revenues
3.31

 
3.59

 
(0.28
)
 
(7.8
)%
Average RES, DSM, and ECA Revenues
0.50

 
0.49

 
0.01

 
2.0
 %
Total Average Retail Revenues
10.80

 
10.11

 
0.69

 
6.8
 %
 
 
 
 
 
 
Weather Data:
 
 
 
 
 
 
 
Cooling Degree Days
 
 
 
 
 
 
 
Three Months Ended June 30,
550

 
577

 
(27
)
 
(4.7
)%
10-Year Average
478

 
463

 
NM

 
NM

(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 and associated retail margin revenues 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 from kWh sales and LFCR revenues available to cover the non-fuel operating expenses of our core utility business.

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Table of Contents

Retail kWh Sales and Margin Revenues
TEP's total retail kWh sales decreased by 0.9% in the second quarter of 2014 due in part to (i) a 4.7% decrease in cooling degree days compared with the second quarter of 2013 and (ii) ongoing energy efficiency programs and additions to customer-owned solar generation. Total Retail Margin Revenues increased by $22 million, or 15.2%, due to a Base Rate increase that was effective on July 1, 2013 and $1 million of LFCR revenues recorded in the second quarter of 2014.
Mining kWh sales increased by 10.1% compared with the second quarter of 2013 due in part to an expansion of one of our customer's mines in October 2013.

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The table below provides a summary of TEP’s retail kWh sales, revenues, and weather data during the first six months of 2014 and 2013:
 
Six Months Ended June 30,
 
Increase (Decrease)
 
2014
 
2013
 
Amount
 
Percent(1)
Energy Sales, kWh (in Millions):
 
 
 
 
 
 
 
Electric Retail Sales:
 
 
 
 
 
 
 
Residential
1,654

 
1,795

 
(141
)
 
(7.9
)%
Commercial(2)
1,029

 
1,050

 
(21
)
 
(2.0
)%
Industrial
997

 
1,016

 
(19
)
 
(1.9
)%
Mining
563

 
528

 
35

 
6.6
 %
Other(2)
17

 
16

 
1

 
6.3
 %
Total Electric Retail Sales
4,260

 
4,405

 
(145
)
 
(3.3
)%
Retail Margin Revenues (in Millions):
 
 
 
 
 
 
 
Residential
$
125

 
$
116

 
$
9

 
7.8
 %
Commercial(2)
87

 
80

 
7

 
8.8
 %
Industrial
51

 
44

 
7

 
15.9
 %
Mining
19

 
14

 
5

 
35.7
 %
Other(2)
1

 
1

 

 
 %
Total by Customer Class
283

 
255

 
28

 
11.0
 %
LFCR Revenues
6

 

 
6

 
NM

Total Retail Margin Revenues (Non-GAAP)(2)
289

 
255

 
34

 
13.3
 %
Fuel and Purchased Power Revenues
131

 
151

 
(20
)
 
(13.2
)%
RES, DSM and ECA Revenues
24

 
23

 
1

 
4.3
 %
Total Retail Revenues (GAAP)
$
444

 
$
429

 
$
15

 
3.5
 %
Average Retail Margin Rate (Cents / kWh):(1)
 
 
 
 
 
 
 
Residential
7.56

 
6.44

 
1.12

 
17.4
 %
Commercial(2)
8.45

 
7.62

 
0.83

 
10.9
 %
Industrial
5.12

 
4.28

 
0.84

 
19.6
 %
Mining
3.37

 
2.75

 
0.62

 
22.5
 %
Other(2)
5.88

 
6.25

 
(0.37
)
 
(5.9
)%
Total Average by Customer Class
6.64

 
5.79

 
0.85

 
14.7
 %
Average LFCR Revenues
0.14

 

 
0.14

 
NM

Average Retail Margin Revenues
6.78

 
5.79

 
0.99

 
17.1
 %
Average Fuel and Purchased Power Revenues
3.08

 
3.42

 
(0.34
)
 
(9.9
)%
Average RES, DSM and ECA Revenues
0.56

 
0.51

 
0.05

 
9.8
 %
Total Average Retail Revenue
10.42

 
9.72

 
0.70

 
7.2
 %
 
 
 
 
 
 
Weather Data:
 
 
 
 
 
 
 
Cooling Degree Days
 
 
 
 
 
 
 
Six Months Ended June 30,
550

 
577

 
(27
)
 
(4.7
)%
10-Year Average
478

 
463

 
NM

 
NM

Heating Degree Days
 
 
 
 
 
 
 
Six Months Ended June 30,
455

 
983

 
(528
)
 
(53.7
)%
10-Year Average
819

 
867

 
NM

 
NM

(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 and associated retail margin revenues 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.

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(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 from kWh sales and LFCR revenues available to cover the non-fuel operating expenses of our core utility business.
Retail kWh Sales and Margin Revenues
TEP's total retail kWh sales decreased by 3.3% in the first six months of 2014 due in part to: a 4.7% decrease in cooling degree days compared with the first six months of 2013; a 55.0% decrease in heating degree days during the first three months of 2014 compared with the first three months of 2013; and ongoing energy efficiency programs and additions to customer-owned solar generation. Total Retail Margin Revenues increased by $34 million, or 13.3%, due to a Base Rate increase that was effective on July 1, 2013 and $6 million of LFCR revenues recorded in the first six months of 2014.
Mining kWh sales increased by 6.6% compared with the first six months of 2013 due in part to an expansion of one of our customer's mines in October 2013.
Wholesale Sales and Transmission Revenues
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
Long-Term Wholesale Revenues:
 
 
 
 
 
 
 
Long-Term Wholesale Margin Revenues (Non-GAAP)(1)
$
2

 
$
1

 
$
6

 
$
4

Fuel and Purchased Power Expense Allocated to Long- Term Wholesale Revenues
5

 
4

 
9

 
9

Total Long-Term Wholesale Revenues
7

 
5

 
15

 
13

Transmission Revenues
4

 
4

 
8

 
8

Short-Term Wholesale Revenues
22

 
21

 
52

 
43

Electric Wholesale Sales (GAAP)
$
33

 
$
30

 
$
75

 
$
64

(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 first six months of 2014 were higher when compared with the first six months of 2013 due in part to higher market prices for wholesale power.
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 June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
 
Millions of Dollars
Revenue related to Springerville Units 3 and 4(1)
$
24

 
$
24

 
$
46

 
$
45

Other Revenue
7

 
7

 
13

 
15

Total Other Revenue
$
31

 
$
31

 
$
59

 
$
60

(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.

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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 second quarter and first six months of 2014 when compared with the same periods last year due in part to maintenance outages .
TEP’s fuel and purchased power expense and energy resources for the quarters ended June 30, 2014 and 2013 are detailed below:
 
Generation and Purchased
Power
 
Fuel and Purchased Power
Expense
 
Three Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of kWh
 
Millions of Dollars
Coal-Fired Generation
1,907

 
2,639

 
$
50

 
$
71

Gas-Fired Generation
306

 
232

 
16

 
12

Utility Owned Renewable Generation
12

 
13

 

 

Reimbursed Fuel Expense for Springerville Units 3 and 4

 

 
2

 
2

Total Fuel
2,225

 
2,884

 
68

 
85

Total Purchased Power
1,107

 
544

 
53

 
28

Transmission and Other PPFAC Recoverable Costs

 

 
4

 
2

Increase (Decrease) to Reflect PPFAC Recovery Treatment

 

 
(13
)
 
5

Total Resources
3,332

 
3,428

 
$
112

 
$
120

Less Line Losses and Company Use
(230
)
 
(248
)
 
 
 
 
Total Energy Sold
3,102

 
3,180

 
 
 
 
 
 
 
 
 
 
 
 
TEP’s fuel and purchased power expense and energy resources for the first six months of 2014 and 2013 are detailed below:
 
Generation and Purchased
Power
 
Fuel and Purchased Power
Expense
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of kWh
 
Millions of Dollars
Coal-Fired Generation
4,202

 
5,110

 
$
106

 
$
142

Gas-Fired Generation
546

 
418

 
27

 
20

Utility Owned Renewable Generation
22

 
24

 

 

Reimbursed Fuel Expense for Springerville Units 3 and 4

 

 
3

 
3

Total Fuel
4,770

 
5,552

 
136

 
165

Total Purchased Power
1,547

 
973

 
76

 
47

Transmission and Other PPFAC Recoverable Costs

 

 
7

 
3

Increase (Decrease) to Reflect PPFAC Recovery Treatment

 

 
(15
)
 
3

Total Resources
6,317

 
6,525

 
$
204

 
$
218

Less Line Losses and Company Use
(397
)
 
(420
)
 
 
 
 
Total Energy Sold
5,920

 
6,105

 
 
 
 

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The table below summarizes TEP’s average fuel cost per kWh generated or purchased:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
cents per kWh
Coal
2.64

 
2.71

 
2.52

 
2.78

Gas
5.34

 
4.99

 
5.02

 
4.71

Purchased Power
4.78

 
5.22

 
4.88

 
4.87

All Sources
4.02

 
3.61

 
3.70

 
3.53

O&M
The table below summarizes the items included in TEP’s O&M expense. Base O&M in the first six months of 2014 includes merger-related expenses of $1 million.
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
Base O&M (Non-GAAP)(1)
$
59

 
$
61

 
$
122

 
$
122

O&M Recorded in Other Expense
(2
)
 
(1
)
 
(4
)
 
(3
)
Reimbursed Expenses Related to Springerville Units 3 and 4
17

 
16

 
31

 
30

Expenses Related to Customer Funded Renewable Energy and DSM Programs(2)
6

 
6

 
12

 
11

Total O&M (GAAP)
$
80

 
$
82

 
$
161

 
$
160

(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:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
Pension Expense Charged to O&M
$
1

 
$
3

 
$
3

 
$
5

Retiree Benefit Expense Charged to O&M
1

 
1

 
2

 
2

Total
$
2

 
$
4

 
$
5

 
$
7


FACTORS AFFECTING RESULTS OF OPERATIONS
2013 TEP Rate Order
The provisions of the 2013 TEP Rate Order, which were effective July 1, 2013, include, but are not limited to:
An increase in Base Rates of approximately $76 million.
A 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 million annually.
An LFCR mechanism 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 review and a year-over-year cap of 1% of TEP's total retail revenues. TEP

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filed its first LFCR report with the ACC in May 2014. The report requested recovery of approximately $5 million. We expect the new LFCR rate to be effective August 1, 2014. TEP recorded LFCR revenues of $6 million in the first six months of 2014 related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013 and 2014. See Note 3.  TEP estimates that it will record total LFCR revenues of approximately $11 million during 2014.
An 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 filed its first ECA report in March 2014 to recover the return on and of qualified investments of approximately $3 million. The ECA rate became effective on May 1, 2014. TEP estimates that it will record total ECA revenues of less than $1 million in 2014.
As required by the 2013 Rate Order, TEP filed a compliance report in July 2014 that outlines its planned purchases of: (i) certain ownership interests in Springerville Unit 1; (ii) 75% of Gila River Unit 3; and (iii) the Springerville Coal Handling Facilities. The report estimates that as a result of these purchases, and the termination of certain lease obligations, TEP's 2014 non-fuel revenue requirement would decline by approximately $36 million. However, when other changes to TEP's rate base, expenses and retail sales levels are considered, we estimate that TEP would have a non-fuel revenue deficiency of approximately $26 million as of December 31, 2014.
See Coal-Fired Generating Resources and Springerville Coal Handling Facilities Leases, below, for more information.
Generating Resources
At June 30, 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 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 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, see Springerville Unit 1, below; and
the planned purchase of Gila River Unit 3, a combined cycle natural gas plant, see Gila River Generating Station Unit 3, 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 MW of 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 capacity rating of 387 MW.
During 2013, TEP agreed to purchase undivided ownership interests in Springerville Unit 1 totaling 35.4%, or 137 MW. The purchase price is the same as the appraisal value of $478 per kW, or approximately $65 million.
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 capacity. Due to TEP’s purchase commitments, TEP and UNS Energy recorded 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.

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TEP does not expect that its final undivided ownership interest in Springerville Unit 1 will exceed 49.5%, or 192 MW of 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 after January 2015, the expiration date of the leases. TEP is currently discussing its post-January 2015 operation of Springerville Unit 1, including capital and O&M cost allocations, with the remaining third-party owners.
TEP expects to replace the 195 MW of expiring leased capacity with the purchase of Gila River Unit 3. See Gila River Generating Station Unit 3, below.
Gila River Generating Station Unit 3
In December 2013, TEP and UNS Electric entered into 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.
On June 13, 2014, the United States Federal Trade Commission granted UNS Energy's request for early termination of the waiting period with respect to the Purchase Agreement under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.
The Purchase Agreement remains subject to, among other things:
the approval of the FERC;
the completion of certain other agreements associated with the operation of Gila River Unit 3; and
other customary closing conditions.
In June 2014, TEP provided a LOC for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the Purchase Agreement. The seller of Gila River Unit 3 is 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 and UNS Electric or the failure of TEP and UNS Electric to close the transaction when the closing conditions have been satisfied. Upon the close of the transaction, the LOC will be canceled.
The purchase of Gila River Unit 3, which would replace the expiring coal-fired leased capacity from Springerville Unit 1 and the expected reduction of coal-fired generating capacity from San Juan Unit 2, is consistent with TEP's strategy to diversify its generation fuel mix. See Note 6.
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 its anticipated ownership of 25% of Gila River Unit 3. See UNS Electric, Factors Affecting Results of Operations, Gila River Generating Station Unit 3 and Note 7.
Springerville Coal Handling Facilities Leases
TEP leases interests in the coal handling facilities at the Springerville Generating Station (Springerville Coal Handling Facilities) under two separate lease agreements (Springerville Coal Handling Facilities Leases). The lease agreements have an initial term that expires in April 2015 and provide TEP the option to renew the leases or to purchase the leased interests at the aggregate fixed price of $120 million.
In April 2014, TEP notified the owner participants and their lessors that TEP has elected to purchase their undivided ownership interests in the 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 recorded, in the second quarter of 2014, an increase to both Utility Plant Under Capital Leases and Current Obligations Under Capital Leases on its balance sheets in the amount of $109 million, which represented the present value of the total purchase commitment.
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 obligated to buy a portion of the Springerville Coal Handling Facilities from TEP for

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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.
Sales to Mining Customers
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 90 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 construction and ongoing operations of Rosemont Copper Mine requires electric service from TEP via a 138 kilo-volt (kV) transmission line. In 2012, the ACC approved a Certificate of Environmental Compatibility (CEC) authorizing TEP to build the line to serve the mine. 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
TEP 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:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
Other Revenues
$
24

 
$
24

 
$
46

 
$
45

Fuel Expense
(2
)
 
(2
)
 
(3
)
 
(3
)
O&M Expense
(17
)
 
(16
)
 
(31
)
 
(30
)
Taxes Other Than Income Taxes

 

 
(1
)
 
(1
)
Interest Rates
See Item 3. Quantitative and Qualitative Disclosures about Market Risk.
Fair Value Measurements
See Note 12.


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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:
 
Six Months Ended June 30,
 
2014
 
2013
 
Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)
$
113

 
$
116

Less: Capital Expenditures
(157
)
 
(118
)
Net Cash Flows after Capital Expenditures (Non-GAAP)(1)
(44
)
 
(2
)
Less: Payments of Capital Lease Obligations
(83
)
 
(84
)
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)
$
(127
)
 
$
(77
)
 
Six Months Ended June 30,
 
2014
 
2013
 
Millions of Dollars
Net Cash Flows – Operating Activities (GAAP)
$
113

 
$
116

Net Cash Flows – Investing Activities (GAAP)
(160
)
 
(113
)
Net Cash Flows – Financing Activities (GAAP)
65

 
(55
)
Net Increase (Decrease) in Cash
18

 
(52
)
Beginning Cash
25

 
80

Ending Cash
$
43

 
$
28

(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
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 with Fortis is approved by all necessary parties, the terms of the Settlement provide that Fortis will make an equity investment of $220 million in UNS Energy within 60 days after closing. If the Merger closes by September 30, 2014, the equity contribution from Fortis will be contributed to the Regulated Utilities, including TEP, to help fund the Gila River Unit 3 and Springerville Unit 1 purchase commitments.
Operating Activities
In the first six months of 2014, net cash flows from operating activities were $3 million lower than in the same period last year. The decrease was due primarily to: a $21 million increase in operations and maintenance costs and wages paid due to planned and unplanned maintenance outages, customer incentives related to renewable programs, and merger-related costs; partially offset by a $6 million increase in cash receipts due to insurance proceeds related to the San Juan mine fire; $6 million of lower interest paid on debt and capital leases; a $3 million increase in cash receipts from retail and electric sales, net of fuel and purchased power costs paid due to a Base Rate increase at TEP that was effective on July 1, 2013; and a $2 million decrease in taxes paid, net of amounts capitalized.

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Investing Activities
Net cash flows used for investing activities increased by $48 million in the first six months of 2014 compared with the same period last year due primarily to an $39 million increase in capital expenditures due in part to maintenance on our generating facilities and the construction of new solar projects. Cash flows from investing activities in the first six months of 2014 also included a $9 million reduction in return of investments in lease debt.
Financing Activities
In the first six months of 2014, net cash from financing activities was $120 million higher than the same period last year due to proceeds from the issuance of $150 million of long-term debt offset by $30 million more in repayments (net of borrowings) under the TEP Revolving Credit Facility.
2014 Bond Issuances
In 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 repay approximately $90 million outstanding under TEP's revolving credit facility, with the remaining proceeds to be applied to general corporate purposes. See Note 5.
TEP Credit Agreement
The TEP Credit Agreement consists of a $200 million revolving credit and LOC facility, and a separate $82 million LOC facility to support tax-exempt bonds. The TEP Credit Agreement expires in November 2016. See Note 5.
TEP provided, in the second quarter of 2014, a 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 is reduced by $15 million until the Gila River transaction closes and the LOC is terminated. See Note 7.
At June 30, 2014, there were no outstanding borrowings and there were $16 million of LOCs issued under the revolving credit and LOC facility, leaving $184 million of available borrowing capacity.
In July 2014, TEP made additional borrowings under its revolving credit facility to help fund scheduled capital lease payments. As of July 18, 2014, TEP had $134 million available under its revolving credit facility.
The TEP Credit Agreement contains restrictions on 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 June 30, 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 June 30, 2014, TEP was in compliance with the terms of the 2010 TEP Reimbursement Agreement.

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Capital Lease Obligations
At June 30, 2014, TEP had $343 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 Leases
June 30, 2014
 
Expiration
 
Renewal/Purchase Option
 
Millions of Dollars
 
 
 
 
Springerville Unit 1(1)
$
129

 
2015
 
Fair market value
Springerville Coal Handling Facilities
131

 
2015
 
Fixed price purchase
option of $120 million(2)
Springerville Common Facilities(3)
83

 
2017 and 2021
 
Fixed price purchase
option of $106 million(3)
Total Capital Lease Obligations
$
343

 
 
 
 
 
(1) 
The Springerville Unit 1 Leases cover both Unit 1 and an undivided one-half interest in certain Springerville Common Facilities. The $129 million balance includes the present value of the lease purchase options agreed to in 2013.
(2) 
The $131 million balance includes the present value of the lease purchase options elected in April 2014. 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. See Factors Affecting Results of Operations, Springerville Coal Handling Facilities Leases. Also see Note 5.
(3) 
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.
Contractual Obligations
There have been no changes in TEP'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:
In March 2014, TEP issued $150 million of 5.0% unsecured notes due March 2044. See Note 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 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.
TEP entered into new forward purchased power commitments with minimum payment obligations of $15 million million in 2015. See Note 6 .
TEP entered into new forward energy commitments with minimum payment obligations of $8 million in 2015 through 2019. See Note 6.
We have reviewed our contractual obligations and provide the following additional information:
The TEP Credit Agreement, the 2010 Reimbursement Agreement, and the 2013 Covenants 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.

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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 June 30, 2014, TEP 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 June 30, 2014, TEP had posted less than $1 million in LOCs as collateral with wholesale counterparties for credit enhancement.
In June 2014, TEP provided a LOC for $15 million to the seller of Gila River Unit 3 to satisfy a condition of the purchase agreement. See Note 7.
Dividends on Common Stock
TEP did not pay any dividends to UNS Energy in the first six months of 2014 or 2013.
The pending Settlement related to the Merger contains a condition restricting subsidiary dividend payments to UNS Energy. See UNS Energy, Outlook and Strategies.
TEP can pay dividends to UNS Energy if it maintains compliance with the TEP Credit Agreement, the 2010 TEP Reimbursement Agreement and the 2013 Covenants Agreement. At June 30, 2014, TEP was in compliance with the terms of the TEP Credit Agreement, the 2010 TEP Reimbursement Agreement and the 2013 Covenants Agreement.

UNS ELECTRIC
RESULTS OF OPERATIONS
UNS Electric reported net income of $4 million in the second quarters of 2014 and 2013. In the first six months of 2014 and 2013, UNSE Electric reported net income of $6 million.
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 June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
Retail Electric Revenues
$
45

 
$
42

 
$
84

 
$
78

Wholesale Electric Revenues
2

 
2

 
4

 
3

Total Operating Revenues
47

 
44

 
88

 
81

Purchased Energy Expense
20

 
20

 
39

 
37

Fuel Expense
1

 
2

 
1

 
3

Transmission Expense
3

 
3

 
7

 
6

Increase (Decrease) to Reflect PPFAC Recovery
1

 
(2
)
 
1

 
(4
)
O&M
7

 
7

 
14

 
15

Depreciation and Amortization Expense
5

 
5

 
10

 
9

Taxes Other Than Income Taxes
2

 
1

 
3

 
3

Total Operating Expenses
39

 
36

 
75

 
69

Operating Income
8

 
8

 
13

 
12

Interest Expense
2

 
2

 
4

 
3

Income Tax Expense
2

 
2

 
3

 
3

Net Income
$
4

 
$
4

 
$
6

 
$
6


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The tables below shows UNS Electric’s kWh sales and margin revenues:
 
Three Months Ended June 30,
 
Increase (Decrease)
 
2014
 
2013
 
Amount
 
Percent(1)
Electric Retail Sales, kWh (in Millions):
 
 
 
 
 
 
 
Residential
201

 
201

 

 
 %
Commercial
165

 
170

 
(5
)
 
(2.9
)%
Industrial
48

 
49

 
(1
)
 
(2.0
)%
Mining
17

 
16

 
1

 
6.3
 %
Total Electric Retail Sales
431

 
436

 
(5
)
 
(1.1
)%
 
 
 
 
Retail Margin Revenues (in Millions):
 
 
 
Residential
$
8

 
$
8

 
$

 
 %
Commercial
8

 
8

 

 
 %
Industrial
2

 
2

 

 
 %
Mining
1

 
1

 

 
 %
Total Retail Margin Revenues (Non-GAAP)(2)
19

 
19

 

 
 %
Fuel and Purchased Power Revenues
24

 
21

 
3

 
14.3
 %
RES & DSM Revenues
2

 
2

 

 
 %
Total Retail Revenues (GAAP)
$
45

 
$
42

 
$
3

 
7.1
 %
Weather Data:
 
 
 
 
 
 
 
Cooling Degree Days
 
 
 
 
 
 
 
Three Months Ended June 30,
1,162

 
1,221

 
(59
)
 
(4.8
)%
10-Year Average
1,037

 
1,029

 
NM

 
NM

(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 from kWh sales available to cover the non-fuel operating expenses of our core utility business.
Total retail kWh sales in the second quarter of 2014 decreased by 1.1% compared with the same period last year due in part to milder summer weather. Despite lower retail sales, total retail margin revenues in the second quarter of 2014 were the same when compared to the second quarter of 2013 due in part to a Base Rate increase effective January 1, 2014.

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Six Months Ended June 30,
 
Increase (Decrease)
 
2014
 
2013
 
Amount
 
Percent(1)
Electric Retail Sales, kWh (in Millions):
 
 
 
 
 
 
 
Residential
359

 
392

 
(33
)
 
(8.4
)%
Commercial
297

 
297

 

 
 %
Industrial
92

 
91

 
1

 
1.1
 %
Mining
31

 
29

 
2

 
6.9
 %
Other
1

 
1

 

 
 %
Total Electric Retail Sales
780

 
810

 
(30
)
 
(3.7
)%
 
 
 
 
Retail Margin Revenues (in Millions):
 
 
 
Residential
$
15

 
$
15

 
$

 
 %
Commercial
14

 
14

 

 
 %
Industrial
4

 
4

 

 
 %
Mining
2

 
3

 
(1
)
 
(33.3
)%
Total by Customer Class
35

 
36

 
(1
)
 
(2.8
)%
LFCR Revenues
2

 

 
2

 
NM

Total Retail Margin Revenues (Non-GAAP)(2)
37

 
36

 
1

 
2.8
 %
Fuel and Purchased Power Revenues
43

 
38

 
5

 
13.2
 %
RES & DSM Revenues
4

 
4

 

 
 %
Total Retail Revenues (GAAP)
$
84

 
$
78

 
$
6

 
7.7
 %
Weather Data:
 
 
 
 
 
 
 
Cooling Degree Days
 
 
 
 
 
 
 
Six Months Ended June 30,
1,250

 
1,304

 
(54
)
 
(4.1
)%
10-Year Average
1,083

 
1,074

 
NM

 
NM

(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 from kWh sales and LFCR revenues available to cover the non-fuel operating expenses of our core utility business.
In the first six months of 2014, total retail kWh sales declined by 3.7% compared with the first six months of 2013 due in part to a 4.1% decrease in cooling degree days and due to milder weather in the first quarter of 2014 when compared with the first quarter of 2013. Total retail margin revenues increased by $1 million, or 2.8%. UNS Electric recorded LFCR revenues of $2 million in the first six months 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

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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 filed its first LFCR report with the ACC in May 2014. The report requested recovery of approximately $1 million. We expect the new LFCR rate to be effective September 1, 2014. UNS Electric recorded LFCR revenues of $2 million in the first six months of 2014 related to reductions in retail kWh sales due to energy efficiency programs and distributed generation implemented in 2013 and 2014. See Note 3. UNS Electric estimates that it will record total LFCR revenues of approximately $2 million during 2014; and
a Transmission Cost Adjustor (TCA) mechanism 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. The TCA rate became effective in June 2014. UNS Electric estimates that it will record TCA revenues of $1 million in 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, Factors 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:
 
Six Months Ended June 30,
 
2014
 
2013
 
Millions of Dollars
Cash Provided By (Used In):
 
 
 
Operating Activities
$
20

 
$
12

Investing Activities
(22
)
 
(30
)
Financing Activities
1

 
14

Net Increase/(Decrease) in Cash
(1
)
 
(4
)
Beginning Cash
5

 
8

Ending Cash
$
4

 
$
4


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Operating Activities
Cash provided by operating activities increased by $8 million in the first six months of 2014 when compared with the same period last year due primarily to a $3 million increase in cash receipts from electric retail sales caused by a Base Rate increase that was effective on January 1, 2014 and a $4 million reduction in income taxes paid.
Investing Activities
UNS Electric had capital expenditures of $20 million in the first six months of 2014 compared with $29 million in the first six months of 2013. The decrease is related to the completion 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 six months of 2014 decreased by $13 million when compared with the same period last year. Financing activities in the first six months of 2014 included $1 million of borrowings under the UNS Electric/UNS Gas Revolver (net of repayments) whereas activity in the same period last year included $12 million of borrowings (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 so long as it maintains compliance with the agreement. At June 30, 2014, UNS Electric and UNS Gas each were in compliance with the terms of the UNS 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 June 30, 2014, UNS Electric had $23 million of outstanding borrowings and less than $1 million of LOCs issued under the UNS Electric/UNS Gas Credit Agreement, leaving available borrowing capacity of $47 million.
Contractual Obligations
There are no 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 the first six months of 2014 and 2013. UNS Electric’s ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.
The pending Settlement related to the Merger contains a condition restricting subsidiary dividend payments to UNS Energy. See UNS Energy, Outlook and Strategies.
The 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 June 30, 2014, UNS Electric was in compliance with the terms of its note purchase agreement and the terms of the UNS Electric/UNS Gas Revolver.


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UNS GAS
RESULTS OF OPERATIONS
UNS Gas reported no net income or loss in the second quarters of 2014 and 2013. In the first six months of 2014, UNS Gas reported net income of $5 million compared with net income of $8 million in the same period last year.
The table below provides summary financial information for UNS Gas:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2014
 
2013
 
2014
 
2013
 
Millions of Dollars
Gas Revenues
$
23

 
$
22

 
$
62

 
$
73

Other Revenues

 

 
3

 
1

Total Operating Revenues
23

 
22

 
65

 
74

Purchased Gas Expense
12

 
12

 
42

 
42

Increase (Decrease) to Reflect PGA Recovery Treatment

 
(1
)
 
(8
)
 
(2
)
O&M
6

 
6

 
12

 
12

Depreciation and Amortization
2

 
2

 
5

 
4

Taxes Other Than Income Taxes
1

 
1

 
2

 
2

Total Operating Expenses
21

 
20

 
53

 
58

Operating Income
2

 
2

 
12

 
16

Other Expense

 

 
1

 

Interest Expense
2

 
2

 
3

 
3

Income Tax Expense

 

 
3

 
5

Net Income
$

 
$

 
$
5

 
$
8

The table below includes UNS Gas' therm sales and margin revenues for the second quarter of 2014 and 2013:
 
Three Months Ended June 30,
 
Increase (Decrease)
 
2014
 
2013
 
Amount
 
Percent(1)
Gas Retail Sales, Therms (in Millions):
 
 
 
 
 
 
 
Residential
10

 
9

 
1

 
11.1
 %
Commercial
5

 
5

 

 
 %
All Other
1

 
1

 

 
 %
Total Gas Retail Sales
16

 
15

 
1

 
6.7
 %
Negotiated Sales Program (NSP)
6

 
7

 
(1
)
 
(14.3
)%
Total Gas Sales
22

 
22

 

 
 %
Retail Margin Revenues (in Millions):
 
 
 
Residential
$
7

 
$
7

 
$

 
 %
Commercial
2

 
2

 

 
 %
All Other
1

 
1

 

 
 %
Total Retail Margin Revenues (Non-GAAP)(2)
10

 
10

 

 
 %
Transport and NSP
4

 
4

 

 
 %
Retail Fuel Revenues
9

 
8

 
1

 
12.5
 %
Total Gas Revenues (GAAP)
$
23

 
$
22

 
$
1

 
4.5
 %
Weather Data:
 
 
 
 
 
 
 
Heating Degree Days
 
 
 
 
 
 
 
Three Months Ended June 30,
541

 
480

 
61

 
12.7
 %
10-Year Average
547

 
560

 
NM

 
NM

(1) 
Calculated on un-rounded data and may not correspond exactly to data shown in table.

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(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.
Retail therm sales in the second quarter of 2014 increased by 6.7% compared with the second quarter of 2013 due in part to a 12.7% increase in heating degree days. Despite the increase in retail therm sales, retail margin revenues were flat when compared with the second quarter of 2013.
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 six months of 2014 and 2013:
 
Six Months Ended June 30,
 
Increase (Decrease)
 
2014
 
2013
 
Amount
 
Percent(1)
Gas Retail Sales, Therms (in Millions):
 
 
 
 
 
 
 
Residential
36

 
44

 
(8
)
 
(18.2
)%
Commercial
15

 
17

 
(2
)
 
(11.8
)%
All Other
5

 
5

 

 
 %
Total Gas Retail Sales
56

 
66

 
(10
)
 
(15.2
)%
Negotiated Sales Program (NSP)
11

 
13

 
(2
)
 
(15.4
)%
Total Gas Sales
67

 
79

 
(12
)
 
(15.2
)%
Retail Margin Revenues (in Millions):
 
 
 
 
 
 
 
Residential
$
20

 
$
23

 
$
(3
)
 
(13.0
)%
Commercial
6

 
6

 

 
 %
All Other
1

 
1

 

 
 %
Total Retail Margin Revenues (Non-GAAP)(2)
27

 
30

 
(3
)
 
(10.0
)%
Transport and NSP
8

 
9

 
(1
)
 
(11.1
)%
Retail Fuel Revenues
27

 
34

 
(7
)
 
(20.6
)%
Total Gas Revenues (GAAP)
$
62

 
$
73

 
$
(11
)
 
(15.1
)%
Weather Data:
 
 
 
 
 
 
 
Heating Degree Days
 
 
 
 
 
 
 
Six Months Ended June 30,
2,263

 
2,668

 
(405
)
 
(15.2
)%
10-Year Average
2,653

 
2,643

 
NM

 
NM

(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.
Retail therm sales in the first six months of 2014 declined by 15.2% when compared with the first six months of 2013 due to a 15.2% decrease in heating degree days. The lower retail therm sales contributed to a decrease in retail margin revenues of 10.0%, or $3 million, when compared with the first six months of 2013.


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FACTORS AFFECTING RESULTS OF OPERATIONS
Fair Value Measurements
See Note 12.

LIQUIDITY AND CAPITAL RESOURCES
Liquidity Outlook
UNS Gas expects operating cash flows to fund all of its construction expenditures during 2014. Sources of funding future capital expenditures could include existing cash balances, 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 Gas:
 
Six Months Ended June 30,
 
2014
 
2013
 
Millions of Dollars
Cash Provided By (Used In):
 
 
 
Operating Activities
$
4

 
$
17

Investing Activities
(8
)
 
(8
)
Financing Activities
(11
)
 
(10
)
Net Decrease in Cash
(15
)
 
(1
)
Beginning Cash
33

 
31

Ending Cash
$
18

 
$
30

UNS Gas' operating cash flows during the first six months of 2014 were $13 million lower than the first six months of 2013 primarily due to the return of the over-collected PGA balance to customers and lower retail therm sales.
UNS Electric/UNS Gas Credit Agreement
At June 30, 2014, UNS Gas had no outstanding borrowings under the UNS Electric/UNS Gas Credit Agreement.
See UNS Electric, Liquidity and Capital Resources, UNS Electric/UNS Gas Credit Agreement.
Interest Rate Risk
See Item 3. Quantitative and Qualitative Disclosures about Market Risk.
Contractual Obligations
There are no changes in UNS Gas' 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 Gas entered into new forward energy commitments with minimum payment obligations of $1 million in each of 2015 through 2017. See Note 6.
Dividends on Common Stock
UNS Gas paid dividends to UNS Energy, through UES, of $10 million in the first six months of 2014 and 2013. UNS Gas’ ability to pay future dividends will depend on the cash needs for capital expenditures and various other factors.
The pending Settlement related to the Merger contains a condition restricting subsidiary dividend payments to UNS Energy. See UNS Energy, Outlook and Strategies.

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The note purchase agreement for UNS Gas contains restrictions on dividends. UNS Gas 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 June 30, 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.


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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
In April 2014, the FASB issued an accounting standards update that limits the circumstances under which a disposal may be reported as a discontinued operation and requires new disclosures. This guidance will be effective in the first quarter of 2015. We do not expect the adoption of this guidance to have an impact on the presentation of our financial statements or our disclosures.
In May 2014, the FASB issued an accounting standards update that will eliminate the transaction- and industry-specific revenue recognition guidance under current U.S. GAAP and replace it with a principles based approach for determining revenue recognition. We will be required to adopt the new guidance retrospectively for annual and interim periods beginning January 1, 2017; early adoption is not permitted. We are evaluating the impact to our financial statements and disclosures.

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; 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 3 in our Annual Report on Form 10-K for the year ended December 31, 2013.

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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 second quarter of 2014 that has materially affected, or is reasonably likely to materially affect, UNS Energy’s or TEP’s internal control over financial reporting.


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PART II - OTHER INFORMATION
ITEM 1. – LEGAL PROCEEDINGS
See the legal proceedings described in Item 3. – Legal Proceedings in our 2013 Annual Report on Form 10-K and in Note 6 and in Item 2. – Management’s Discussion and Analysis of Financial Condition and Results of Operations, which descriptions in Note 6 and Item 2 are incorporated herein by reference.

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 2013 Annual Report on Form 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:
 
Six Months Ended June 30, 2014
 
Twelve Months Ended June 30, 2014
UNS Energy
2.572

 
2.982

TEP
2.484

 
2.987

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 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 (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 capital cost of this 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.

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Springerville Generating Station
Based on the MATS rules, Springerville Generating Station (Springerville) may require mercury emission control equipment by April 2016. 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 $1 million. Estimated costs are split equally between the two units. TEP will own 49.5% of Springerville Unit 1 upon close of the lease option purchases in January 2015; after the completion of such purchases, third party owners will be responsible for 50.5% of environmental costs attributed to Springerville Unit 1. TEP will continue to be responsible for 100% of environmental costs attributable to Springerville Unit 2.
Sundt Generating Station
TEP expects the MATS rules will have little effect on capital 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 wilderness areas. The rules call for all states to establish goals and emission reduction strategies for improving visibility. States must submit these goals and strategies to the EPA for approval. BART applies to plants built between August 1962 and August 1977. Because Navajo and Four Corners are located on the 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 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. 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.

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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. In May 2014, EPA proposed to approve the revised SIP and withdraw the existing FIP. The EPA is expected to make a final determination on the revised SIP 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 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.
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.
At June 30, 2014, the book value of 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 one unit by October 2016 and the remaining units by October 2017. In December 2013, APS (the operator) decided to shut down Units 1, 2, and 3 and install SCRs on Units 4 and 5. Under this scenario, the installation of 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 Units 1 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.
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 timeline to issue a federal implementation plan for emissions sources including Sundt Unit 4. While TEP does not agree that Sundt Unit 4 is subject 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 June 2014, the EPA issued a final BART rule that would require TEP to either (i) install, by mid-2017, SNCR and dry sorbent injection (DSI) 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 rule, TEP is required to notify the EPA of its decision by March 2017. At June 30, 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 for both new and existing fossil-fueled power plants.

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In January 2014, the EPA published 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.
In June 2014, the EPA issued proposed carbon emission regulations for existing power plants called the Clean Power Plan. The Clean Power Plan targets a nation-wide reduction in carbon emissions of 30% by 2030. To achieve this goal, the proposed plan sets carbon emission rates for each state that must be achieved by an interim period of 2020-2029, with final rates by 2030. States can apply a variety of strategies to achieve the interim and final emission rates. Using 2012 as a baseline year, Arizona's carbon emission rate for 2030 represents a 52% reduction. The EPA expects to issue a final rule by June 2015, and under the current proposal, states must file implementation plans by June 2016 (or June 2017 for multi-state plans, with a possible one-year extension). UNS Energy cannot estimate the impact of the new proposed rule on its operations at this time.
UNS Energy will continue to work with federal and state regulatory agencies, and other neighboring utilities, to promote compliance flexibility in the rules impacting existing fossil-fuel fired power plants. We cannot predict the ultimate outcome of these matters.
Coal Combustion Residuals Regulations
The EPA is developing regulations for Coal Combustion Residuals (CCR) placed in landfills and surface impoundments (i.e. ponds).
In June 2010, the EPA issued a proposed rule presenting for public comment two approaches for regulating CCR: 1) as solid waste under Subtitle D of the Resource Conservation and Recovery Act (RCRA); and 2) as hazardous waste under Subtitle C of RCRA. Both approaches would maintain an exception from regulation for beneficial use. In May 2014, EPA entered a consent decree agreeing to take final action on the proposed rule as it relates to regulation under Subtitle D of RCRA by December 2014.
If the final rule is structured similar to existing “municipal solid waste” rules, TEP’s ash disposal facility at Springerville would likely be in compliance with the requirements, however, upgrades could be required for future disposal. At Navajo and Four Corners, the ash that cannot be sold is land filled on site. These sites also could be required to upgrade. At San Juan, the ash that cannot be sold is returned to the mine. The proposed rule would not address mine placement of CCRs. Mine placement will be addressed through a separate rule-making under the oversight of the Department of Interior's Office of Surface Mining Reclamation and Enforcement.
If the final rule regulates CCR as a “hazardous waste”, in addition to the disposal facility upgrades discussed above, upgrades to handling and storage facilities at the plant sites would also be required.
TEP cannot determine the economic impact of this rule at this time.

ITEM 6. – EXHIBITS
See Exhibit Index.

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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:
July 29, 2014
 
/s/ Kevin P. Larson
 
  
 
Kevin P. Larson
 
  
 
Senior Vice President, Treasurer, and
 
  
 
Chief Financial Officer
 
 
 
 
 
  
 
TUCSON ELECTRIC POWER COMPANY
 
  
 
(Registrant)
 
 
 
 
Date:
July 29, 2014
 
/s/ Kevin P. Larson
 
  
 
Kevin P. Larson
 
 
 
Senior Vice President and Chief
 
  
 
Financial Officer


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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.
 
 
 
31(a)
 
  
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act – UNS Energy, by David G. Hutchens.
 
 
 
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 David G. Hutchens.
 
 
 
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 Quarterly Report on Form 10-Q for the three and six-month periods ended June 30, 2014, formatted in XBRL (Extensible Business Reporting Language):
 
 
 
 
 
 
 
  
(a)
UNS Energy’s and TEP’s (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income (iii) Consolidated Statements of Cash Flows, (iv) Consolidated Balance Sheets, (v) Consolidated Statements of Changes in Stockholders’ Equity; and
 
 
 
 
 
 
 
  
(b)
Notes to Consolidated Financial Statements.
(*)
Previously filed as indicated and incorporated herein by reference.
**
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.
 
 


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