EX-4.7


  Exhibit 4.7

 

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. 

TECO ENERGY, INC. 

 


Report of Independent Registered Certified Public Accounting Firm 

To the Board of Directors and Shareholders of TECO Energy, Inc.:

  

In our opinion, the consolidated financial statements listed in the
index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of TECO Energy, Inc. and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.  In addition, in our opinion, the financial statement schedule listed in the index appearing
under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.  Also in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO).  The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting
and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting.  Our responsibility is to express opinions on
these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits.  We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective
internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding
of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included
performing such other procedures as we considered necessary in the circumstances.  We believe that our audits provide a reasonable basis for our opinions. 

 

As discussed in Note 2 to the financial statements, the Company
changed the manner in which it classifies deferred taxes in 2015.
  

A company’s internal control over financial reporting is a
process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A
company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the financial statements. 
  

Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate. 
  

/s/ PricewaterhouseCoopers LLP 

Tampa, Florida 

February 26, 2016 

 
  

 

71


 TECO ENERGY, INC. 


Consolidated Balance Sheets 
  
 
	
Assets
	
 
	
Dec. 31,
	
 
	
 
	
Dec. 31,
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Current assets
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Cash and cash
equivalents
	
 
	
$
	
23.8
	
 
	
 
	
$
	
25.4
	
 

	
Receivables, less allowance for
uncollectibles of $2.1 and

   $2.1 at Dec. 31,
2015 and 2014, respectively
	
 
	
 
	
280.7
	
 
	
 
	
 
	
299.8
	
 

	
Inventories, at average
cost
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Fuel
	
 
	
 
	
113.4
	
 
	
 
	
 
	
96.4
	
 

	
Materials and supplies
	
 
	
 
	
76.8
	
 
	
 
	
 
	
75.4
	
 

	
Regulatory assets
	
 
	
 
	
44.8
	
 
	
 
	
 
	
53.6
	
 

	
Deferred income taxes
	
 
	
 
	
0.0
	
 
	
 
	
 
	
72.8
	
 

	
Prepayments and other current
assets
	
 
	
 
	
30.8
	
 
	
 
	
 
	
22.6
	
 

	
Assets held for sale
	
 
	
 
	
0.0
	
 
	
 
	
 
	
109.6
	
 

	
Total current assets
	
 
	
 
	
570.3
	
 
	
 
	
 
	
755.6
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Property, plant and
equipment
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Utility plant in
service
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Electric
	
 
	
 
	
7,270.3
	
 
	
 
	
 
	
7,094.8
	
 

	
Gas
	
 
	
 
	
2,113.8
	
 
	
 
	
 
	
1,984.6
	
 

	
Construction work in
progress
	
 
	
 
	
794.7
	
 
	
 
	
 
	
640.0
	
 

	
Other property
	
 
	
 
	
15.9
	
 
	
 
	
 
	
14.5
	
 

	
Property, plant and equipment,
at original costs
	
 
	
 
	
10,194.7
	
 
	
 
	
 
	
9,733.9
	
 

	
Accumulated
depreciation
	
 
	
 
	
(2,712.9
	
)
	
 
	
 
	
(2,645.7
	
)

	
Total property, plant and
equipment, net
	
 
	
 
	
7,481.8
	
 
	
 
	
 
	
7,088.2
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Other assets
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulatory assets
	
 
	
 
	
395.2
	
 
	
 
	
 
	
348.5
	
 

	
Goodwill
	
 
	
408.4
	
 
	
 
	
408.3
	
 

	
Deferred charges and other
assets
	
 
	
 
	
105.4
	
 
	
 
	
 
	
65.8
	
 

	
Assets held for sale
	
 
	
 
	
0.0
	
 
	
 
	
 
	
59.8
	
 

	
Total other assets
	
 
	
 
	
909.0
	
 
	
 
	
 
	
882.4
	
 

	
Total assets
	
 
	
$
	
8,961.1
	
 
	
 
	
$
	
8,726.2
	
 




The accompanying notes are an integral part of
the consolidated financial statements. 
  

 
  

72


 TECO ENERGY, INC. 

Consolidated Balance Sheets – continued 

 
 
	
Liabilities and Capital
	
 
	
Dec. 31,
	
 
	
 
	
Dec. 31,
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Current liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Long-term debt due within one
year
	
 
	
$
	
333.3
	
 
	
 
	
$
	
274.5
	
 

	
Notes payable
	
 
	
 
	
247.0
	
 
	
 
	
 
	
139.0
	
 

	
Accounts payable
	
 
	
 
	
255.4
	
 
	
 
	
 
	
288.6
	
 

	
Customer deposits
	
 
	
 
	
182.1
	
 
	
 
	
 
	
176.2
	
 

	
Regulatory liabilities
	
 
	
 
	
84.8
	
 
	
 
	
 
	
57.0
	
 

	
Derivative liabilities
	
 
	
 
	
24.1
	
 
	
 
	
 
	
36.6
	
 

	
Interest accrued
	
 
	
 
	
36.2
	
 
	
 
	
 
	
39.9
	
 

	
Taxes accrued
	
 
	
 
	
13.2
	
 
	
 
	
 
	
29.9
	
 

	
Other
	
 
	
 
	
22.6
	
 
	
 
	
 
	
16.8
	
 

	
Liabilities associated with
assets held for sale
	
 
	
 
	
0.0
	
 
	
 
	
 
	
39.4
	
 

	
Total current
liabilities
	
 
	
 
	
1,198.7
	
 
	
 
	
 
	
1,097.9
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Other liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Deferred income taxes
	
 
	
 
	
570.7
	
 
	
 
	
 
	
519.2
	
 

	
Investment tax credits
	
 
	
 
	
10.5
	
 
	
 
	
 
	
9.0
	
 

	
Regulatory liabilities
	
 
	
 
	
715.8
	
 
	
 
	
 
	
729.0
	
 

	
Derivative liabilities
	
 
	
 
	
2.1
	
 
	
 
	
 
	
6.1
	
 

	
Deferred credits and other
liabilities
	
 
	
 
	
387.4
	
 
	
 
	
 
	
370.9
	
 

	
Liabilities associated with
assets held for sale
	
 
	
 
	
0.0
	
 
	
 
	
 
	
65.4
	
 

	
Long-term debt, less amount due
within one year
	
 
	
 
	
3,516.9
	
 
	
 
	
 
	
3,354.0
	
 

	
Total other
liabilities
	
 
	
 
	
5,203.4
	
 
	
 
	
 
	
5,053.6
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Commitments and Contingencies (see
Note 12)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Capital
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Common equity (400.0 million
shares authorized; par value $1;

   235.3 million
and 234.9 million shares outstanding at

   Dec. 31, 2015 and
2014, respectively)
	
 
	
 
	
235.3
	
 
	
 
	
 
	
234.9
	
 

	
Additional paid in
capital
	
 
	
 
	
1,894.5
	
 
	
 
	
 
	
1,875.9
	
 

	
Retained earnings
	
 
	
 
	
441.4
	
 
	
 
	
 
	
479.6
	
 

	
Accumulated other comprehensive
loss
	
 
	
 
	
(12.2
	
)
	
 
	
 
	
(15.7
	
)

	
Total TECO Energy
capital
	
 
	
 
	
2,559.0
	
 
	
 
	
 
	
2,574.7
	
 

	
Total liabilities and
capital
	
 
	
$
	
8,961.1
	
 
	
 
	
$
	
8,726.2
	
 




The accompanying notes are an integral part of
the consolidated financial statements. 
  

 
  

73


 TECO ENERGY, INC.


Consolidated Statements of Income 
  
 
	
 (millions, except per share
amounts)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
For the years ended Dec.
31,
	
 
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Revenues
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulated electric
	
 
	
 
	
 
	
$
	
2,014.9
	
 
	
 
	
$
	
2,019.9
	
 
	
 
	
$
	
1,949.6
	
 

	
Regulated gas
	
 
	
 
	
 
	
 
	
716.8
	
 
	
 
	
 
	
537.4
	
 
	
 
	
 
	
392.9
	
 

	
Unregulated
	
 
	
 
	
 
	
 
	
11.8
	
 
	
 
	
 
	
9.1
	
 
	
 
	
 
	
12.6
	
 

	
Total revenues
	
 
	
 
	
 
	
 
	
2,743.5
	
 
	
 
	
 
	
2,566.4
	
 
	
 
	
 
	
2,355.1
	
 

	
Expenses
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulated operations and
maintenance
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Fuel
	
 
	
 
	
 
	
 
	
638.6
	
 
	
 
	
 
	
692.3
	
 
	
 
	
 
	
680.2
	
 

	
Purchased power
	
 
	
 
	
 
	
 
	
78.9
	
 
	
 
	
 
	
71.4
	
 
	
 
	
 
	
64.7
	
 

	
Cost of natural gas
sold
	
 
	
 
	
 
	
 
	
271.6
	
 
	
 
	
 
	
209.7
	
 
	
 
	
 
	
142.2
	
 

	
Other
	
 
	
 
	
 
	
 
	
613.2
	
 
	
 
	
 
	
547.8
	
 
	
 
	
 
	
524.4
	
 

	
Operation and maintenance other
expense
	
 
	
 
	
 
	
 
	
22.7
	
 
	
 
	
 
	
29.5
	
 
	
 
	
 
	
12.5
	
 

	
Depreciation and
amortization
	
 
	
 
	
 
	
 
	
349.0
	
 
	
 
	
 
	
315.3
	
 
	
 
	
 
	
291.8
	
 

	
Taxes, other than
income
	
 
	
 
	
 
	
 
	
207.4
	
 
	
 
	
 
	
195.0
	
 
	
 
	
 
	
184.7
	
 

	
Total expenses
	
 
	
 
	
 
	
 
	
2,181.4
	
 
	
 
	
 
	
2,061.0
	
 
	
 
	
 
	
1,900.5
	
 

	
Income from operations
	
 
	
 
	
 
	
 
	
562.1
	
 
	
 
	
 
	
505.4
	
 
	
 
	
 
	
454.6
	
 

	
Other income (expense)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Allowance for other funds used
during construction
	
 
	
 
	
 
	
 
	
17.4
	
 
	
 
	
 
	
10.5
	
 
	
 
	
 
	
6.3
	
 

	
Other income
	
 
	
 
	
 
	
 
	
3.4
	
 
	
 
	
 
	
0.5
	
 
	
 
	
 
	
1.8
	
 

	
Total other income
	
 
	
 
	
 
	
 
	
20.8
	
 
	
 
	
 
	
11.0
	
 
	
 
	
 
	
8.1
	
 

	
Interest charges
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Interest expense
	
 
	
 
	
 
	
195.1
	
 
	
 
	
176.4
	
 
	
 
	
 
	
165.0
	
 

	
Allowance for borrowed funds
used during construction
	
 
	
 
	
 
	
 
	
(8.7
	
)
	
 
	
 
	
(5.3
	
)
	
 
	
 
	
(3.6
	
)

	
Total interest charges
	
 
	
 
	
 
	
 
	
186.4
	
 
	
 
	
 
	
171.1
	
 
	
 
	
 
	
161.4
	
 

	
Income from continuing operations
before provision
    for
income taxes
	
 
	
 
	
 
	
 
	
396.5
	
 
	
 
	
 
	
345.3
	
 
	
 
	
 
	
301.3
	
 

	
Provision for income
taxes
	
 
	
 
	
 
	
 
	
155.3
	
 
	
 
	
 
	
138.9
	
 
	
 
	
 
	
112.6
	
 

	
Net income from continuing
operations
	
 
	
 
	
 
	
 
	
241.2
	
 
	
 
	
 
	
206.4
	
 
	
 
	
 
	
188.7
	
 

	
Discontinued operations
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Income (loss) from discontinued
operations
	
 
	
 
	
 
	
 
	
(106.3
	
)
	
 
	
 
	
(125.4
	
)
	
 
	
 
	
5.2
	
 

	
Provision (benefit) for income
taxes
	
 
	
 
	
 
	
 
	
(38.6
	
)
	
 
	
 
	
(49.4
	
)
	
 
	
 
	
(3.8
	
)

	
Income (loss) from discontinued
operations, net
	
 
	
 
	
 
	
 
	
(67.7
	
)
	
 
	
 
	
(76.0
	
)
	
 
	
 
	
9.0
	
 

	
Net income
	
 
	
 
	
 
	
$
	
173.5
	
 
	
 
	
$
	
130.4
	
 
	
 
	
$
	
197.7
	
 

	
Average common shares
outstanding
	
 
	
– Basic
	
 
	
 
	
233.1
	
 
	
 
	
 
	
223.1
	
 
	
 
	
 
	
215.0
	
 

	
 
	
 
	
– Diluted
	
 
	
 
	
234.5
	
 
	
 
	
 
	
223.7
	
 
	
 
	
 
	
215.5
	
 

	
Earnings per share from continuing
operations
	
 
	
– Basic
	
 
	
$
	
1.03
	
 
	
 
	
$
	
0.92
	
 
	
 
	
$
	
0.88
	
 

	
 
	
 
	
– Diluted
	
 
	
$
	
1.03
	
 
	
 
	
$
	
0.92
	
 
	
 
	
$
	
0.88
	
 

	
Earnings per share from discontinued
operations
	
 
	
– Basic
	
 
	
$
	
(0.29
	
)
	
 
	
$
	
(0.34
	
)
	
 
	
$
	
0.04
	
 

	
 
	
 
	
– Diluted
	
 
	
$
	
(0.29
	
)
	
 
	
$
	
(0.34
	
)
	
 
	
$
	
0.04
	
 

	
Earnings per share
	
 
	
– Basic
	
 
	
$
	
0.74
	
 
	
 
	
$
	
0.58
	
 
	
 
	
$
	
0.92
	
 

	
 
	
 
	
– Diluted
	
 
	
$
	
0.74
	
 
	
 
	
$
	
0.58
	
 
	
 
	
$
	
0.92
	
 

	
Dividends paid per common share
outstanding
	
 
	
 
	
 
	
$
	
0.90
	
 
	
 
	
$
	
0.88
	
 
	
 
	
$
	
0.88
	
 




Amounts shown include reclassifications to
reflect discontinued operations as discussed in Note 19. 

The accompanying notes are an integral part of
the consolidated financial statements. 
  

 

74


 TECO ENERGY, INC. 


Consolidated Statements of Comprehensive Income 
  


	
 (millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
For the years ended Dec.
31,
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Net income
	
 
	
$
	
173.5
	
 
	
 
	
$
	
130.4
	
 
	
 
	
$
	
197.7
	
 

	
Other comprehensive income (loss),
net of tax
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Gain on cash flow
hedges
	
 
	
 
	
3.5
	
 
	
 
	
 
	
0.7
	
 
	
 
	
 
	
1.4
	
 

	
Amortization of unrecognized
benefit costs and other
	
 
	
 
	
2.1
	
 
	
 
	
 
	
(3.0
	
)
	
 
	
 
	
14.8
	
 

	
Change in benefit obligation due
to valuation
	
 
	
 
	
(9.8
	
)
	
 
	
 
	
8.0
	
 
	
 
	
 
	
0.0
	
 

	
Increase in unrecognized
postemployment costs
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(8.2
	
)
	
 
	
 
	
0.0
	
 

	
Recognized benefit costs due to
settlement
	
 
	
 
	
7.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.6
	
 

	
Other comprehensive income
(loss), net of tax
	
 
	
 
	
3.5
	
 
	
 
	
 
	
(2.5
	
)
	
 
	
 
	
17.8
	
 

	
Comprehensive income
	
 
	
$
	
177.0
	
 
	
 
	
$
	
127.9
	
 
	
 
	
$
	
215.5
	
 




The accompanying notes are an integral part of
the consolidated financial statements. 
  

 
  

75


 TECO ENERGY, INC. 

Consolidated
 Statements of Cash Flows 
  
 
	
 (millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
For the years ended Dec.
31,
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Cash flows from operating
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net income
	
 
	
$
	
173.5
	
 
	
 
	
$
	
130.4
	
 
	
 
	
$
	
197.7
	
 

	
Adjustments to reconcile net
income to net cash from operating activities:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Depreciation and
amortization
	
 
	
 
	
350.2
	
 
	
 
	
 
	
341.9
	
 
	
 
	
 
	
329.5
	
 

	
Deferred income taxes and
investment tax credits
	
 
	
 
	
117.5
	
 
	
 
	
 
	
89.4
	
 
	
 
	
 
	
110.1
	
 

	
Allowance for other funds used
during construction
	
 
	
 
	
(17.4
	
)
	
 
	
 
	
(10.5
	
)
	
 
	
 
	
(6.3
	
)

	
Non-cash stock
compensation
	
 
	
 
	
13.1
	
 
	
 
	
 
	
12.7
	
 
	
 
	
 
	
13.5
	
 

	
Loss (gain) on disposals of
business/assets
	
 
	
 
	
13.2
	
 
	
 
	
 
	
(0.2
	
)
	
 
	
 
	
(1.6
	
)

	
Deferred recovery
clauses
	
 
	
 
	
26.4
	
 
	
 
	
 
	
(15.2
	
)
	
 
	
 
	
(6.2
	
)

	
Asset impairment
	
 
	
 
	
78.6
	
 
	
 
	
 
	
115.9
	
 
	
 
	
 
	
0.0
	
 

	
Receivables, less allowance for
uncollectibles
	
 
	
 
	
36.0
	
 
	
 
	
 
	
(36.6
	
)
	
 
	
 
	
(4.5
	
)

	
Inventories
	
 
	
 
	
(22.6
	
)
	
 
	
 
	
12.8
	
 
	
 
	
 
	
1.1
	
 

	
Prepayments and other current
assets
	
 
	
 
	
(8.0
	
)
	
 
	
 
	
2.8
	
 
	
 
	
 
	
(2.2
	
)

	
Taxes accrued
	
 
	
 
	
(15.9
	
)
	
 
	
 
	
1.1
	
 
	
 
	
 
	
1.4
	
 

	
Interest accrued
	
 
	
 
	
(3.6
	
)
	
 
	
 
	
7.3
	
 
	
 
	
 
	
(1.3
	
)

	
Accounts payable
	
 
	
 
	
(61.6
	
)
	
 
	
 
	
23.4
	
 
	
 
	
 
	
35.9
	
 

	
Other
	
 
	
 
	
(69.8
	
)
	
 
	
 
	
(10.4
	
)
	
 
	
 
	
(8.5
	
)

	
Cash flows from operating
activities
	
 
	
 
	
609.6
	
 
	
 
	
 
	
664.8
	
 
	
 
	
 
	
658.6
	
 

	
Cash flows from investing
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Capital expenditures
	
 
	
 
	
(739.7
	
)
	
 
	
 
	
(703.8
	
)
	
 
	
 
	
(526.1
	
)

	
Purchase of NMGI, net of cash
acquired
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(751.5
	
)
	
 
	
 
	
0.0
	
 

	
Net proceeds from sales of
business/assets
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
4.3
	
 

	
Other investments
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
(7.9
	
)
	
 
	
 
	
0.0
	
 

	
Cash flows used in investing
activities
	
 
	
 
	
(740.0
	
)
	
 
	
 
	
(1,463.0
	
)
	
 
	
 
	
(521.8
	
)

	
Cash flows from financing
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Dividends paid
	
 
	
 
	
(211.7
	
)
	
 
	
 
	
(199.2
	
)
	
 
	
 
	
(191.2
	
)

	
Proceeds from the sale of common
stock
	
 
	
 
	
7.3
	
 
	
 
	
 
	
302.3
	
 
	
 
	
 
	
6.7
	
 

	
Proceeds from long-term debt
issuance
	
 
	
 
	
499.7
	
 
	
 
	
 
	
563.6
	
 
	
 
	
 
	
0.0
	
 

	
Repayment of long-term
debt/Purchase in lieu of redemption
	
 
	
 
	
(274.5
	
)
	
 
	
 
	
(83.3
	
)
	
 
	
 
	
(51.6
	
)

	
Change in short-term
debt
	
 
	
 
	
108.0
	
 
	
 
	
 
	
55.0
	
 
	
 
	
 
	
84.0
	
 

	
Cash flows from/(used in)
financing activities
	
 
	
 
	
128.8
	
 
	
 
	
 
	
638.4
	
 
	
 
	
 
	
(152.1
	
)

	
Net decrease in cash and cash
equivalents
	
 
	
 
	
(1.6
	
)
	
 
	
 
	
(159.8
	
)
	
 
	
 
	
(15.3
	
)

	
Cash and cash equivalents at
beginning of the year
	
 
	
 
	
25.4
	
 
	
 
	
 
	
185.2
	
 
	
 
	
 
	
200.5
	
 

	
Cash and cash equivalents at
end of the year
	
 
	
$
	
23.8
	
 
	
 
	
$
	
25.4
	
 
	
 
	
$
	
185.2
	
 

	
Supplemental disclosure of cash flow
information
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Cash paid during the year
for:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Interest
	
 
	
$
	
179.6
	
 
	
 
	
$
	
161.3
	
 
	
 
	
$
	
161.0
	
 

	
Income taxes paid
	
 
	
$
	
14.5
	
 
	
 
	
$
	
2.9
	
 
	
 
	
$
	
1.8
	
 

	
Supplemental disclosure of non-cash
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Debt assumed in NMGI
acquisition
	
 
	
$
	
0.0
	
 
	
 
	
$
	
200.0
	
 
	
 
	
$
	
0.0
	
 

	
Change in accrued capital
expenditures
	
 
	
$
	
8.0
	
 
	
 
	
$
	
13.3
	
 
	
 
	
$
	
4.7
	
 




The accompanying notes are an integral part of
the consolidated financial statements. 
  

 
  

76


 TECO ENERGY, INC. 


Consolidated Statements of Capital 
  
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Accumulated
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Additional
	
 
	
 
	
 
	
 
	
 
	
 
	
Other
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
Common
	
 
	
 
	
Paid in
	
 
	
 
	
Retained
	
 
	
 
	
Comprehensive
	
 
	
 
	
Total
	
 

	
(millions)
	
 
	
Shares
	
 
	
 
	
Stock
	
 
	
 
	
Capital
	
 
	
 
	
Earnings
	
 
	
 
	
Income
(Loss)
	
 
	
 
	
Capital
	
 

	
Balance, Dec. 31, 2012
	
 
	
 
	
216.6
	
 
	
 
	
$
	
216.6
	
 
	
 
	
$
	
1,564.5
	
 
	
 
	
$
	
541.7
	
 
	
 
	
$
	
(31.0
	
)
	
 
	
$
	
2,291.8
	
 

	
Net income
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
197.7
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
197.7
	
 

	
Other comprehensive income, after
tax
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
17.8
	
 
	
 
	
 
	
17.8
	
 

	
Common stock issued
	
 
	
 
	
0.7
	
 
	
 
	
 
	
0.7
	
 
	
 
	
 
	
5.2
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
5.9
	
 

	
Cash dividends declared
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
(191.2
	
)
	
 
	
 
	
 
	
 
	
 
	
 
	
(191.2
	
)

	
Stock compensation expense
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
13.5
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
13.5
	
 

	
Restricted
stock—dividends
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
1.0
	
 
	
 
	
 
	
0.1
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
1.1
	
 

	
Tax short fall—stock
compensation
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
(2.9
	
)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
(2.9
	
)

	
Balance, Dec. 31, 2013
	
 
	
 
	
217.3
	
 
	
 
	
$
	
217.3
	
 
	
 
	
$
	
1,581.3
	
 
	
 
	
$
	
548.3
	
 
	
 
	
$
	
(13.2
	
)
	
 
	
$
	
2,333.7
	
 

	
Net income
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
130.4
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
130.4
	
 

	
Other comprehensive income, after
tax
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
(2.5
	
)
	
 
	
 
	
(2.5
	
)

	
Common stock issued
	
 
	
 
	
17.6
	
 
	
 
	
 
	
17.6
	
 
	
 
	
 
	
283.2
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
300.8
	
 

	
Cash dividends declared
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
(199.2
	
)
	
 
	
 
	
 
	
 
	
 
	
 
	
(199.2
	
)

	
Stock compensation expense
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
12.7
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
12.7
	
 

	
Restricted
stock—dividends
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
1.1
	
 
	
 
	
 
	
0.1
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
1.2
	
 

	
Tax short fall—stock
compensation
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
(2.4
	
)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
(2.4
	
)

	
Balance, Dec. 31, 2014
	
 
	
 
	
234.9
	
 
	
 
	
$
	
234.9
	
 
	
 
	
$
	
1,875.9
	
 
	
 
	
$
	
479.6
	
 
	
 
	
$
	
(15.7
	
)
	
 
	
$
	
2,574.7
	
 

	
Net income
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
173.5
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
173.5
	
 

	
Other comprehensive loss, after
tax
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
3.5
	
 
	
 
	
 
	
3.5
	
 

	
Common stock issued
	
 
	
 
	
0.4
	
 
	
 
	
 
	
0.4
	
 
	
 
	
 
	
4.6
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
5.0
	
 

	
Cash dividends declared
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
(211.7
	
)
	
 
	
 
	
 
	
 
	
 
	
 
	
(211.7
	
)

	
Stock compensation expense
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
13.1
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
13.1
	
 

	
Restricted
stock—dividends
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
1.3
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
1.3
	
 

	
Tax short fall—stock
compensation
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
(0.4
	
)

	
Balance, Dec. 31, 2015
	
 
	
 
	
235.3
	
 
	
 
	
$
	
235.3
	
 
	
 
	
$
	
1,894.5
	
 
	
 
	
$
	
441.4
	
 
	
 
	
$
	
(12.2
	
)
	
 
	
$
	
2,559.0
	
 




 

The accompanying notes are an integral part of the
consolidated financial statements. 
  

 
  

77


 TECO ENERGY, INC. 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
  
  

1. Significant Accounting Policies 

Description of the Business

TECO Energy is a holding company for regulated utilities and
other businesses. TECO Energy currently owns no operating assets but holds all of the common stock of TEC and, through its subsidiary, NMGI, owns NMGC. 

TEC, a Florida corporation and TECO Energy’s largest
subsidiary, has two business segments. Its Tampa Electric division provides retail electric services in West Central Florida, and PGS, the gas division of TEC, is engaged in the purchase, distribution and sale
of natural gas for residential, commercial, industrial and electric power generation customers in Florida. 

NMGC, a Delaware corporation and wholly owned subsidiary of
NMGI, was acquired by the company on Sept. 2, 2014. NMGC is engaged in the purchase, distribution and sale of natural gas for residential, commercial and industrial customers in New Mexico. 

On Sept. 21, 2015, TECO Diversified sold all of its ownership
interest in TECO Coal.  TECO Coal, a Kentucky LLC, had subsidiaries which owned assets in Eastern Kentucky, Tennessee and Virginia. These entities owned mineral rights, owned or operated surface and underground mines and owned interests in
coal processing and loading facilities. See Note 19 for further information.

On Sept. 4, 2015, TECO Energy and Emera entered into the
Merger Agreement. Upon closing, TECO Energy will become a wholly owned indirect subsidiary of Emera. See Note 21 for further information.

The company’s significant accounting policies are as
follows: 
 Principles of Consolidation and Basis of Presentation

 The consolidated financial statements include the accounts
of TECO Energy and its majority-owned subsidiaries.  Intercompany balances and intercompany transactions have been eliminated in consolidation. 

The consolidated financial statements include NMGI and NMGC from
the acquisition date of Sept. 2, 2014 through Dec. 31, 2015 (see Note 21). In addition, all periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for
TECO Coal and certain charges at Parent and TECO Diversified that directly related to TECO Coal and TECO Guatemala (see Note 19). 

For entities that are determined to meet the definition of a VIE,
the company obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If the company is determined to be the primary beneficiary, then the VIE is consolidated and a noncontrolling interest is recognized for any
other third-party interests. If the company is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in the company consolidating entities in which it has
less than a 50% equity investment and deconsolidating entities in which it has a majority equity interest (see Note 18). 

Through its centralized services company subsidiary, TSI, TECO
Energy provides its operating subsidiaries with specialized services at cost, including information technology, procurement, human resources, legal, risk management, financial, and administrative services. TSI’s costs are directly charged or
allocated to the applicable operating subsidiaries using cost-causative allocation methods. Corporate governance-type costs that cannot be directly assigned are allocated based on a Modified Massachusetts Formula, which is a method that utilizes a
combination of total operating revenues, total operating assets and net income as the basis of allocation. TSI has losses related to taxes which are not distributed to affiliate companies.  The results of TECO Energy’s corporate
operations, consisting of TSI tax losses and non-allocable Parent costs, are included within the “Other” reportable segment (see Note 14).

Use of Estimates 

The use of estimates is inherent in the preparation of financial
statements in accordance with U.S. GAAP. Actual results could differ from these estimates. 

Cash Equivalents 

Cash equivalents are highly liquid, high-quality investments
purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments. 

Property, Plant and Equipment 

          

78


           Property, plant and equipment is stated at original cost, which includes labor, material, applicable taxes, overhead and AFUDC. Tampa Electric, PGS and NMGC, concurrent with a planned major maintenance outage or with new construction, capitalize the cost of adding or replacing retirement units-of-property in conformity with the regulations of FERC, FPSC and NMPRC, as applicable. The cost of maintenance, repairs and replacement of minor items of property is expensed as incurred. 

In general, when regulated depreciable property is retired or
disposed, its original cost less salvage is charged to accumulated depreciation. For other property dispositions, the cost and accumulated depreciation are removed from the balance sheet and a gain or loss is recognized.

Depreciation 

Tampa Electric, PGS and NMGC compute depreciation and
amortization for electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods: 
 
	  
	 ●
	 the group
remaining life method, approved by the FPSC or NMPRC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property; 



 
	  
	 ●
	 the amortizable
life method, approved by the FPSC or NMPRC, is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. 




The provision for total regulated utility plant in service,
expressed as a percentage of the original cost of depreciable property, was 3.7% for 2015, 3.6% for 2014 and 3.7% for 2013. Construction work in progress is not depreciated until the asset is completed or placed in service. 

On Sept. 11, 2013, the FPSC unanimously voted to approve a
stipulation and settlement agreement between Tampa Electric and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric began using a 15-year amortization period for all computer software retroactive
to Jan. 1, 2013. 
 Other TECO Energy subsidiaries compute
depreciation primarily by the straight-line method at annual rates that amortize the original cost, less net salvage value, of depreciable property over the following estimated useful lives: 

 
 
	
Asset
	
 
	
Estimated Useful
Lives

	
Building and improvements
	
 
	
40 years

	
 
	
 
	
 

	
Office equipment and
furniture
	
 
	
4 - 7
years

	
 
	
 
	
 

	
Computer software
	
 
	
3 - 15
years



 Total depreciation expense
for the years ended Dec. 31, 2015, 2014 and 2013 was $339.1 million, $307.5 million and $285.6 million, respectively. 

Allowance for Funds Used During Construction 

AFUDC is a non-cash credit to income with a corresponding charge
to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate Tampa Electric’s AFUDC is revised periodically to reflect significant changes
in Tampa Electric’s cost of capital. Tampa Electric’s rate was 8.16% for May 2009 through December 2013. In March 2014, the rate was revised to 6.46% effective Jan. 1, 2014. NMGC’s rate used to calculate its AFUDC in 2015 and 2014
was 4.41% and 4.92%, respectively. Total AFUDC for the years ended Dec. 31, 2015, 2014 and 2013 was $26.1 million, $15.8 million and $9.9 million, respectively. 

Inventory 

TEC and NMGC value materials, supplies and fossil fuel inventory
(coal, oil or natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess
of market) will be recovered with a normal profit upon sale in the ordinary course of business. 

79


  
 
	
Fuel Inventory
	
 
	
Dec. 31,
	
 
	
 
	
Dec. 
31,
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 

	
TEC
	
 
	
$
	
105.6
	
 
	
 
	
$
	
85.2
	
 

	
NMGC
	
 
	
 
	
7.8
	
 
	
 
	
 
	
11.2
	
 

	
Total
	
 
	
$
	
113.4
	
 
	
 
	
$
	
96.4
	
 




TECO Coal inventories were stated at the lower of cost, computed
on the first-in, first-out method, or net realizable value. Parts and supplies inventories were stated at the lower of cost or market on an average cost basis. TECO Coal’s inventory was classified within Assets held for sale at Dec. 31, 2014.

 Regulatory Assets and Liabilities 

Tampa Electric, PGS and NMGC are subject to accounting guidance
for the effects of certain types of regulation (see Note 3 for additional details). 

Deferred Income Taxes 

TECO Energy uses the asset and liability method to determine
deferred income taxes. Under the asset and liability method, the company estimates its current tax exposure and assesses the temporary differences resulting from differences in the treatment of items, such as depreciation, for financial statement
and tax purposes. These differences are reported as deferred taxes, measured at current rates, in the consolidated financial statements. Management reviews all reasonably available current and historical information, including forward-looking
information, to determine if it is more likely than not that some or all of the deferred tax assets will not be realized. If management determines that it is likely that some or all of deferred tax assets will not be realized, then a valuation
allowance is recorded to report the balance at the amount expected to be realized (see Note 4 for additional details). 

Investment Tax Credits 

ITCs have been recorded as deferred credits and are being
amortized as reductions to income tax expense over the service lives of the related property. 

Goodwill 

Goodwill is calculated as the excess of the
purchase price of an acquired entity over the estimated fair values of assets acquired and liabilities assumed at the acquisition date. Under the accounting guidance for goodwill, goodwill is subject to an annual assessment for impairment at the
reporting unit level. See Note 20 for further detail.

Employee Postretirement Benefits 

The company sponsors a defined benefit retirement plan and other
postretirement benefits.  The measurement of the plans are based on several statistical and other factors, including those that attempt to anticipate future events.  See Note 5 for further
detail.
 Revenue Recognition 

TECO Energy recognizes revenues consistent with accounting
standards for revenue recognition. Except as discussed below, TECO Energy and its subsidiaries recognize revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred
to the buyer. 
 The regulated utilities’ retail
businesses and the prices charged to customers are regulated by the FPSC or NMPRC, as applicable. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant
regulatory matters and the applicability of the accounting guidance for certain types of regulation to the company. 

Revenues for energy marketing operations at TECO EnergySource,
Inc. are presented on a net basis in accordance with the accounting guidance for reporting revenue gross as a principal versus net as an agent and recognition and reporting of gains and losses on energy trading contracts to reflect the nature of the
contractual relationships with customers and suppliers. Accordingly, for the years ended Dec. 31, 2015, 2014 and 2013, total costs of $3.1 million, $4.3 million and $23.1 million, respectively, consisting primarily of natural gas purchased, were
netted against revenues in the “Revenues-Unregulated” caption on the Consolidated Statements of Income. 

Revenues for TECO Coal shipments, both domestic and
international, were recognized when title and risk of loss transfer to the customer. They were included in “Income (loss) from discontinued operations” on the Consolidated Statements of Income.

80


 Revenues and Cost Recovery 

Revenues include amounts resulting from cost recovery clauses at
the regulated utilities (Tampa Electric, PGS and NMGC) which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, gas storage,
interstate pipeline capacity and conservation costs for PGS and NMGC. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into
account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets. 

Certain other costs incurred by the regulated utilities are
allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide
for a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2015 and 2014, unbilled revenues of $81.1 million and $86.6 million, respectively, are included in the “Receivables” line
item on TECO Energy’s Consolidated Balance Sheets. 

Tampa Electric purchases power on a regular basis primarily to
meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $78.9 million, $71.4 million and $64.7 million, for the years ended Dec. 31, 2015, 2014 and 2013, respectively. The prudently
incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost recovery clause. 

Receivables and Allowance for Uncollectible Accounts 

Receivables consist of services billed to
residential, commercial, industrial and other customers. An allowance for uncollectible accounts is established based on the regulated utilities’ collection experience. Circumstances that could affect Tampa Electric’s, PGS’s and
NMGC’s estimates of uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be
uncollectible. 
 TECO
Coal’s receivables, which were classified within Assets held for sale at Dec. 31, 2014, consisted of coal sales billed to industrial and utility customers. An allowance for uncollectible accounts was established based on TECO Coal’s
collection experience. Circumstances that could have affected TECO Coal’s estimates of uncollectible receivables included customer credit issues and general economic conditions. Accounts were written off once they were determined to be
uncollectible.
 Accounting for Excise Taxes, Franchise Fees and
Gross Receipts 
 Tampa Electric and PGS are allowed to recover
certain costs on a dollar-for-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Statements
of Income. Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $116.9 million, $113.9 million
and $108.5 million for the years ended Dec. 31, 2015, 2014 and 2013, respectively. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross
basis.  Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statement of Income. 

TECO Energy’s excise taxes were accrued as an expense and
reconciled to the actual cash payment of excise taxes. As general expenses, they were not specifically recovered through revenues. Excise taxes paid by the regulated utilities were not material and were expensed when incurred. 

Deferred Charges and Other Assets 

Deferred charges and other assets consist primarily of a
contribution made by the company in order to fully fund its SERP obligation (see Note 5), unamortized debt issuance costs and assets related to NMGC’s ROW. 

Debt issuance costs – The
company capitalizes the external costs of obtaining debt financing and amortizes such costs over the life of the related debt on a straight-line basis that approximates the effective interest method. These amounts are reflected in “Interest
expense” on TECO Energy’s Consolidated Statements of Income. 

NMGC’s ROW- Gross assets
related to NMGC’s ROW were $41 million at Dec. 31, 2015 and 2014. The related accumulated amortization was $9 million and $8 million at Dec. 31, 2015 and 2014, respectively. The company amortizes costs related to obtaining NMGC’s ROW to
“Depreciation and amortization expense” on TECO Energy’s Consolidated Statements of Income.

81


 Deferred Credits and Other Liabilities 

Deferred credits and other liabilities primarily include the
accrued postretirement and pension liabilities (see Note 5), MGP environmental remediation liability (see Note 12), and medical and general liability claims incurred but
not reported. The company and its subsidiaries have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. The company estimates its liabilities
for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2015 and 2014
ranged from 2.92% to 4.00% and 2.71% to 4.00%, respectively. 

Stock-Based Compensation 

TECO Energy accounts for its stock-based compensation in
accordance with the accounting guidance for share-based payment. Under the provisions of this guidance, stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense
over the employee’s or director’s requisite service period (generally the vesting period of the equity grant). See Note 9 for more information on share-based payments. 

Cash Flows Related to Derivatives and Hedging Activities 

The company classifies cash inflows and outflows related to
derivative and hedging instruments in the appropriate cash flow sections associated with the item being hedged. In the case of diesel fuel swaps, which are used to mitigate the fluctuations in the price of diesel fuel, the cash inflows and outflows
are included in the operating section. For natural gas and ongoing interest rate swaps, the cash inflows and outflows are included in the operating section. For interest rate swaps that settle coincident with the debt issuance, the cash inflows and
outflows are treated as premiums or discounts and included in the financing section of the Consolidated Statements of Cash Flows.

Reclassifications

Certain reclassifications were made to prior year amounts to
conform to current period presentation. None of the reclassifications affected TECO Energy’s net income in any period. 
  

2. New Accounting Pronouncements 

Revenue from Contracts with Customers 

In May 2014, the FASB issued guidance regarding the accounting
for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods
or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In addition, the guidance will require additional disclosures regarding the nature, amount,
timing and uncertainty of revenue arising from contracts with customers.  This guidance will be effective for the company beginning in 2018, with early adoption permitted in 2017, and will allow for either full retrospective adoption or
modified retrospective adoption. The company expects to adopt this guidance effective Jan. 1, 2018, and is continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does
not expect the impact to be significant. 
 Presentation of Debt
Issuance Costs 
 In April 2015, the FASB issued guidance
regarding the presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a
deferred charge (i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements
as an asset, regardless of whether a balance is outstanding. This guidance will be effective for the company beginning in 2016 and will be required to be applied on a retrospective basis for all periods presented. As of Dec. 31, 2015, $27.7 million
of debt issuance costs, which does not include costs for line-of-credit arrangements, are included in the “Deferred charges and other assets” line item on the company’s Consolidated Condensed Balance Sheet. The guidance will not
affect the company’s results of operations or cash flows.
  

Disclosure of Investments Using Net Asset Value 

In May 2015, the FASB issued guidance stating that investments
for which fair value is measured using the NAV per share practical expedient should not be categorized in the fair value hierarchy but should be provided to reconcile to total investments on the balance sheet. In addition, the guidance clarifies
that a plan sponsor’s pension assets are eligible to be measured at NAV as a practical expedient and that those investments should also not be categorized in the fair value hierarchy. TECO Energy’s pension plan has such investments as
disclosed in Note 5. This standard will be required for the company beginning in 2016. As early adoption is permitted, the company adopted the standard for its 2015 fiscal year and applied the presentation on a
retrospective basis for all periods presented 

82


 in the pension plan assets fair value hierarchy. The guidance did not affect the company’s balance sheets, results of operations or cash flows.

Measurement Period Adjustments in Business Combinations

In September 2015, the FASB issued guidance requiring an acquirer
in a business combination to account for measurement period adjustments during the reporting period in which the adjustment is determined, rather than retrospectively. When measurements are incomplete as of the end of the reporting period covering a
business combination, an acquirer may record adjustments to provisional amounts based on events and circumstances that existed as of the acquisition date during the period from the date of acquisition to the date information is received, not to
exceed one year. The guidance will be effective for the company beginning in 2016 and will be applied prospectively. The guidance will not affect the company’s current financial statements. However, the company will assess the potential impact
of the guidance on future acquisitions.
 Balance Sheet
Classification of Deferred Taxes
 In November 2015, the FASB
issued guidance regarding the classification of deferred taxes on the balance sheet. To simplify the presentation of deferred income taxes, the new guidance requires that all deferred tax assets and liabilities be classified as noncurrent on the
balance sheet rather than be classified as current or noncurrent under current guidance. The guidance will be required for the company beginning in 2017 and may be applied on a prospective or retrospective basis. As early adoption is permitted, the
company adopted the standard in December 2015 and applied the balance sheet presentation on a prospective basis. Therefore, prior period balance sheets were not retrospectively adjusted. The guidance did not affect the company’s results of
operations or cash flows.
  

Recognition and Measurement of Financial Assets and Financial
Liabilities
 In January 2016, the FASB issued guidance related
to accounting for financial instruments, including equity investments, financial liabilities under the fair value option, valuation allowances for available-for-sale debt securities, and the presentation and disclosure requirements for financial
instruments. The company does not have equity investments or available-for-sale debt securities and it does not record financial liabilities under the fair value option. However, it is evaluating the impact of the adoption of this guidance on its
financial statement disclosures, including those regarding the fair value of its long-term debt, but it does not expect the impact to be significant. The guidance will be effective for the company beginning in 2018.

 

Leases

 In February 2016, the FASB
issued guidance regarding the accounting for leases. The objective is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with a lease term of more than 12
months. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet.
The dual model for income statement classification is maintained under the new guidance and as a result is expected to limit the impact of the changes on the income statement and statement of cash flows. This guidance will be effective for the
company beginning in 2019, with early adoption permitted, and will be applied using a modified retrospective approach. The company is currently evaluating the impacts of the adoption of the guidance on its financial statements.

 
  

3. Regulatory

Tampa Electric’s retail business and PGS are regulated by
the FPSC. Tampa Electric is also subject to regulation by the FERC. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety,
accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus
a reasonable return on invested capital. 
 NMGC is subject to
regulation by the NMPRC. The NMPRC has jurisdiction over the regulatory matters related, directly and indirectly, to NMGC providing service to its customers, including, among other things, rates, accounting procedures, securities issuances, and
standards of service. NMGC must follow certain accounting guidance that pertains specifically to entities that are subject to such regulation. Comparable to the FPSC, the NMPRC sets rates at a level that allows utilities such as NMGC to collect
total revenues (revenue requirement) equal to their cost of providing service, plus a reasonable return on invested capital. 

Base Rates-Tampa Electric 

Tampa Electric’s results for the first ten months of 2013
reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure and 2009 13-month average rate base
of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an additional $33.5
million. 
 83


 Tampa Electric’s results for 2015, 2014 and the last two months of 2013 reflect the results of a Stipulation and Settlement Agreement entered on Sept. 6, 2013, between Tampa Electric and all of the intervenors in its Tampa Electric division base rate proceeding, which resolved all matters in Tampa Electric’s 2013 base rate proceeding. On Sept. 11, 2013, the FPSC
unanimously voted to approve the stipulation and settlement agreement.

This agreement provided for the following revenue increases:
$57.5 million effective Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that the expansion of
Tampa Electric’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to
10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective no sooner than Jan. 1, 2018), unless its earned ROE were to fall below
9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than Tampa Electric could
seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric began using a 15-year amortization period for all computer software retroactive to Jan. 1,
2013.
 Tampa Electric is also subject to regulation by the
FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices. 

Tampa Electric Storm Damage Cost Recovery

Prior to the above-mentioned stipulation and settlement
agreement, Tampa Electric was accruing $8.0 million annually to a FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to
destructive acts of nature. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa
Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve
remained $56.1 million at both Dec. 31, 2015 and 2014.  

Base Rates-PGS

PGS’s base rates were established in May 2009 and reflect
an ROE of 10.75%, which is the middle of a range between 9.75% to 11.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital, on an allowed rate base of $560.8 million. 

Base Rates-NMGC

In March 2011, NMGC filed an application with the NMPRC seeking
authority to increase NMGC’s base rates by approximately $34.5 million on a normalized annual basis. In September 2011, the parties to the base rate proceeding entered into a settlement. The parties filed an unopposed stipulation reflecting
the terms of that settlement with the NMPRC and the unopposed stipulation was approved by the NMPRC on Jan. 31, 2012, revising, among other things, base rates for all service provided on or after Feb. 1, 2012. The revised rates contained in the
NMPRC-approved settlement increased NMGC’s base rate revenue by approximately $21.5 million on a normalized annual basis. The monthly residential customer access fee increased from $9.59 to $11.50, with the remaining rate increase reflected in
changes to volumetric delivery charges. The parties stipulated that the NMPRC-approved revised rates would not increase again prior to July 31, 2013. Subsequently, as a condition of the August 2014 NMPRC order approving the TECO Energy
acquisition of NMGC, the rates were frozen at the approved 2012 levels until the end of 2017, as reported in Note 21. 

Regulatory Assets and Liabilities

Tampa Electric, PGS and NMGC apply the accounting standards for
regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in
fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them, when cost recovery is ordered over a period longer than a fiscal year; and the
advance recovery of expenditures for approved costs such as future storm damage or the future removal of property. All regulatory assets are recovered through the regulatory process. 

84


 Details of the regulatory assets and liabilities as of Dec. 31, 2015 and 2014 are presented in the following table: 

 
 
	
 
	
 
	
Dec. 31,
	
 
	
 
	
Dec. 31,
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Regulatory assets:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulatory tax asset (1)
	
 
	
$
	
74.7
	
 
	
 
	
$
	
69.2
	
 

	
Cost-recovery clauses - deferred
balances (2)
	
 
	
5.5
	
 
	
 
	
1.9
	
 

	
Cost-recovery clauses - offsets
to derivative liabilities (2)
	
 
	
 
	
26.5
	
 
	
 
	
 
	
43.2
	
 

	
Environmental remediation (3)
	
 
	
 
	
54.0
	
 
	
 
	
 
	
53.1
	
 

	
Postretirement benefits (4)
	
 
	
 
	
240.6
	
 
	
 
	
 
	
194.0
	
 

	
Deferred bond refinancing costs (5)
	
 
	
 
	
6.5
	
 
	
 
	
 
	
7.2
	
 

	
Debt basis adjustment (6)
	
 
	
 
	
17.5
	
 
	
 
	
 
	
20.9
	
 

	
Competitive rate adjustment (2)
	
 
	
 
	
2.6
	
 
	
 
	
 
	
2.8
	
 

	
Other
	
 
	
 
	
12.1
	
 
	
 
	
 
	
9.8
	
 

	
Total regulatory assets
	
 
	
 
	
440.0
	
 
	
 
	
 
	
402.1
	
 

	
Less: Current portion
	
 
	
 
	
44.8
	
 
	
 
	
 
	
53.6
	
 

	
Long-term regulatory
assets
	
 
	
$
	
395.2
	
 
	
 
	
$
	
348.5
	
 

	
Regulatory liabilities:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulatory tax
liability
	
 
	
$
	
7.9
	
 
	
 
	
$
	
6.9
	
 

	
Cost-recovery clauses (2)
	
 
	
 
	
55.9
	
 
	
 
	
 
	
25.9
	
 

	
Transmission and delivery storm
reserve
	
 
	
 
	
56.1
	
 
	
 
	
 
	
56.1
	
 

	
Accumulated reserve—cost
of removal (7)
	
 
	
 
	
679.9
	
 
	
 
	
 
	
695.2
	
 

	
Other
	
 
	
 
	
0.8
	
 
	
 
	
 
	
1.9
	
 

	
Total regulatory
liabilities
	
 
	
 
	
800.6
	
 
	
 
	
 
	
786.0
	
 

	
Less: Current portion
	
 
	
 
	
84.8
	
 
	
 
	
 
	
57.0
	
 

	
Long-term regulatory
liabilities
	
 
	
$
	
715.8
	
 
	
 
	
$
	
729.0
	
 




 
 
	 (1)
	 The regulatory tax asset is
primarily associated with the depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue
requirements. It will be recovered over the expected life of the related assets.  



 
	 (2)
	 These assets and liabilities are related to FPSC and NMPRC
clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or NMPRC, as applicable, on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities,
recovery occurs in the year following the settlement of the derivative position.



 
	 (3)
	 This asset is related to costs associated with environmental
remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the
expenditures related to remediation.



 
	 (4)
	 This asset is related to the deferred costs of postretirement
benefits. It is included in rate base and earns a rate of return as permitted by the FPSC or NMPRC, as applicable. It is amortized over the remaining service life of plan participants.



 
	 (5)
	 This asset represents the past costs associated with refinancing
debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments.




 
	 (6)
	 This asset represents the difference between the fair value and
pre-merger carrying amounts for NMGC’s long-term debt on the acquisition date. It does not earn a return and is not included in the regulatory capital structure. It is amortized over the term of the related debt
instrument.



 
	 (7)
	 This item represents the non-ARO cost of removal in the
accumulated reserve for depreciation.



  
  

4. Income Taxes 

Income Tax Expense

In 2015, 2014 and 2013, TECO Energy recorded net tax provisions
from continuing operations of $155.3 million, $138.9 million and $112.6 million, respectively. A majority of this provision is non-cash. TECO Energy has net operating losses that are being utilized to reduce its taxable income. As such, cash taxes
paid for income taxes as required for the alternative minimum tax, state income taxes and prior year audits in 2015, 2014 and 2013 were $14.5 million, $2.9 million and $1.8 million, respectively. 

85


 Income tax expense consists of the following: 

Income Tax Expense (Benefit)

  
 
	
 (millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
For the year ended Dec. 31,
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Continuing Operations
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Current income taxes
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Federal
	
 
	
$
	
(0.5
	
)
	
 
	
$
	
0.5
	
 
	
 
	
$
	
2.2
	
 

	
State
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Deferred income taxes
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Federal
	
 
	
 
	
133.2
	
 
	
 
	
 
	
111.0
	
 
	
 
	
 
	
98.8
	
 

	
State
	
 
	
 
	
21.1
	
 
	
 
	
 
	
27.7
	
 
	
 
	
 
	
11.9
	
 

	
Amortization of investment tax
credits
	
 
	
 
	
1.5
	
 
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
(0.3
	
)

	
Income tax expense from
continuing operations
	
 
	
 
	
155.3
	
 
	
 
	
 
	
138.9
	
 
	
 
	
 
	
112.6
	
 

	
Discontinued Operations
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Current income taxes
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Federal
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
State
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
(3.5
	
)

	
Deferred income taxes
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Federal
	
 
	
 
	
(34.7
	
)
	
 
	
 
	
(44.0
	
)
	
 
	
 
	
(0.3
	
)

	
State
	
 
	
 
	
(3.6
	
)
	
 
	
 
	
(5.0
	
)
	
 
	
 
	
0.0
	
 

	
Income tax expense from
discontinued operations
	
 
	
 
	
(38.6
	
)
	
 
	
 
	
(49.4
	
)
	
 
	
 
	
(3.8
	
)

	
Total income tax expense
	
 
	
$
	
116.7
	
 
	
 
	
$
	
89.5
	
 
	
 
	
$
	
108.8
	
 




During 2015, 2014 and 2013, TECO Energy increased its net
operating loss carryforward. 
 The reconciliation of the
federal statutory rate to the company’s effective income tax rate is as follows: 

Effective Income Tax Rate

  
 
	
 (millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
For the year ended Dec. 31,
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Income tax expense at the federal
statutory rate of 35%
	
 
	
$
	
138.8
	
 
	
 
	
$
	
120.9
	
 
	
 
	
$
	
105.5
	
 

	
Increase (decrease) due
to:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
State income tax, net of federal
income tax
	
 
	
 
	
13.6
	
 
	
 
	
 
	
17.0
	
 
	
 
	
 
	
7.5
	
 

	
Valuation allowance
	
 
	
 
	
0.1
	
 
	
 
	
 
	
0.9
	
 
	
 
	
 
	
0.0
	
 

	
Other
	
 
	
 
	
2.8
	
 
	
 
	
 
	
0.1
	
 
	
 
	
 
	
(0.4
	
)

	
Total income tax expense from
continuing operations
	
 
	
$
	
155.3
	
 
	
 
	
$
	
138.9
	
 
	
 
	
$
	
112.6
	
 

	
Income tax expense as a percent of
income from continuing operations,

   before income
taxes
	
 
	
 
	
39.2
	
%
	
 
	
 
	
40.2
	
%
	
 
	
 
	
37.4
	
%




For the three years presented, the overall effective tax rate on
continuing operations was higher than the 35% U.S. federal statutory rate primarily due to state income taxes. For 2015, the effective tax rate decreased as a result of a lower state consolidated tax adjustment, offset by a tax expense related to
stock-based compensation. 
 As discussed in Note 1, TECO Energy uses the asset and liability method to determine deferred income taxes. Based primarily on the reversal of deferred income tax liabilities and future earnings of the company’s utility
operations, management has determined that the net deferred tax assets recorded at Dec. 31, 2015 will be realized in future periods. 

86


 Deferred Income Taxes

The major components of the company’s deferred tax assets
and liabilities recognized are as follows: 
  
 
	
 (millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
As of Dec. 31,
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Deferred tax liabilities (1)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Property related
	
 
	
$
	
1,519.3
	
 
	
 
	
$
	
1,391.3
	
 

	
Pension
	
 
	
 
	
86.6
	
 
	
 
	
 
	
62.3
	
 

	
Total deferred tax
liabilities
	
 
	
 
	
1,605.9
	
 
	
 
	
 
	
1,453.6
	
 

	
Deferred tax assets (1)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Alternative minimum tax credit
carryforward
	
 
	
 
	
213.5
	
 
	
 
	
 
	
214.0
	
 

	
Loss and credit carryforwards (2)
	
 
	
 
	
637.5
	
 
	
 
	
 
	
566.7
	
 

	
Other postretirement
benefits
	
 
	
 
	
69.5
	
 
	
 
	
 
	
71.5
	
 

	
Other
	
 
	
 
	
117.5
	
 
	
 
	
 
	
159.6
	
 

	
Total deferred tax
assets
	
 
	
 
	
1,038.0
	
 
	
 
	
 
	
1,011.8
	
 

	
Valuation allowance (3)
	
 
	
 
	
(2.0
	
)
	
 
	
 
	
(4.6
	
)

	
Total deferred tax assets, net
of valuation allowance
	
 
	
 
	
1,036.0
	
 
	
 
	
 
	
1,007.2
	
 

	
Total deferred tax liability,
net
	
 
	
 
	
569.9
	
 
	
 
	
 
	
446.4
	
 

	
Less: Current portion of deferred
tax asset
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(72.8
	
)

	
Less: Long term portion of deferred
tax asset
	
 
	
 
	
(0.8
	
)
	
 
	
 
	
0.0
	
 

	
Long-term portion of deferred tax
liability, net
	
 
	
$
	
570.7
	
 
	
 
	
$
	
519.2
	
 





	 (1)
	 Certain property related assets and liabilities have been
netted. 



 
	 (2)
	 As a result of certain realization requirements of accounting
guidance, loss carryforwards do not include certain deferred tax assets as of Dec. 31, 2015 that arose directly from tax deductions related to equity compensation greater than compensation recognized for financial reporting. Stockholder’s
equity will be increased by $2.6 million when such deferred tax assets are ultimately realized. The company uses tax law ordering when determining when excess tax benefits have been realized.



 
	 (3)
	 During 2015, the valuation allowance related to discontinued
operations decreased from $3.6 million to $1.0 million. 




At Dec. 31, 2015, the company had cumulative unused federal,
Florida and New Mexico NOLs for income tax purposes of $1,728.6 million, $675.2 million and $85.8 million, respectively, expiring at various times between 2025 and 2034, with the majority expiring in 2025. The federal NOL includes $121.6 million of
NOLs due to the 2014 acquisition of NMGI. In addition, the company has unused general business credits of $5.8 million expiring between 2026 and 2034. During 2015, the company’s available AMT credit carryforward decreased from $214.0 million
to $213.5 million. The AMT credit may be used indefinitely to reduce federal income taxes. 

The company’s consolidated balance sheet reflects loss
carryforwards excluding amounts resulting from excess stock-based compensation. Accordingly, such losses from excess stock-based compensation tax deductions are accounted for as an increase to additional paid-in capital if and when realized through
a reduction in income taxes payable. 
 The company
establishes valuation allowances on its deferred tax assets, including losses and tax credits, when the amount of expected future taxable income is not likely to support the use of the deduction or credit. At Dec. 31, 2014, a $4.6 million valuation
allowance had been established for state NOL carryforwards and state deferred tax assets, net of federal tax. During 2015, the valuation allowance decreased by $2.6 million.  As a result of the company’s sale of its 100% interest in
TECO Coal, the company released a $3.6 million valuation allowance previously recorded in 2014 related to state NOL carryforwards and deferred tax assets, net of federal tax, with a corresponding write off of the gross deferred tax assets since the
likelihood that the company will ever utilize those carryforwards is remote.  The TECO Coal sale also generated a federal capital loss carryforward deferred tax asset of $1.0 million for which a full valuation allowance has been
established due to the uncertainty of recognizing the benefit from this loss, before it expires in 2020.         

Unrecognized Tax Benefits

The company accounts for uncertain tax positions in accordance
with FASB guidance. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the guidance, the company may recognize the tax benefit
from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements
from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The guidance also provides standards on derecognition, classification, interest and
penalties on income taxes, accounting in interim periods and requires increased disclosures. 

87


 A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: 

 
 
	
 (millions)
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Balance at Jan. 1,
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
2.9
	
 

	
Decreases due to expiration of
statute of limitations
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(2.9
	
)

	
Balance at Dec. 31
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 




The company recognizes interest accruals related to uncertain
tax positions in “Other income” or “Interest expense”, as applicable, and penalties in “Operation and maintenance other expense” in the Consolidated Statements of Income. In 2015, 2014 and 2013, the company
recognized $0.0 million, $0.0 million and $(0.9) million, respectively, of pretax charges (benefits) for interest only. Additionally, the company did not have any accrued interest at Dec. 31, 2015 and 2014. No amounts have been recorded for
penalties. 
 The
company’s subsidiaries join in the filing of a U.S. federal consolidated income tax return. The IRS concluded its examination of the company’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of
limitations remains open for the year 2012 and forward. Years 2015 and 2016 are currently under examination by the IRS under its Compliance Assurance Program. U.S. state and foreign jurisdictions have statutes of limitations generally ranging from
three to four years from the filing of an income tax return. Additionally, any state net operating losses that were generated in prior years and are still being utilized are subject to examination by state jurisdictions. The state impact of any
federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by taxing authorities in major state jurisdictions and foreign jurisdictions
include 2005 and forward. The company does not expect the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months. 

 
  

5. Employee Postretirement Benefits

Pension Benefits 

TECO Energy has a qualified, non-contributory defined benefit
retirement plan that covers substantially all employees. Benefits are based on employees’ age, years of service and final average earnings. 

Amounts disclosed for pension benefits in the following tables and
discussion also include the fully-funded obligations for the SERP. The SERP is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management. 

TECO Coal participants ceased earning pension benefits on Sept.
21, 2015, the date of TECO Energy’s sale of TECO Coal. As a result of the sale, a curtailment loss in the Retirement Plan was recognized in the fourth quarter of 2014. See curtailment-related line items in tables below. 

Other Postretirement Benefits

TECO Energy and its subsidiaries currently provide certain
postretirement health care and life insurance benefits (Other Benefits or Other Postretirement Benefit Plan) for most employees retiring after age 50 meeting certain service requirements. Postretirement benefit levels are substantially unrelated to
salary. The company reserves the right to terminate or modify the plans in whole or in part at any time. 

MMA added prescription drug coverage to Medicare, with a 28%
tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes
coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially
equivalent” to the standard drug benefits that are offered under Medicare Part D. 

The FASB issued accounting guidance and disclosure requirements
related to MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that sponsor
postretirement health care plans that provide prescription drug benefits. 

In March 2010, the Patient Protection and Affordable Care Act and
a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduce the tax benefits available to an employer that receives the
Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TECO Energy reduced its deferred tax asset in 2010 and recorded a true up in 2013. TEC is amortizing the regulatory asset over the remaining average
service life at the time of 12 years. Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for retiree medical benefits. In particular, the Health Care Reform Acts include a provision that
imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform
Acts will materially increase its PBO. TECO Energy will continue to monitor and assess the impact of the Health Care Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results
of operations, cash flows or financial position. 

88


 Effective Jan. 1, 2013, the company decided to implement an EGWP for its post-65 retiree prescription drug plan. The
EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount enhancements provided under the Health Care Reform
Acts, which are greater than the subsidy payments previously received by the company under Medicare Part D for its post-65 retiree prescription drug plan. 

NMGC has a separate, partially-funded other postretirement
benefit plan. It is not presented separately; rather, it is presented with TECO Energy’s plan in the tables and discussion below. Since NMGC is allowed to recover its other postretirement benefit costs through rates, the regulated asset
established prior to the acquisition for pre-acquisition-related prior service cost, actuarial loss, and transition obligation was maintained after the acquisition. This regulated asset will be amortized. See “unrecognized costs in regulated
asset acquired in business combination” line item in the “Amounts recognized in accumulated other comprehensive income, pretax, and regulatory assets” table below.

Effective Jan. 1, 2015, the TECO Coal participants were
terminated from the Other Postretirement Benefit Plan. As a result, the other postretirement benefit obligation for TECO Coal was eliminated as of Dec. 31, 2014. See curtailment-related line items in tables below.

Obligations and Funded Status 

TECO Energy recognizes in its statement of financial position the
over-funded or under-funded status of its postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other
postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in the benefit liabilities and AOCI in the case of the unregulated companies, or the benefit liabilities and regulatory assets in the case of TEC
and NMGC. The results of operations are not impacted. 
 The
following table provides a detail of the change in benefit obligations and change in plan assets for combined pension plans (pension benefits) and combined other postretirement benefit plans (other benefits). 

 
 
	
Obligations and Plan Assets
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Change in benefit obligation
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net benefit obligation at beginning
of year
	
 
	
$
	
728.9
	
 
	
 
	
$
	
666.0
	
 
	
 
	
$
	
201.5
	
 
	
 
	
$
	
208.1
	
 

	
Service cost
	
 
	
 
	
20.9
	
 
	
 
	
 
	
18.3
	
 
	
 
	
 
	
2.2
	
 
	
 
	
 
	
2.5
	
 

	
Interest cost
	
 
	
 
	
30.3
	
 
	
 
	
 
	
32.0
	
 
	
 
	
 
	
8.2
	
 
	
 
	
 
	
10.8
	
 

	
Plan participants’
contributions
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
2.0
	
 
	
 
	
 
	
2.8
	
 

	
Plan amendments
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(3.7
	
)
	
 
	
 
	
(23.2
	
)

	
Actuarial loss (gain)
	
 
	
 
	
5.8
	
 
	
 
	
 
	
48.3
	
 
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
1.5
	
 

	
Benefits paid
	
 
	
 
	
(53.0
	
)
	
 
	
 
	
(39.9
	
)
	
 
	
 
	
(14.6
	
)
	
 
	
 
	
(16.0
	
)

	
Transfer in due to the effect of
business combination
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
26.7
	
 

	
Plan curtailment
	
 
	
 
	
0.0
	
 
	
 
	
 
	
4.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(11.7
	
)

	
Special termination
benefit
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Net benefit obligation at end of
year
	
 
	
$
	
732.9
	
 
	
 
	
$
	
728.9
	
 
	
 
	
$
	
195.2
	
 
	
 
	
$
	
201.5
	
 




 
 
	
Change in plan assets
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Fair value of plan assets at
beginning of year
	
 
	
$
	
648.0
	
 
	
 
	
$
	
593.0
	
 
	
 
	
$
	
18.8
	
 
	
 
	
$
	
0.0
	
 

	
Actual return on plan
assets
	
 
	
 
	
(25.5
	
)
	
 
	
 
	
46.4
	
 
	
 
	
 
	
(0.6
	
)
	
 
	
 
	
0.1
	
 

	
Employer contributions
	
 
	
 
	
55.0
	
 
	
 
	
 
	
47.5
	
 
	
 
	
 
	
1.5
	
 
	
 
	
 
	
(1.0
	
)

	
Employer direct benefit
payments
	
 
	
 
	
0.9
	
 
	
 
	
 
	
1.0
	
 
	
 
	
 
	
13.5
	
 
	
 
	
 
	
16.0
	
 

	
Plan participants’
contributions
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
2.0
	
 
	
 
	
 
	
2.8
	
 

	
Transfer in due to
acquisition
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
16.9
	
 

	
Benefits paid
	
 
	
 
	
(53.0
	
)
	
 
	
 
	
(39.9
	
)
	
 
	
 
	
(14.6
	
)
	
 
	
 
	
(16.0
	
)

	
Fair value of plan assets at end of
year (1)
	
 
	
$
	
625.4
	
 
	
 
	
$
	
648.0
	
 
	
 
	
$
	
20.6
	
 
	
 
	
 
	
18.8
	
 




 
 
	  (1)
	 The MRV of plan assets is used as the basis for calculating the
EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.




 89


 At Dec. 31, the aggregate financial position for pension plans and other postretirement plans with benefit obligations in excess of plan assets was as follows:

 
 
	
Funded Status
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Benefit obligation
(PBO/APBO)
	
 
	
$
	
732.9
	
 
	
 
	
$
	
728.9
	
 
	
 
	
$
	
195.2
	
 
	
 
	
$
	
201.5
	
 

	
Less: Fair value of plan
assets
	
 
	
 
	
625.4
	
 
	
 
	
 
	
648.0
	
 
	
 
	
 
	
20.6
	
 
	
 
	
 
	
18.8
	
 

	
Funded status at end of
year
	
 
	
$
	
(107.5
	
)
	
 
	
$
	
(80.9
	
)
	
 
	
$
	
(174.6
	
)
	
 
	
$
	
(182.7
	
)




 

The accumulated benefit obligation for all defined benefit
pension plans was $686.9 million at Dec. 31, 2015 and $685.0 million at Dec. 31, 2014.  

The amounts recognized in the Consolidated Balance Sheets for
pension and other postretirement benefit obligations, plan assets, and unrecognized costs at Dec. 31 were as follows:
  
 
	
Amounts recognized in balance
sheet
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Regulatory assets
	
 
	
$
	
208.2
	
 
	
 
	
$
	
167.4
	
 
	
 
	
$
	
32.4
	
 
	
 
	
$
	
26.6
	
 

	
Accrued benefit costs and other
current liabilities
	
 
	
 
	
(10.5
	
)
	
 
	
 
	
(4.9
	
)
	
 
	
 
	
(10.7
	
)
	
 
	
 
	
(10.7
	
)

	
Deferred credits and other
liabilities
	
 
	
 
	
(97.0
	
)
	
 
	
 
	
(76.0
	
)
	
 
	
 
	
(163.9
	
)
	
 
	
 
	
(172.0
	
)

	
Accumulated other comprehensive
loss (income), pretax
	
 
	
 
	
55.7
	
 
	
 
	
 
	
36.3
	
 
	
 
	
 
	
(41.6
	
)
	
 
	
 
	
(34.6
	
)

	
Net amount recognized at end of
year
	
 
	
$
	
156.4
	
 
	
 
	
$
	
122.8
	
 
	
 
	
$
	
(183.8
	
)
	
 
	
$
	
(190.7
	
)




 

Unrecognized gains and losses and prior service credits and costs
are recorded in accumulated other comprehensive income for the non-regulated companies and regulatory assets for the regulated companies. The following table provides a detail of the unrecognized gains and losses and prior service credits and
costs.
  
 
	
Amounts recognized in accumulated
other comprehensive income, pretax, and regulatory assets
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Net actuarial loss 
	
 
	
$
	
263.6
	
 
	
 
	
$
	
203.7
	
 
	
 
	
$
	
10.9
	
 
	
 
	
$
	
9.6
	
 

	
Prior service cost
(credit)
	
 
	
 
	
0.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(25.0
	
)
	
 
	
 
	
(23.6
	
)

	
Unrecognized costs in regulated
asset acquired in business combination
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
4.9
	
 
	
 
	
 
	
6.0
	
 

	
Amount recognized,
pretax
	
 
	
$
	
263.9
	
 
	
 
	
$
	
203.7
	
 
	
 
	
$
	
(9.2
	
)
	
 
	
$
	
(8.0
	
)




 

Assumptions used to determine benefit obligations at Dec. 31: 

 
 
	
 
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
 
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Discount rate
	
 
	
 
	
4.688
	
%
	
 
	
 
	
4.258
	
%
	
 
	
 
	
4.669
	
%
	
 
	
 
	
4.211
	
%

	
Rate of compensation
increase—weighted
	
 
	
 
	
3.87
	
%
	
 
	
 
	
3.87
	
%
	
 
	
 
	
2.50
	
%
	
 
	
 
	
3.86
	
%

	
Healthcare cost trend rate
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Immediate rate
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
 
	
7.05
	
%
	
 
	
 
	
7.09
	
%

	
Ultimate rate
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
 
	
4.50
	
%
	
 
	
 
	
4.57
	
%

	
Year rate reaches
ultimate
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
2038
	
 
	
 
	
2025
	
 




 

A one-percentage-point change in assumed health care cost trend
rates would have the following effect on the benefit obligation: 

 
 
	
 
	
 
	
 
	
1%
	
 
	
 
	
 
	
1%
	
 

	
(millions)
	
 
	
Increase
	
 
	
 
	
Decrease
	
 

	
Effect on postretirement benefit
obligation
	
 
	
$
	
9.0
	
 
	
 
	
$
	
(7.7
	
)




The discount rate assumption used to determine the Dec. 31, 2015
benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate
bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits
and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate. 

90


 Amounts recognized in Net Periodic Benefit Cost, OCI and Regulatory Assets

 
 
	
(millions)
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
 
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Service cost
	
 
	
$
	
20.9
	
 
	
 
	
$
	
18.3
	
 
	
 
	
$
	
18.2
	
 
	
 
	
$
	
2.2
	
 
	
 
	
$
	
2.5
	
 
	
 
	
$
	
2.5
	
 

	
Interest cost
	
 
	
 
	
30.3
	
 
	
 
	
 
	
32.0
	
 
	
 
	
 
	
28.9
	
 
	
 
	
 
	
8.2
	
 
	
 
	
 
	
10.8
	
 
	
 
	
 
	
9.3
	
 

	
Expected return on plan
assets
	
 
	
 
	
(43.3
	
)
	
 
	
 
	
(41.8
	
)
	
 
	
 
	
(38.4
	
)
	
 
	
 
	
(1.1
	
)
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
0.0
	
 

	
Amortization of:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Actuarial loss
	
 
	
 
	
15.1
	
 
	
 
	
 
	
13.5
	
 
	
 
	
 
	
20.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
1.0
	
 

	
Prior service (benefit)
cost
	
 
	
 
	
(0.2
	
)
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
(2.4
	
)
	
 
	
 
	
(0.2
	
)
	
 
	
 
	
(0.4
	
)

	
Curtailment loss (gain)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
3.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.2
	
)
	
 
	
 
	
0.0
	
 

	
Special termination
benefit
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Settlement loss
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Net periodic benefit
cost
	
 
	
$
	
22.8
	
 
	
 
	
$
	
25.7
	
 
	
 
	
$
	
29.8
	
 
	
 
	
$
	
6.9
	
 
	
 
	
$
	
12.8
	
 
	
 
	
$
	
12.4
	
 




 
 
	
New prior service cost
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
(3.7
	
)
	
 
	
$
	
(23.6
	
)
	
 
	
$
	
0.0
	
 

	
Net loss (gain) arising during the
year
	
 
	
 
	
74.5
	
 
	
 
	
 
	
44.1
	
 
	
 
	
 
	
(75.7
	
)
	
 
	
 
	
1.3
	
 
	
 
	
 
	
(9.9
	
)
	
 
	
 
	
(15.6
	
)

	
Unrecognized costs in regulated
asset acquired in business combination
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
6.4
	
 
	
 
	
 
	
0.0
	
 

	
Amounts recognized as component of
net periodic benefit cost:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Amortization of actuarial gain
(loss)
	
 
	
 
	
(15.1
	
)
	
 
	
 
	
(13.5
	
)
	
 
	
 
	
(21.5
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.2
	
)
	
 
	
 
	
(1.0
	
)

	
Amortization of prior service
(benefit) cost
	
 
	
 
	
0.2
	
 
	
 
	
0.4
	
 
	
 
	
 
	
0.4
	
 
	
 
	
 
	
2.4
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
0.3
	
 

	
Total recognized in OCI and
regulatory assets
	
 
	
$
	
59.6
	
 
	
 
	
$
	
31.0
	
 
	
 
	
$
	
(96.8
	
)
	
 
	
$
	
0.0
	
 
	
 
	
$
	
(27.1
	
)
	
 
	
$
	
(16.3
	
)

	
Total recognized in net periodic
benefit cost, OCI and regulatory assets
	
 
	
$
	
82.4
	
 
	
 
	
$
	
56.7
	
 
	
 
	
$
	
(67.0
	
)
	
 
	
$
	
6.9
	
 
	
 
	
$
	
(14.3
	
)
	
 
	
$
	
(3.9
	
)




 

A curtailment loss and special termination benefits were
recognized in 2014 for the Retirement Plan due to the expected sale of TECO Coal. The sale was completed in 2015. Additionally, a curtailment gain was recognized for the OPEB plan due to the termination of the TECO Coal plan effective Jan. 1,
2015.
 The estimated net loss and prior service cost for the
defined benefit pension plans that will be amortized from AOCI into net periodic benefit cost over the next fiscal year are $3.5 million and $0.1 million, respectively. The estimated prior service cost for the other postretirement benefit plans that
will be amortized from AOCI into net periodic benefit cost over the next fiscal year is $0.5 million. 

In addition, the estimated net loss for the defined benefit
pension plans that will be amortized from regulatory assets into net periodic benefit cost over the next fiscal year are $9.8 million. There will be an estimated $2.1 million prior service cost that will be amortized from regulatory assets into net
periodic benefit cost over the next fiscal year for the other postretirement benefit plan. Additionally, $1.1 million of NMGC’s pre-acquisition regulated asset will be amortized from regulatory assets into net periodic benefit cost over the
next fiscal year.
 Assumptions used to determine net periodic
benefit cost for years ended Dec. 31: 
  
 
	
 
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
 
	
 
	
2015
	
 
	
 
	
2014 (1)
	
 
	
 
	
2013
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Discount rate
	
 
	
 
	
4.258
	
%
	
 
	
5.118%/4.277%/4.331%

	
 
	
 
	
 
	
4.196
	
%
	
 
	
 
	
4.211
	
%
	
 
	
 
	
5.096
	
%
	
 
	
 
	
4.180
	
%

	
Expected long-term return on plan
assets
	
 
	
 
	
7.00
	
%
	
 
	
7.25%/7.00%/7.00%

	
 
	
 
	
 
	
7.50
	
%
	
 
	
 
	
5.75
	
 
	
 
	
 
	
5.75
	
 
	
 
	
n/a
	
 

	
Rate of compensation
increase
	
 
	
 
	
3.87
	
%
	
 
	
 
	
3.73
	
%
	
 
	
 
	
3.76
	
%
	
 
	
 
	
3.86
	
%
	
 
	
 
	
3.71
	
%
	
 
	
 
	
3.74
	
%

	
Healthcare cost trend rate
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Initial rate
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
 
	
7.09
	
%
	
 
	
 
	
7.25
	
%
	
 
	
 
	
7.50
	
%

	
Ultimate rate
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
 
	
4.57
	
%
	
 
	
 
	
4.50
	
%
	
 
	
 
	
4.50
	
%

	
Year rate reaches
ultimate
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
2025
	
 
	
 
	
2025
	
 
	
 
	
2025
	
 





	  (1) 
	 TECO Energy performed a valuation as of Jan. 1,
2014. TECO remeasured its Retirement Plan on Sept. 2, 2014 for the acquisition of NMGC and on Oct. 31, 2014 for the expected curtailment of TECO Coal, resulting in the respective updated discount rates and EROAs.




91


 The discount rate assumption used to determine the 2015 benefit cost was based on a cash flow matching technique
developed by outside actuaries and a review of current economic conditions. This technique constructs
hypothetical bond portfolios using high-quality (AA or better by S&P) corporate bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce
adequate cash flows to pay the yearly benefits and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate. 

The expected return on assets assumption was based on historical
returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation at the measurement date. A change in asset allocations could have a significant impact on the expected return on assets. Additionally, expectations
of long-term inflation, real growth in the economy and a provision for active management and expenses paid were incorporated in the assumption. For the year ended Dec. 31, 2015, TECO Energy’s pension plan assets decreased approximately 3.5%.

 The compensation increase assumption was based on the same
underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases. 

A one-percentage-point change in assumed health care cost trend
rates would have the following effect on expense: 
 
	
  
	
 
	
 
	
1%
	
 
	
 
	
 
	
1%
	
 

	
(millions)
	
 
	
Increase
	
 
	
 
	
Decrease
	
 

	
Effect on periodic cost
	
 
	
$
	
0.4
	
 
	
 
	
$
	
(0.3
	
)




Pension Plan Assets 

Pension plan assets (plan assets) are primarily invested in a mix
of equity and fixed income securities. The company’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. The company’s strategy is to hire
proven managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan
expenses. 
  
 
	
 
	
 
	
Target 
Allocation
	
 
	
 
	
Actual 
Allocation, End of Year
	
 

	
Asset Category
	
 
	
 
	
 
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Equity securities
	
 
	
47%-53%
	
 
	
 
	
 
	
53
	
%
	
 
	
 
	
50
	
%

	
Fixed income securities
	
 
	
47%-53%
	
 
	
 
	
 
	
47
	
%
	
 
	
 
	
50
	
%

	
Total
	
 
	
 
	
100
	
%
	
 
	
 
	
100
	
%
	
 
	
 
	
100
	
%




The company reviews the plan’s asset allocation
periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. The company will continue to monitor the
matching of plan assets with plan liabilities. 
 The
plan’s investments are held by a trust fund administered by JP Morgan Chase Bank, N.A. (JP Morgan). Investments are valued using quoted market prices on an exchange when available. Such investments are classified Level 1. In some cases where a
market exchange price is available but the investments are traded in a secondary market, acceptable practical expedients are used to calculate fair value. 

If observable transactions and other market data are not
available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party
generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable. 

As required by the fair value accounting standards, the
investments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The plan’s assessment of the significance of a particular input to the fair value measurement requires judgment,
and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the
income approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2015 and 2014. 

 
 



92


 
	
 (millions)
	
 
	
At Fair Value as of
Dec. 31, 2015
	
 

	
 
	
 
	
Level 1
	
 
	
 
	
Level 2
	
 
	
 
	
Level 
3
	
 
	
 
	
Using NAV (1)
	
 
	
 
	
Total
	
 

	
Net cash
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Cash
	
 
	
$
	
1.9
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
1.9
	
 

	
Accounts receivable
	
 
	
 
	
14.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
14.3
	
 

	
Accounts payable
	
 
	
 
	
(27.2
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(27.2
	
)

	
Total net cash
	
 
	
 
	
(11.0
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(11.0
	
)

	
Cash equivalents
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Money markets
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 

	
Discounted notes
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.7
	
 

	
Short-term investment funds
(STIFs) (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
12.4
	
 
	
 
	
 
	
12.4
	
 

	
Total cash equivalents
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
12.4
	
 
	
 
	
 
	
13.3
	
 

	
Equity securities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Common stocks
	
 
	
 
	
90.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
90.9
	
 

	
American depository receipts
(ADRs)
	
 
	
 
	
5.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
5.7
	
 

	
Real estate investment trusts
(REITs)
	
 
	
 
	
4.8
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
4.8
	
 

	
Commingled fund
	
 
	
 
	
0.0
	
 
	
 
	
 
	
53.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
53.7
	
 

	
Mutual funds (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
175.6
	
 
	
 
	
 
	
175.6
	
 

	
Total equity securities
	
 
	
 
	
101.4
	
 
	
 
	
 
	
53.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
175.6
	
 
	
 
	
 
	
330.7
	
 

	
Fixed income securities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Municipal bonds
	
 
	
 
	
0.0
	
 
	
 
	
 
	
5.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
5.0
	
 

	
Government bonds
	
 
	
 
	
0.0
	
 
	
 
	
 
	
56.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
56.2
	
 

	
Corporate bonds
	
 
	
 
	
0.0
	
 
	
 
	
 
	
32.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
32.2
	
 

	
Asset backed securities
(ABS)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.3
	
 

	
Mortgage-backed securities
(MBS), net short sales
	
 
	
 
	
0.0
	
 
	
 
	
 
	
8.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
8.7
	
 

	
Collateralized mortgage
obligations (CMOs)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.5
	
 

	
Commingled fund (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
117.9
	
 
	
 
	
 
	
117.9
	
 

	
Mutual fund (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
71.3
	
 
	
 
	
 
	
71.3
	
 

	
Total fixed income
securities
	
 
	
 
	
0.0
	
 
	
 
	
 
	
103.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
189.2
	
 
	
 
	
 
	
293.1
	
 

	
Derivatives
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Swaps
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.9
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.9
	
)

	
Purchased options
(swaptions)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.1
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.1
	
 

	
Written options
(swaptions)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(1.0
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(1.0
	
)

	
Total derivatives
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.8
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.8
	
)

	
Miscellaneous
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.1
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.1
	
 

	
Total
	
 
	
$
	
90.4
	
 
	
 
	
$
	
157.8
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
377.2
	
 
	
 
	
$
	
625.4
	
 





	 (1)
	 In accordance with accounting standards, certain
investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy
to amounts presented in the Consolidated Balance Sheet.



 



93


 
	
 (millions)
	
 
	
At Fair Value as of
Dec. 31, 2014
	
 

	
 
	
 
	
Level 1
	
 
	
 
	
Level 2
	
 
	
 
	
Level 
3
	
 
	
 
	
Using NAV (1)
	
 
	
 
	
Total
	
 

	
Net cash
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Cash
	
 
	
$
	
0.4
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.4
	
 

	
Accounts receivable
	
 
	
 
	
1.4
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.4
	
 

	
Accounts payable
	
 
	
 
	
(5.3
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(5.3
	
)

	
Total net cash
	
 
	
 
	
(3.5
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(3.5
	
)

	
Cash equivalents
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Treasury bills (T
bills)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 

	
Discounted notes
	
 
	
 
	
0.0
	
 
	
 
	
 
	
8.8
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
8.8
	
 

	
Short-term investment funds
(STIFs) (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
7.6
	
 
	
 
	
 
	
7.6
	
 

	
Total cash equivalents
	
 
	
 
	
0.0
	
 
	
 
	
 
	
9.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
7.6
	
 
	
 
	
 
	
16.6
	
 

	
Equity securities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Common stocks
	
 
	
 
	
98.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
98.0
	
 

	
American depository receipts
(ADRs)
	
 
	
 
	
1.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.3
	
 

	
Real estate investment trusts
(REITs)
	
 
	
 
	
2.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
2.5
	
 

	
Preferred stock
	
 
	
 
	
0.8
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.8
	
 

	
Commingled fund
	
 
	
 
	
0.0
	
 
	
 
	
 
	
45.6
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
45.6
	
 

	
Mutual funds (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
171.3
	
 
	
 
	
 
	
171.3
	
 

	
Total equity securities
	
 
	
 
	
102.6
	
 
	
 
	
 
	
45.6
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
171.3
	
 
	
 
	
 
	
319.5
	
 

	
Fixed income securities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Municipal bonds
	
 
	
 
	
0.0
	
 
	
 
	
 
	
6.1
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
6.1
	
 

	
Government bonds
	
 
	
 
	
0.0
	
 
	
 
	
 
	
47.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
47.9
	
 

	
Corporate bonds
	
 
	
 
	
0.0
	
 
	
 
	
 
	
22.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
22.0
	
 

	
Asset backed securities
(ABS)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.3
	
 

	
Mortgage-backed securities
(MBS), net short sales
	
 
	
 
	
0.0
	
 
	
 
	
 
	
9.6
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
9.6
	
 

	
Collateralized mortgage
obligations (CMOs)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
2.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
2.0
	
 

	
Commingled fund (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
129.2
	
 
	
 
	
 
	
129.2
	
 

	
Mutual fund (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
98.6
	
 
	
 
	
 
	
98.6
	
 

	
Total fixed income
securities
	
 
	
 
	
0.0
	
 
	
 
	
 
	
87.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
227.8
	
 
	
 
	
 
	
315.7
	
 

	
Derivatives
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Short futures
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.3
	
)

	
Purchased options
(swaptions)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.7
	
 

	
Written options
(swaptions)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.8
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.8
	
)

	
Total derivatives
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.4
	
)

	
Miscellaneous
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.1
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.1
	
 

	
Total
	
 
	
$
	
99.1
	
 
	
 
	
$
	
142.2
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
406.7
	
 
	
 
	
$
	
648.0
	
 





	 (1)
	 In accordance with accounting standards, certain
investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy
to amounts presented in the Consolidated Balance Sheet.




The following list details the pricing inputs and
methodologies used to value the investments in the pension plan:
 
	  
	 ●
	 The primary
pricing inputs in determining the fair value of the Level 1 assets are closing quoted prices in active markets. 



 
	  
	 ●
	 The methodology
and inputs used to value the investment in the equity commingled fund are broker dealer quotes sourced by State Street Custody System.  The fund holds primarily international equity securities that are actively traded in over-the-counter
markets. The fund honors subscription and redemption activity on an “as of” basis. 



 
	  
	 ●
	 The money markets
are valued at cost due to their short-term nature. Discounted notes are valued at amortized cost.



 
	  
	 ●
	 The primary
pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are
the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMO are priced using TBA prices,
treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. 



 
	  
	 ●
	 Futures are
valued using futures data, cash rate data, swap rates, and cash flow analyses.



 
	  
	 ●
	 Swaps are valued
using benchmark yields, swap curves, and cash flow analyses.




94


 
	  
	 ●
	 Options are valued using the bid-ask spread and the last price. 



 
	  
	 ●
	 The STIF is
valued at NAV as determined by JP Morgan. The funds are open-end investments. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV.




 
	  
	 ●
	 The primary
pricing inputs in determining the equity mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV.



 
	  
	 ●
	 The primary
pricing input in determining the fair value of the fixed asset mutual fund is its NAV. It is an unregistered open-ended mutual fund. 



 
	  
	 ●
	 The fixed income
commingled fund is a private fund valued at NAV. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid
prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15th calendar day of the month.
Redemptions are honored on the 15th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date. 




Additionally, the unqualified SERP had $43.5 million and $0.9
million of assets as of Dec. 31, 2015 and 2014, respectively. Since the plan is unqualified, its assets are included in the “Deferred charges and other assets” line item in TECO Energy’s Consolidated Balance Sheets rather than
being netted with the related liability. The fund holds investments in a money market fund, which is valued at cost due to its short-term nature, making this a level 2 asset. The SERP was fully funded as of Dec. 31, 2015.

Other Postretirement Benefit Plan Assets 

NMGC’s other postretirement benefits plan had $20.6 million
and $18.8 million of assets as of Dec. 31, 2015 and 2014, respectively. The majority of the assets are valued at the cash surrender value of NMGC participant life insurance policies and are considered Level 2 assets. In accordance with NMPRC
requirements, NMGC must fund to a trust, on an annual basis, an amount equal to the other postretirement expense allowed in its last base rate case. 

Contributions 

The Pension Protection Act became effective Jan. 1, 2008 and
requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions), pay higher premiums to the PBGC if they sponsor defined benefit plans, amend plan documents and provide additional
plan disclosures in regulatory filings and to plan participants. 

WRERA was signed into law on Dec. 23, 2008. WRERA grants plan
sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans
funded less than 100%, required shortfall contributions were based on a percentage of the funding target until 2013, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use of
asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements.

In August 2014, the President signed into law HAFTA, which
modified MAP-21. HAFTA and MAP-21 provide funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. The
company expects the required minimum pension contributions to be lower than the levels previously projected; however, the company plans on funding at levels above the required minimum pension contributions under HAFTA and MAP-21. In November 2015,
the President signed into law the Bipartisan Budget Act of 2015, which extended pension funding relief of MAP-21 and HAFTA through 2022.

The qualified pension plan’s actuarial value of assets,
including credit balance, was 120.1% of the Pension Protection Act funded target as of Jan. 1, 2015 and is estimated at 114.1% of the Pension Protection Act funded target as of Jan. 1, 2016.

The company’s policy is to fund the qualified pension plan
at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. The company made $55.0 million and $47.5 million of contributions to this plan in 2015 and 2014,
respectively, which met the minimum funding requirements for both 2015 and 2014. These amounts are reflected in the “Other” line on the Consolidated Statements of Cash Flows. The company estimates its contribution in 2016 to be $37.4
million and expects to make contributions from 2017 to 2020 in the range of $12.2 to $44.6 million per year based on current assumptions. These contributions are in excess of the minimum required contribution under ERISA guidelines. 

The company made contributions of $43.4 million and $1.2 million
to the SERP in 2015 and 2014, respectively. The company’s contribution in October 2015 to the SERP’s trust was made in order to fully fund its SERP obligation following the signing of the Merger Agreement with Emera. The execution of the
Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy is required to maintain such funding as of the end of each calendar year, including 2015. The fully funded 

95


 amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus the current value of benefits that would become payable under the SERP to current
participants. Since the SERP is fully funded, the company does not expect to make significant contributions to this plan in 2016. 

The company funds its other postretirement benefits periodically
to meet benefit obligations. The company’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. The
company’s contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2016, the company expects to make
contributions of about $14.3 million. This includes $3.6 million that NMGC is required to fund to its trust in accordance with NMPRC requirements. Postretirement benefit levels are substantially unrelated to salary. 

Benefit Payments 

The following benefit payments, which reflect expected future
service, as appropriate, are expected to be paid: 
 Expected
Benefit Payments 

(including projected service and net of employee contributions) 
  
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Other
	
 

	
 
	
 
	
Pension
	
 
	
 
	
Postretirement
	
 

	
(millions)
	
 
	
Benefits
	
 
	
 
	
Benefits
	
 

	
2016
	
 
	
$
	
77.8
	
 
	
 
	
$
	
11.5
	
 

	
2017
	
 
	
 
	
49.5
	
 
	
 
	
 
	
11.9
	
 

	
2018
	
 
	
 
	
52.7
	
 
	
 
	
 
	
12.5
	
 

	
2019
	
 
	
 
	
59.2
	
 
	
 
	
 
	
13.0
	
 

	
2020
	
 
	
 
	
54.9
	
 
	
 
	
 
	
13.3
	
 

	
2021-2025
	
 
	
 
	
299.1
	
 
	
 
	
 
	
68.6
	
 




Defined Contribution Plan 

The company has a defined contribution savings plan covering
substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. The company and its subsidiaries match up to 6% of the participant’s
payroll savings deductions. Effective Jan. 1, 2015, employer matching contributions were 70% of eligible participant contributions with additional incentive match of up to 30% of eligible participant contributions based on the achievement of certain
operating company financial goals. During the period from April 2013 to December 2014, employer matching contributions were 65% of eligible participant contributions with additional incentive match of up to 35% of eligible participant contributions
based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions, with an additional incentive match of up to 40%. For the years ended Dec. 31,
2015, 2014 and 2013, the company and its subsidiaries recognized expense totaling $11.1 million, $13.1 million and $11.3 million, respectively, related to the matching contributions made to this plan. 

  

 

6. Short-Term Debt 

At Dec. 31, 2015 and Dec. 31, 2014, the following credit
facilities and related borrowings existed: 
 Credit Facilities 
  
 
	
 
	
 
	
Dec. 31,
2015
	
 
	
 
	
Dec. 31,
2014
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Letters
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Letters
	
 

	
 
	
 
	
Credit
	
 
	
 
	
Borrowings
	
 
	
 
	
of Credit
	
 
	
 
	
Credit
	
 
	
 
	
Borrowings
	
 
	
 
	
of Credit
	
 

	
(millions)
	
 
	
Facilities
	
 
	
 
	
Outstanding  (1)
	
 
	
 
	
Outstanding
	
 
	
 
	
Facilities
	
 
	
 
	
Outstanding  (1)
	
 
	
 
	
Outstanding
	
 

	
Tampa Electric 
Company:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
5-year facility (2)
	
 
	
$
	
325.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.5
	
 
	
 
	
$
	
325.0
	
 
	
 
	
$
	
12.0
	
 
	
 
	
$
	
0.6
	
 

	
3-year accounts receivable
facility (3)
	
 
	
 
	
150.0
	
 
	
 
	
 
	
61.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
150.0
	
 
	
 
	
 
	
46.0
	
 
	
 
	
 
	
0.0
	
 

	
TECO Energy/TECO 
Finance:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
5-year facility (2)(4)
	
 
	
 
	
300.0
	
 
	
 
	
 
	
163.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
300.0
	
 
	
 
	
 
	
50.0
	
 
	
 
	
 
	
0.0
	
 

	
New Mexico Gas Company:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
5-year facility (2)
	
 
	
 
	
125.0
	
 
	
 
	
 
	
23.0
	
 
	
 
	
 
	
1.7
	
 
	
 
	
 
	
125.0
	
 
	
 
	
 
	
31.0
	
 
	
 
	
 
	
1.7
	
 

	
Total
	
 
	
$
	
900.0
	
 
	
 
	
$
	
247.0
	
 
	
 
	
$
	
2.2
	
 
	
 
	
$
	
900.0
	
 
	
 
	
$
	
139.0
	
 
	
 
	
$
	
2.3
	
 




96


 
	 (1)
	 Borrowings outstanding are reported as notes payable. 



 
	 (2)
	 This 5-year facility matures Dec. 17, 2018.




 
	 (3) 
	 Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year
facility matures Mar. 23, 2018.



 
	 (4)
	 TECO Finance is the borrower and TECO Energy is the guarantor of
this facility. 



 At Dec. 31, 2015,
these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities at Dec. 31, 2015 and 2014 was 1.29% and 1.16%, respectively. 

Tampa Electric Company Accounts Receivable Facility 

On Mar. 24, 2015, TEC and TRC amended and restated their $150
million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders, and
(iii) extend the scheduled termination date from Apr. 14, 2015 to Mar. 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement dated as of Mar. 24, 2015 between TEC and TRC and (b) a Loan and Servicing Agreement
dated as of Mar. 24, 2015, among TEC as Servicer, TRC as Borrower, certain lenders named therein and BTMU, as Program Agent (the Loan Agreement). Pursuant to the Loan Agreement, TRC will pay program and liquidity fees, which total 65 basis points as
of Dec. 31, 2015. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s
option, either the BTMU’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank deposit rate (if available) plus a margin. In addition, under the terms of the Loan Agreement, TEC has
pledged as collateral a pool of receivables equal to the borrowings outstanding in the case of default. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of Dec.
31, 2015, TEC and TRC were in compliance with the requirements of the Loan Agreement.

TECO Energy Credit Agreement Assigned to and Assumed by NMGC 

On Dec. 17, 2013, TECO Energy entered into a $125 million bank
credit facility, pursuant to which it was the initial party to the Credit Agreement (the NMGC Credit Agreement). TECO Energy had no rights or obligations to borrow under the NMGC Credit Agreement, which was entered into solely with the intent of it
being assigned to, and assumed by, NMGC upon the closing of the Acquisition. Pursuant to the terms of the NMGC Credit Agreement, on Sept. 2, 2014, TECO Energy designated NMGC as the borrower under the NMGC Credit Agreement by delivering a Joinder
and Release Agreement duly executed by TECO Energy and NMGC, whereupon (i) NMGC became the borrower for all purposes of the NMGC Credit Agreement and the other credit facility documents under the NMGC Credit Agreement, and (ii) TECO Energy
ceased to be a party to the NMGC Credit Agreement and any further rights or obligations thereunder. The NMGC Credit Agreement (i) has a maturity date of Dec. 17, 2018 (subject to further extension with the consent of each lender);
(ii) allows NMGC to borrow funds at a rate equal to the one-month London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows NMGC to borrow funds at an interest rate equal to a margin plus the
higher of JPMorgan Chase Bank’s prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows NMGC to borrow funds on a same-day basis under a swingline loan provision, which loans
mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the Borrower and the relevant swingline lender prior to the making of any such loans; (v) allows NMGC to request the lenders
to increase their commitments under the credit facility by up to $75 million in the aggregate; and (vi) includes a $40 million letter of credit facility. 

On Sept. 30, 2014, NMGC entered into an amendment of the NMGC
Credit Agreement, which reallocated commitments among the lenders and made certain other technical changes. 

Amendment of Tampa Electric Company Credit
Facility
 On Dec. 17, 2013, TEC amended and restated its $325
million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extended the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to
further extension with the consent of each lender); (ii) continued to allow TEC, as borrower, to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC
to borrow funds at an interest rate equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a
swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; (v)
continues to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes. 
 On Sept. 30, 2014, TEC
entered into an amendment of its $325 million bank credit facility, which reallocated commitments among the lenders and made certain other technical changes. 

97


 Amendments of TECO Energy/TECO Finance Credit Facility

On Dec. 17, 2013, TECO Energy amended and restated its $200
million bank credit facility, entering into a Fourth Amended and Restated Credit Agreement (the TECO Credit Facility).  The amendment (i) extended the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject
to further extension with the consent of each lender); (ii) continues with TECO Energy as guarantor and its wholly-owned subsidiary, TECO Finance, as borrower; (iii) allows TECO Finance to borrow funds at an interest rate equal to the London
interbank deposit rate plus a margin; (iv) as an alternative to the above interest rate, allows TECO Finance to borrow funds at an interest rate equal to a margin plus the higher of the JPMorgan Chase Bank's prime rate, the federal funds rate plus
50 basis points, or the London interbank deposit rate plus 1.00%; (v) allows TECO Finance to borrow funds on a same-day basis under a swingline loan provision, which loans mature on the fourth banking day after which any such loans are made and bear
interest at an interest rate as agreed by the Borrower and the relevant swingline lender prior to the making of any such loans;  (vi) allows TECO Finance to request the lenders to increase their commitments under the credit facility by $100
million in the aggregate; (vii) continues to include a $200 million letter of credit facility; and (viii) made other technical changes.  

The Fourth Amended and Restated Credit Agreement includes the
changes made in Amendment No. 1 dated June 24, 2013 (Amendment) to the TECO Energy/TECO Finance Third Amended and Restated Credit Agreement dated Oct. 25, 2011. Amendment No. 1 was entered into to accommodate the acquisition of NMGI, as described in
Note 21 herein, by (i) temporarily changing the total debt to total capitalization financial covenant such that, during the four fiscal quarters commencing with the quarter in which the acquisition closed, TECO
Energy must maintain a total debt to total capitalization ratio of no greater than 0.70 to 1.00, instead of the previous capitalization ratio of 0.65 to 1.00 and (ii) changed the definition of Permitted Liens to permit the acquisition of a
significant subsidiary that has outstanding secured debt and made other changes matching the corresponding covenant in the Bridge Facility. TECO Energy and TECO Finance entered into a $1.075 billion senior unsecured bridge credit agreement on June
24, 2013, among TECO Energy as guarantor, TECO Finance as borrower, Morgan Stanley Senior Funding, Inc. (Morgan Stanley) as administrative agent, sole lead arranger and sole book runner, and Morgan Stanley together with nine other banks as lenders
in the Bridge Facility. 
 On Sept. 30, 2014, the TECO Credit
Facility was amended to increase total commitments to $300 million and to reallocate commitments among the lenders.
  

 

7. Long-Term Debt

At Dec. 31, 2015, total long-term debt had a carrying amount of
$3,850.2 million and an estimated fair market value of $4,061.6 million. At Dec. 31, 2014, total long-term debt had a carrying amount of $3,628.5 million and an estimated fair market value of $3,987.8 million. The company uses the market approach in
determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using prices obtained from the Municipal Securities
Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments. 

TECO Finance is a wholly owned subsidiary of TECO Energy. TECO
Finance’s sole purpose is to raise capital for TECO Energy’s diversified businesses. TECO Energy is a full and unconditional guarantor of TECO Finance’s securities, and no subsidiaries of TECO Energy guarantee TECO Finance’s
securities. 
 A substantial part of Tampa Electric’s
tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture. 

TECO Energy’s gross maturities and annual sinking fund
requirements of long-term debt for 2016 through 2020 and thereafter are as follows: 

Long-Term Debt Maturities

  
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Total
	
 

	
As of Dec. 31, 2015
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Long-Term
	
 

	
(millions)
	
 
	
2016
	
 
	
 
	
2017
	
 
	
 
	
2018
	
 
	
 
	
2019
	
 
	
 
	
2020
	
 
	
 
	
Thereafter
	
 
	
 
	
Debt
	
 

	
TECO Finance
	
 
	
$
	
250.0
	
 
	
 
	
$
	
300.0
	
 
	
 
	
$
	
250.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
300.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
1,100.0
	
 

	
Tampa Electric
	
 
	
 
	
83.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
254.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1,666.7
	
 
	
 
	
 
	
2,004.2
	
 

	
PGS
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
50.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
211.7
	
 
	
 
	
 
	
261.7
	
 

	
NMGC
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
270.0
	
 
	
 
	
 
	
270.0
	
 

	
NMGI
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
50.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
150.0
	
 
	
 
	
 
	
200.0
	
 

	
Total long-term debt
maturities
	
 
	
$
	
333.3
	
 
	
 
	
$
	
300.0
	
 
	
 
	
$
	
554.2
	
 
	
 
	
$
	
50.0
	
 
	
 
	
$
	
300.0
	
 
	
 
	
$
	
2,298.4
	
 
	
 
	
$
	
3,835.9
	
 




98


  

Issuance of TECO Finance Floating Rate Notes due 2018 

On Apr. 10, 2015, TECO Finance completed an offering of $250
million aggregate principal amount of floating rate notes due 2018 (the 2018 Notes), which are guaranteed by TECO Energy. The 2018 Notes were sold at par and mature on Apr. 10, 2018. The 2018 Notes bear interest at a floating rate that is reset
quarterly based on the three-month LIBOR plus 60 basis points. The 2018 Notes are not  subject to redemption prior to maturity. The 2018 Notes are effectively subordinated to existing and future liabilities of TECO Energy’s
subsidiaries to their respective creditors, and also are effectively subordinated to any secured debt that TECO Finance and TECO Energy incur to the extent of the value of the assets securing that indebtedness. 

The offering resulted in net proceeds to TECO Finance (after
deducting underwriting discounts and commissions and estimated offering expenses) of approximately $248.6 million. TECO Finance used these net proceeds to repay borrowings under the TECO Finance credit facility and to fund a portion of the payment
of $191 million of TECO Finance notes that matured in May 2015.

Issuance of Tampa Electric Company 4.20% Notes due 2045

On May 20, 2015, TEC completed an offering of $250 million
aggregate principal amount of 4.20% Notes due May 15, 2045 (the TEC 2015 Notes).  The TEC 2015 Notes were sold at 99.814% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions, estimated
offering expenses and before settlement of interest rate swaps) of approximately $246.8 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Until Nov. 15, 2044, TEC may redeem all or any part of the TEC 2015
Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the TEC 2015 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and
interest on the TEC 2015 Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption
date.  At any time on or after Nov. 15, 2044, TEC may, at its option, redeem the TEC 2015 Notes, in whole or in part, at 100% of the principal amount of the TEC 2015 Notes being redeemed plus accrued and unpaid interest thereon to but
excluding the date of redemption.
  Issuance of Tampa Electric
Company 4.35% Notes due 2044 
 On May 15, 2014, TEC
completed an offering of $300 million aggregate principal amount of 4.35% Notes due 2044 (the TEC 2014 Notes). The TEC 2014 Notes were sold at 99.933% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts,
commissions, estimated offering expenses and before settlement of interest rate swaps) of approximately $296.6 million. Net proceeds were used to repay short-term debt and for general corporate purposes. TEC may redeem all or any part of the TEC
2014 Notes at its option at any time and from time to time before Nov. 15, 2043 at a redemption price equal to the greater of (i) 100% of the principal amount of TEC 2014 Notes to be redeemed or (ii) the sum of the present value of the
remaining payments of principal and interest on the notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 15 basis points; in either case, the redemption price would include accrued and unpaid interest
to the redemption date. At any time on or after Nov. 15, 2043, TEC may at its option redeem the TEC 2014 Notes, in whole or in part, at 100% of the principal amount of the notes being redeemed plus accrued and unpaid interest thereon to but
excluding the date of redemption. 
 Issuance of New Mexico Gas
Intermediate Senior Unsecured Notes 
 On Sept. 2, 2014, NMGI
completed an offering of $50 million aggregate principal amount of 2.71% Series A Senior Unsecured Notes due July 30, 2019 (the NMGI Series A 2014 Notes) and $150 million aggregate principal amount of 3.64% Series B Senior Unsecured Notes due
July 30, 2024 (the NMGI Series B 2014 Notes and, with the NMGI Series A 2014 Notes, the NMGI 2014 Notes). The NMGI 2014 Notes were sold at 100% of par. The offering resulted in net proceeds to NMGI (after deducting underwriting discounts,
commissions and estimated offering expenses) of approximately $198.4 million. Net proceeds were used to repay existing indebtedness and for general corporate purposes. NMGI may redeem all or any part of the NMGI 2014 Notes at its option at any time
and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of NMGI 2014 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on the NMGI
notes to be redeemed, discounted at an applicable reinvestment yield (as defined in the note purchase agreement), plus 50 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. The NMGI
2014 Notes were issued in a private placement that was not subject to the registration requirements of the Securities Act of 1933. 

Issuance of New Mexico Gas Company Senior Unsecured 3.54 %
Notes due 2026 
 On Sept. 2, 2014, NMGC completed an offering
of $70 million aggregate principal amount of 3.54% Senior Unsecured Notes due July 30, 2026 (the NMGC 2014 Notes). The NMGC 2014 Notes were sold at 100% of par. The offering resulted in net proceeds to NMGC (after deducting underwriting
discounts, commissions and estimated offering expenses) of approximately $69.3 million. Net proceeds were used to repay existing indebtedness and for general corporate purposes. NMGC may redeem all or any part of the NMGC 2014 Notes at its option at
any time and from time to time at a redemption price equal to the greater of (i) 100% of the 

99


 principal amount of NMGC 2014 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of principal and interest on
the notes to be redeemed, discounted at an applicable reinvestment yield (as defined in the note purchase agreement), plus 50 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. The NMGC 2014
Notes were issued in a private placement that was exempt from the registration requirements of the Securities Act of 1933. 

Amendment of New Mexico Gas Company 4.87 % Notes due 2021 

On Feb. 8, 2011, NMGC issued secured notes in an aggregate
principal amount of $200 million (NMGC 2011 Notes), maturing Feb. 8, 2021. The NMGC 2011 Notes were issued in a private placement that was exempt from the registration requirements of the Securities Act of 1933. 

On July 16, 2014, NMGC received approvals from the
noteholders of the NMGC 2011 Notes to release the collateral securing the NMGC 2011 Notes by amending the existing note purchase agreement. The amendments to the note purchase agreement were subject to the approval of the NMPRC, and on Oct. 22,
2014, NMGC received the required NMPRC approval of the amendments. On Oct. 30, 2014, the amendments became effective, the collateral securing the NMGC 2011 Notes was released and other technical changes were made to the NMGC 2011 Notes. 

Purchase in Lieu of Redemption of Revenue Refunding Bonds 

On Mar. 15, 2012, TEC purchased in lieu of redemption $86.0
million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the Series 2006 HCIDA Bonds). On Mar. 19, 2008, the HCIDA had remarketed the Series 2006 HCIDA Bonds in a term-rate mode pursuant
to the terms of the Loan and Trust Agreement governing those bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 5.00% per annum from Mar. 19, 2008 to Mar. 15, 2012. TEC is responsible for payment of the interest and
principal associated with the Series 2006 HCIDA Bonds. Regularly scheduled principal and interest when due, are insured by Ambac Assurance Corporation. 

On Sept. 3, 2013, TEC purchased in lieu of redemption $51.6
million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B (the Series 2007 B HCIDA Bonds). On Mar. 26, 2008, the HCIDA had remarketed the Series 2007 B HCIDA Bonds in a term-rate mode pursuant to
the terms of the Loan and Trust Agreement governing those bonds. The Series 2007 B HCIDA Bonds bore interest at a term rate of 5.15% per annum from Mar. 26, 2008 to Sept. 1, 2013. TEC is responsible for payment of the interest and
principal associated with the Series 2007 B HCIDA Bonds.
 As
of Dec. 31, 2015, $232.6 million of bonds purchased in lieu of redemption were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives. 

100


 At Dec. 31, 2015 and 2014, TECO Energy had the following long-term debt outstanding: 

 
 
	
Long-Term Debt
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
 
	
 
	
Due
	
 
	
2015
	
 
	
 
	
2014
	
 

	
TECO Finance
	
 
	
Notes (1)(2) : 6.75% (3)
	
 
	
2015
	
 
	
$
	
0.0
	
 
	
 
	
$
	
191.2
	
 

	
 
	
 
	
4.00% (3)
	
 
	
2016
	
 
	
 
	
250.0
	
 
	
 
	
 
	
250.0
	
 

	
 
	
 
	
6.57% (3)
	
 
	
2017
	
 
	
 
	
300.0
	
 
	
 
	
 
	
300.0
	
 

	
 
	
 
	
Floating rate notes
	
 
	
2018
	
 
	
 
	
250.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
5.15% (3)
	
 
	
2020
	
 
	
 
	
300.0
	
 
	
 
	
 
	
300.0
	
 

	
 
	
 
	
Total long-term debt of TECO
Finance
	
 
	
 
	
 
	
 
	
1,100.0
	
 
	
 
	
 
	
1,041.2
	
 

	
Tampa Electric
	
 
	
Installment contracts payable (4) :
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
5.65% Refunding 
bonds
	
 
	
2018
	
 
	
 
	
54.2
	
 
	
 
	
 
	
54.2
	
 

	
 
	
 
	
Variable rate 
bonds repurchased in 2008 (5)
	
 
	
2020
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
5.15% Refunding bonds
repurchased in 2013 (6)
	
 
	
2025
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
1.5% Term rate bonds repurchased
in 2011 (7)
	
 
	
2030
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
5.0% Refunding bonds repurchased
in 2012 (8)
	
 
	
2034
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
Notes (1)(2) : 6.25%
	
 
	
2015-2016
	
 
	
 
	
83.3
	
 
	
 
	
 
	
166.7
	
 

	
 
	
 
	
6.10%
	
 
	
2018
	
 
	
 
	
200.0
	
 
	
 
	
 
	
200.0
	
 

	
 
	
 
	
5.40%
	
 
	
2021
	
 
	
 
	
231.7
	
 
	
 
	
 
	
231.7
	
 

	
 
	
 
	
2.60%
	
 
	
2022
	
 
	
 
	
225.0
	
 
	
 
	
 
	
225.0
	
 

	
 
	
 
	
6.55%
	
 
	
2036
	
 
	
 
	
250.0
	
 
	
 
	
 
	
250.0
	
 

	
 
	
 
	
6.15%
	
 
	
2037
	
 
	
 
	
190.0
	
 
	
 
	
 
	
190.0
	
 

	
 
	
 
	
4.10%
	
 
	
2042
	
 
	
 
	
250.0
	
 
	
 
	
 
	
250.0
	
 

	
 
	
 
	
4.35%
	
 
	
2044
	
 
	
 
	
290.0
	
 
	
 
	
 
	
290.0
	
 

	
 
	
 
	
4.20%
	
 
	
2045
	
 
	
 
	
230.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
Total long-term debt of Tampa
Electric
	
 
	
 
	
 
	
 
	
2,004.2
	
 
	
 
	
 
	
1,857.6
	
 

	
PGS
	
 
	
Notes (2)(3) : 6.10%
	
 
	
2018
	
 
	
 
	
50.0
	
 
	
 
	
 
	
50.0
	
 

	
 
	
 
	
5.40%
	
 
	
2021
	
 
	
 
	
46.7
	
 
	
 
	
 
	
46.7
	
 

	
 
	
 
	
2.60%
	
 
	
2022
	
 
	
 
	
25.0
	
 
	
 
	
 
	
25.0
	
 

	
 
	
 
	
6.15%
	
 
	
2037
	
 
	
 
	
60.0
	
 
	
 
	
 
	
60.0
	
 

	
 
	
 
	
4.10%
	
 
	
2042
	
 
	
 
	
50.0
	
 
	
 
	
 
	
50.0
	
 

	
 
	
 
	
4.35%
	
 
	
2044
	
 
	
 
	
10.0
	
 
	
 
	
 
	
10.0
	
 

	
 
	
 
	
4.20%
	
 
	
2045
	
 
	
 
	
20.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
Total long-term debt of
PGS
	
 
	
 
	
 
	
 
	
261.7
	
 
	
 
	
 
	
241.7
	
 

	
NMGI
	
 
	
Notes (2)(3) : 2.71%
	
 
	
2019
	
 
	
 
	
50.0
	
 
	
 
	
 
	
50.0
	
 

	
 
	
 
	
3.64%
	
 
	
2024
	
 
	
 
	
150.0
	
 
	
 
	
 
	
150.0
	
 

	
 
	
 
	
Total long-term debt of
NMGI
	
 
	
 
	
 
	
 
	
200.0
	
 
	
 
	
 
	
200.0
	
 

	
NMGC
	
 
	
Notes (2)(3) : 4.87%
	
 
	
2021
	
 
	
 
	
200.0
	
 
	
 
	
 
	
200.0
	
 

	
 
	
 
	
3.54%
	
 
	
2026
	
 
	
 
	
70.0
	
 
	
 
	
 
	
70.0
	
 

	
 
	
 
	
Total long-term debt of
NMGC
	
 
	
 
	
 
	
 
	
270.0
	
 
	
 
	
 
	
270.0
	
 

	
 
	
 
	
Total long-term debt of TECO
Energy
	
 
	
 
	
 
	
 
	
3,835.9
	
 
	
 
	
 
	
3,610.5
	
 

	
Unamortized debt discount,
net
	
 
	
 
	
 
	
 
	
 
	
 
	
14.3
	
 
	
 
	
 
	
18.0
	
 

	
Total carrying amount of
long-term debt
	
 
	
 
	
 
	
 
	
3,850.2
	
 
	
 
	
 
	
3,628.5
	
 

	
Less amount due within one
year
	
 
	
 
	
 
	
 
	
 
	
 
	
333.3
	
 
	
 
	
 
	
274.5
	
 

	
Total long-term debt
	
 
	
 
	
 
	
 
	
 
	
$
	
3,516.9
	
 
	
 
	
$
	
3,354.0
	
 





	 (1)
	 Guaranteed by TECO Energy. 





	 (2)
	 These long-term debt agreements contain various restrictive
financial covenants. 



 
	 (3)
	 These securities are subject to redemption in whole or in part,
at any time, at the option of the issuer.



 
	 (4)
	 Tax-exempt securities. 





	 (5)
	 In March 2008 these bonds, which were in auction rate mode, were
purchased in lieu of redemption by TEC.  These held variable rate bonds have a par amount of $20.0 million due in 2020.



 
	 (6)
	 In September 2013 these bonds, which were in term rate mode, were
purchased in lieu of redemption by TEC.  These held term rate bonds have a par amount of $51.6 million due in 2025.




101


 
	 (7)
	 In March 2011 these bonds, which were in term rate mode, were purchased in lieu of redemption by TEC.  These
held term rate bonds have a par amount of $75.0 million due in 2030.



 
	 (8)
	 In March 2012 these bonds, which were in term rate mode, were
purchased in lieu of redemption by TEC.  These held term rate bonds have a par amount of $86.0 million due in 2034.



  

 

8. Preferred Stock 

Preferred stock of TECO Energy – $1 par 
 10 million shares
authorized, none outstanding. 
 Preference stock (subordinated
preferred stock) of Tampa Electric – no par 

2.5 million shares authorized, none outstanding. 

Preferred stock of Tampa Electric – no par 
 2.5 million shares
authorized, none outstanding. 
 Preferred stock of Tampa
Electric – $100 par 

1.5 million shares authorized, none outstanding. 

 
  

9. Common Stock

Pending Merger with Emera

On Sept. 4, 2015, TECO Energy and Emera entered into the Merger
Agreement. Upon closing of the Merger, which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without
interest. 
 The Merger Agreement with Emera restricts TECO
Energy and its subsidiaries, without Emera’s prior written consent, from issuing equity or equity equivalents and from paying quarterly cash dividends in excess of levels agreed upon in the Merger Agreement until the Merger occurs or the
Merger Agreement is terminated.  
 See Note 21 for additional information regarding the pending Merger.

Public Offering of 15.5 million in Common Shares 

On July 1, 2014, the company entered into an underwriting
agreement with Morgan Stanley & Co. LLC, as representative of the several underwriters named therein, pursuant to which the company agreed to offer and sell 15.5 million shares of its common stock in an underwritten public offering at
a public offering price of $18.10 per share. The company received approximately $271 million in net proceeds from the offering after underwriting fees and offering expenses. The shares were delivered to the underwriters on July 8, 2014. 

Pursuant to the terms of the underwriting agreement, the company
granted the underwriters a 30-day option to purchase up to an additional 2.3 million shares. The company received approximately $21 million of net proceeds when the underwriters exercised this option for an additional 1.2 million shares.

 The company used the net proceeds from the offering to fund,
in part, the acquisition of NMGI and for general corporate purposes. 

Stock-Based Compensation 

On May 5, 2010, the shareholders approved the 2010 Equity
Incentive Plan (2010 Plan) as an amendment and restatement of both the company’s 2004 Equity Incentive Plan (2004 Plan) and the 1997 Director Equity Plan (1997 Plan, and together with the 2004 Plan, the Old Plans). The 2010 Plan superseded the
Old Plans and no additional grants will be made under the Old Plans. The rights of the holders of outstanding options, unvested restricted stock or other outstanding awards under the Old Plans were not affected. The purpose of the 2010 Plan is to
attract and retain key employees and non-employee directors, to enable the company to provide equity-based incentives relating to achieving long-range performance goals and to enable award recipients to participate in the long-term growth of the
company. The 2010 Plan is administered by the Compensation Committee of the Board of Directors (Committee), which may grant awards to any employee of the company who is capable of contributing significantly to the successful performance of the
company. Only the Board of Directors may grant awards to any non-employee members of the Board of Directors. 

The 2010 Plan amended the 2004 Plan. The amendment reduced the
number of shares of common stock subject to grants to 4.0 million shares (a reduction of 3.0 million shares), removed the cap on shares available for stock grant, placed various limitations 

102


 on the terms of awards granted under the 2010 Plan, removed the ability to make awards to consultants of the company and reapproved the business criteria upon which objective performance goals may be established by the Committee to continue to permit the company to take federal tax
deductions for performance-based awards made to certain senior officers under Section 162(m) of the tax code. 

The types of awards that can be granted under the 2010 Plan
include stock options, stock grants and stock equivalents. Stock options were last awarded in 2006 under the Old Plans. Stock grants and time-vested restricted stock are valued at the fair market value on the date of grant, with expense recognized
over the vesting period, which is normally three years. Time-vested restricted stock granted to directors vest in one year. Performance-based restricted stock has been granted to officers and employees, with shares potentially vesting after three
years. The total awards for performance-based restricted stock vest based on the total return of TECO Energy common stock compared to a peer group of utility stocks. The performance-based grants can vest in amounts ranging between 0% and 150% of the
original grant. Beginning in 2015, the total awards for performance-based restricted stock vest based on achievement of earnings growth, with the ability to earn more shares based on total return of TECO Energy common stock compared to a peer group
of utility stocks. The 2015 performance-based grants can vest in amounts ranging between 0% and 200% of the original grant. Dividends are paid on all time-vested stock grants during the vesting period. Dividends are accrued during the vesting period
on all performance stock granted and paid at vesting date on the shares that vest. The value of time-vested restricted stock and stock grants are based on the fair market value of TECO Energy common stock at the time of grant. The Merger Agreement
with Emera contains provisions regarding the vesting of outstanding grants which would apply upon closing of the Merger. 

The fair market value of stock options is determined using the
Black-Scholes valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of options granted is based on accounting guidance
for the simplified method of averaging the vesting term and the original contractual term; the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the
option); and the expected dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant. 

The fair market value of performance-based restricted stock
awards is determined using the Monte-Carlo valuation model, and the company uses the following methods to determine its underlying assumptions: expected volatilities are based on the historical volatilities; the expected term of the awards is based
on the performance measurement period (which is generally three years); the risk-free interest rate is based on the U.S. Treasury implied yield on zero-coupon issues (with a remaining term equal to the expected term of the award); and the expected
dividend yield is based on the current annual dividend amount divided by the stock price on the date of grant, with continuous compounding. 

 
 
	
Assumptions
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Assumptions applicable to
performance-based restricted stock
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Risk-free interest rate
	
 
	
 
	
0.83
	
%
	
 
	
 
	
0.68
	
%
	
 
	
 
	
0.41
	
%

	
Expected lives (in
years)
	
 
	
 
	
3
	
 
	
 
	
 
	
3
	
 
	
 
	
 
	
3
	
 

	
Expected stock
volatility
	
 
	
 
	
14.78
	
%
	
 
	
 
	
17.36
	
%
	
 
	
 
	
19.04
	
%

	
Dividend yield
	
 
	
 
	
3.98
	
%
	
 
	
 
	
5.13
	
%
	
 
	
 
	
4.83
	
%




In 2015, 2014 and 2013, 0.7 million, 0.8 million and
0.7 million shares of restricted stock were granted, respectively, with weighted-average fair value per share of $22.96, $14.69 and $17.21, respectively. The total fair market value of awards vesting during 2015, 2014 and 2013 was $7.5 million,
$3.6 million and $3.5 million, respectively, which includes stock grants, time-vested restricted stock and performance-based restricted stock. As of Dec. 31, 2015, there was $13.2 million of unrecognized compensation cost related to all non-vested
awards that is expected to be recognized over a weighted-average period of two years. 

The following table provides additional information on
compensation costs and income tax benefits and excess tax benefits related to the stock-based compensation awards. 

 
 
	
 (millions)
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Compensation costs (1)
	
 
	
$
	
13.1
	
 
	
 
	
$
	
12.7
	
 
	
 
	
$
	
13.5
	
 

	
Income tax benefits (1)
	
 
	
 
	
5.1
	
 
	
 
	
 
	
4.9
	
 
	
 
	
 
	
5.2
	
 

	
Excess tax benefits (2)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.4
	
 
	
 
	
 
	
0.0
	
 





	 (1)
	 Reflected on the Consolidated Statements of Income.




 
	 (2)
	 Reflected as financing activities on the Consolidated Statements
of Cash Flows. 



 The aggregate
intrinsic value of stock options exercised was $2.9 million, $2.7 million and $2.4 million for the periods ended Dec. 31, 2015, 2014 and 2013, respectively. Cash received from option exercises under all share-based payment arrangements was $9.4
million, $10.8 million and $6.7 million for the periods ended Dec. 31, 2015, 2014 and 2013, respectively. The income tax benefit 

103


 realized from stock option exercises was $1.1 million, $1.0 million and $0.8 million for the periods ended Dec. 31, 2015, 2014 and 2013, respectively. 

A summary of non-vested shares of restricted stock is shown as
follows: 
 Nonvested Restricted Stock 

 
 
	
 
	
 
	
Time-Based
Restricted
	
 
	
 
	
Performance-Based

	
 

	
 
	
 
	
Stock (1)
	
 
	
 
	
Restricted Stock (1)
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
Weighted
-
	
 
	
 
	
 
	
 
	
 
	
 
	
Weighted-
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
Avg.
Grant
	
 
	
 
	
 
	
 
	
 
	
 
	
Avg.
Grant
	
 

	
 
	
 
	
Number of
	
 
	
 
	
Date
	
 
	
 
	
Number of
	
 
	
 
	
Date
	
 

	
 
	
 
	
Shares
	
 
	
 
	
Fair
Value
	
 
	
 
	
Shares
	
 
	
 
	
Fair
Value
	
 

	
 
	
 
	
(thousands)
	
 
	
 
	
(per 
share)
	
 
	
 
	
(thousands)
	
 
	
 
	
(per 
share)
	
 

	
Nonvested balance at Dec. 31,
2014
	
 
	
 
	
668
	
 
	
 
	
$
	
17.56
	
 
	
 
	
 
	
1,515
	
 
	
 
	
$
	
15.44
	
 

	
Granted
	
 
	
 
	
213
	
 
	
 
	
$
	
21.34
	
 
	
 
	
 
	
445
	
 
	
 
	
$
	
23.72
	
 

	
Vested
	
 
	
 
	
(273
	
)
	
 
	
$
	
17.96
	
 
	
 
	
 
	
(626
	
)
	
 
	
$
	
15.94
	
 

	
Forfeited
	
 
	
 
	
(19
	
)
	
 
	
$
	
17.78
	
 
	
 
	
 
	
(43
	
)
	
 
	
$
	
16.05
	
 

	
Nonvested balance at Dec. 31,
2015
	
 
	
 
	
589
	
 
	
 
	
$
	
18.74
	
 
	
 
	
 
	
1,291
	
 
	
 
	
$
	
18.06
	
 





	 (1)
	 The weighted-average remaining contractual term of restricted
stock is two years. 



 Stock option
transactions are summarized as follows: 
 Stock Options 

 
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Weighted-Avg.
	
 
	
 
	
Aggregate
	
 

	
 
	
 
	
Number of
	
 
	
 
	
Weighted-Avg.
	
 
	
 
	
Remaining
	
 
	
 
	
Intrinsic
	
 

	
 
	
 
	
Shares
	
 
	
 
	
Option
Price
	
 
	
 
	
Contractual
	
 
	
 
	
Value
	
 

	
 
	
 
	
(thousands)
	
 
	
 
	
(per
share)
	
 
	
 
	
Term
(years)
	
 
	
 
	
(millions)
	
 

	
Outstanding balance at Dec. 31,
2014
	
 
	
 
	
840
	
 
	
 
	
$
	
16.32
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Granted
	
 
	
 
	
0
	
 
	
 
	
$
	
0.00
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Exercised
	
 
	
 
	
(580
	
)
	
 
	
$
	
16.30
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Cancelled
	
 
	
 
	
(6
	
)
	
 
	
$
	
18.87
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Outstanding balance at Dec. 31,
2015 (1)
	
 
	
 
	
254
	
 
	
 
	
$
	
16.30
	
 
	
 
	
 
	
1
	
 
	
 
	
$
	
2.6
	
 

	
Exercisable at Dec. 31, 2015 (1)
	
 
	
 
	
254
	
 
	
 
	
$
	
16.30
	
 
	
 
	
 
	
1
	
 
	
 
	
$
	
2.6
	
 

	
Available for future grant at Dec.
31, 2015
	
 
	
 
	
2,429
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 





	 (1)
	 Option prices are $16.30 per share. 




Direct Stock Purchase and Dividend Reinvestment Plan 

In September 2014, the Direct Stock Purchase and Dividend Plan
amended and restated the 1992 Dividend Reinvestment and Common Stock Purchase Plan. TECO Energy purchased shares on the open market for this plan in 2015, 2014 and 2013, resulting in no increase in shares outstanding.

 
  

104


 10. Other Comprehensive Income

TECO Energy reported the following OCI (loss) for the years ended
Dec. 31, 2015, 2014 and 2013, related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s benefit plans: 

 
 
	
 (millions)
	
 
	
Gross
	
 
	
 
	
Tax
	
 
	
 
	
Net
	
 

	
2015
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Unrealized gain (loss) on cash flow
hedges
	
 
	
$
	
4.3
	
 
	
 
	
$
	
(1.5
	
)
	
 
	
$
	
2.8
	
 

	
Reclassification from AOCI to net
income (1)
	
 
	
 
	
1.4
	
 
	
 
	
 
	
(0.7
	
)
	
 
	
 
	
0.7
	
 

	
Gain (Loss) on cash flow
hedges
	
 
	
 
	
5.7
	
 
	
 
	
 
	
(2.2
	
)
	
 
	
 
	
3.5
	
 

	
Amortization of unrecognized
benefit costs and other (2)
	
 
	
 
	
3.4
	
 
	
 
	
 
	
(1.3
	
)
	
 
	
 
	
2.1
	
 

	
Change in benefit obligation due to
valuation (3)
	
 
	
 
	
(15.5
	
)
	
 
	
 
	
5.7
	
 
	
 
	
 
	
(9.8
	
)

	
Recognized cost due to settlement (4)
	
 
	
 
	
12.1
	
 
	
 
	
 
	
(4.4
	
)
	
 
	
 
	
7.7
	
 

	
Total other comprehensive income
(loss)
	
 
	
$
	
5.7
	
 
	
 
	
$
	
(2.2
	
)
	
 
	
$
	
3.5
	
 

	
2014
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Unrealized gain (loss) on cash flow
hedges
	
 
	
$
	
(0.5
	
)
	
 
	
$
	
0.2
	
 
	
 
	
$
	
(0.3
	
)

	
Reclassification from AOCI to net
income (1)
	
 
	
 
	
1.6
	
 
	
 
	
 
	
(0.6
	
)
	
 
	
 
	
1.0
	
 

	
Gain (Loss) on cash flow
hedges
	
 
	
 
	
1.1
	
 
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
0.7
	
 

	
Amortization of unrecognized
benefit costs and other (2)
	
 
	
 
	
(4.8
	
)
	
 
	
 
	
1.8
	
 
	
 
	
 
	
(3.0
	
)

	
Increase in unrecognized
postemployment costs (5)
	
 
	
 
	
(12.9
	
)
	
 
	
 
	
4.7
	
 
	
 
	
 
	
(8.2
	
)

	
Change in benefit obligation due to
valuation (6)
	
 
	
 
	
12.6
	
 
	
 
	
 
	
(4.6
	
)
	
 
	
 
	
8.0
	
 

	
Total other comprehensive income
(loss)
	
 
	
$
	
(4.0
	
)
	
 
	
$
	
1.5
	
 
	
 
	
$
	
(2.5
	
)

	
2013
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Unrealized gain (loss) on cash flow
hedges
	
 
	
$
	
1.0
	
 
	
 
	
$
	
(0.4
	
)
	
 
	
$
	
0.6
	
 

	
Reclassification from AOCI to net
income (1)
	
 
	
 
	
1.3
	
 
	
 
	
 
	
(0.5
	
)
	
 
	
 
	
0.8
	
 

	
Gain (Loss) on cash flow
hedges
	
 
	
 
	
2.3
	
 
	
 
	
 
	
(0.9
	
)
	
 
	
 
	
1.4
	
 

	
Amortization of unrecognized
benefit costs and other (2)
	
 
	
 
	
23.6
	
 
	
 
	
 
	
(8.8
	
)
	
 
	
 
	
14.8
	
 

	
Recognized costs due to
settlement
	
 
	
 
	
2.6
	
 
	
 
	
 
	
(1.0
	
)
	
 
	
 
	
1.6
	
 

	
Total other comprehensive income
(loss)
	
 
	
$
	
28.5
	
 
	
 
	
$
	
(10.7
	
)
	
 
	
$
	
17.8
	
 





	 (1)
	 Related to interest rate contracts in Interest expense and
commodity contracts recognized in Income (loss) from discontinued operations.



 
	 (2)
	 Related to postretirement and postemployment
benefits.  See Note 5 for additional information.



 
	 (3)
	 Related to the transfer of employees and their associated
postretirement benefits from TEC to TSI, the TECO Energy shared services company. TEC recognized these deferred costs as regulatory assets, whereas TSI recognized them in AOCI.



 
	 (4)
	 Related to the settlement of the TECO Coal black lung obligation
at the closing of the sale. See Note 19 for additional information.



 
	 (5)
	 Amounts reflect an out-of-period adjustment related to TECO
Coal’s unfunded black lung liability.



 
	 (6)
	 Includes an adjustment to eliminate TECO Coal’s OPEB
liability.  See Note 5 for additional information. 




Accumulated Other Comprehensive Loss

 
 
	
 (millions) Dec. 31,
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Unamortized pension losses and
prior service credits (1)
	
 
	
$
	
(34.2
	
)
	
 
	
$
	
(22.5
	
)

	
Unamortized other benefit gains,
prior service costs and transition obligations (2)
	
 
	
 
	
25.6
	
 
	
 
	
 
	
13.9
	
 

	
Net unrealized losses from cash
flow hedges (3)
	
 
	
 
	
(3.6
	
)
	
 
	
 
	
(7.1
	
)

	
Total accumulated other
comprehensive loss
	
 
	
$
	
(12.2
	
)
	
 
	
$
	
(15.7
	
)





	 (1)
	 Net of tax benefit of $21.5 million and $13.8 million as of Dec.
31, 2015 and 2014, respectively. 



 
	 (2)
	 Net of tax expense of $16.1 million and $8.3 million as of Dec.
31, 2015 and 2014, respectively. The Dec. 31, 2014 balance included a $7.7 million loss related to TECO Coal’s unfunded black lung liability that was reclassified from AOCI to net income from discontinued operations upon the settlement of the
black lung obligation at the sale date. See Note 5. 



 
	 (3)
	 Net of tax benefit of $2.3 million and $4.5 million as of Dec.
31, 2015 and 2014, respectively. 



  
  

11. Earnings Per Share 

In accordance with accounting standards for the calculation of
EPS, TECO Energy follows the two-class method for computing EPS. These standards define share-based payment awards that participate in dividends prior to vesting as participating securities that should be included in the earnings allocation in
computing EPS under the two-class method. 

105


 The two-class method of calculating EPS requires TECO Energy to calculate EPS for its common stock and its participating securities (time-vested restricted stock and performance-based restricted stock)
based on dividends declared and the pro-rata share each has to undistributed earnings. The application of the two-class method did not have a material effect on TECO Energy’s EPS calculations. 

 
 
	
 (millions, except per share
amounts)
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013 (1)
	
 

	
Basic earnings per share
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net income from continuing
operations
	
 
	
$
	
241.2
	
 
	
 
	
$
	
206.4
	
 
	
 
	
$
	
188.7
	
 

	
Amount allocated to nonvested
participating shareholders
	
 
	
 
	
(0.7
	
)
	
 
	
 
	
(0.7
	
)
	
 
	
 
	
(0.6
	
)

	
Income before discontinued
operations available to

    common
shareholders—Basic
	
 
	
$
	
240.5
	
 
	
 
	
$
	
205.7
	
 
	
 
	
$
	
188.1
	
 

	
Income (loss) from discontinued
operations
	
 
	
$
	
(67.7
	
)
	
 
	
$
	
(76.0
	
)
	
 
	
$
	
9.0
	
 

	
Amount allocated to nonvested
participating shareholders
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Income (loss) from discontinued
operations —Basic
	
 
	
$
	
(67.7
	
)
	
 
	
$
	
(76.0
	
)
	
 
	
$
	
9.0
	
 

	
Net income
	
 
	
$
	
173.5
	
 
	
 
	
$
	
130.4
	
 
	
 
	
$
	
197.7
	
 

	
Amount allocated to nonvested
participating shareholders
	
 
	
 
	
(0.7
	
)
	
 
	
 
	
(0.7
	
)
	
 
	
 
	
(0.6
	
)

	
Net income available to common
shareholders—Basic
	
 
	
$
	
172.8
	
 
	
 
	
$
	
129.7
	
 
	
 
	
$
	
197.1
	
 

	
Average common shares
outstanding—Basic
	
 
	
 
	
233.1
	
 
	
 
	
 
	
223.1
	
 
	
 
	
 
	
215.0
	
 

	
Earnings per share from continuing
operations available to

   common
shareholders—Basic
	
 
	
$
	
1.03
	
 
	
 
	
$
	
0.92
	
 
	
 
	
$
	
0.88
	
 

	
Earnings per share from
discontinued operations available to common

  
shareholders—Basic
	
 
	
 
	
(0.29
	
)
	
 
	
 
	
(0.34
	
)
	
 
	
 
	
0.04
	
 

	
Earnings per share attributable to
TECO Energy available

    to common
shareholders—Basic
	
 
	
$
	
0.74
	
 
	
 
	
$
	
0.58
	
 
	
 
	
$
	
0.92
	
 

	
Diluted earnings per share
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net income from continuing
operations
	
 
	
$
	
241.2
	
 
	
 
	
$
	
206.4
	
 
	
 
	
$
	
188.7
	
 

	
Amount allocated to nonvested
participating shareholders
	
 
	
 
	
(0.7
	
)
	
 
	
 
	
(0.7
	
)
	
 
	
 
	
(0.6
	
)

	
Income before discontinued
operations available to

   common
shareholders—Diluted
	
 
	
$
	
240.5
	
 
	
 
	
$
	
205.7
	
 
	
 
	
$
	
188.1
	
 

	
Income (loss) from discontinued
operations
	
 
	
$
	
(67.7
	
)
	
 
	
$
	
(76.0
	
)
	
 
	
$
	
9.0
	
 

	
Amount allocated to nonvested
participating shareholders
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Income (loss) from discontinued
operations available to common

  
shareholders—Diluted
	
 
	
$
	
(67.7
	
)
	
 
	
$
	
(76.0
	
)
	
 
	
$
	
9.0
	
 

	
Net income
	
 
	
$
	
173.5
	
 
	
 
	
$
	
130.4
	
 
	
 
	
$
	
197.7
	
 

	
Amount allocated to nonvested
participating shareholders
	
 
	
 
	
(0.7
	
)
	
 
	
 
	
(0.7
	
)
	
 
	
 
	
(0.6
	
)

	
Net income available to common
shareholders—Diluted
	
 
	
$
	
172.8
	
 
	
 
	
$
	
129.7
	
 
	
 
	
$
	
197.1
	
 

	
Unadjusted average common shares
outstanding—Diluted
	
 
	
 
	
233.1
	
 
	
 
	
 
	
223.1
	
 
	
 
	
 
	
215.0
	
 

	
Assumed conversion of stock
options, unvested restricted

   stock and contingent
performance shares, net
	
 
	
 
	
1.4
	
 
	
 
	
 
	
0.6
	
 
	
 
	
 
	
0.5
	
 

	
Average common shares
outstanding—Diluted
	
 
	
 
	
234.5
	
 
	
 
	
 
	
223.7
	
 
	
 
	
 
	
215.5
	
 

	
Earnings per share from continuing
operations available to

   common
shareholders—Diluted
	
 
	
$
	
1.03
	
 
	
 
	
$
	
0.92
	
 
	
 
	
$
	
0.88
	
 

	
Earnings per share from
discontinued operations available to common

  
shareholders—Diluted
	
 
	
 
	
(0.29
	
)
	
 
	
 
	
(0.34
	
)
	
 
	
 
	
0.04
	
 

	
Earnings per share available to
common shareholders—Diluted
	
 
	
$
	
0.74
	
 
	
 
	
$
	
0.58
	
 
	
 
	
$
	
0.92
	
 

	
Anti-dilutive shares
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 





	  (1)
	 All prior periods presented reflect the classification of TECO
Coal as discontinued operations (see Note 19). 



  

 

12. Commitments and Contingencies 

Legal Contingencies 

From time to time, TECO Energy and its subsidiaries are involved
in various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for
contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in which the company or a subsidiary of the company is a defendant in the pending actions described below are without merit and
intends to defend the matters vigorously. The company is unable at this time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does 

106


 not believe that their ultimate resolution will have a material adverse effect on the company’s results of
operations, financial condition or cash flows. 
 Tampa
Electric Legal Proceedings
 A 36-year-old man died from
mesothelioma in March 2014. His estate and his family sued Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at
various job sites throughout the Tampa area. Plaintiff’s case against Tampa Electric and 14 other defendants had alleged, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death. Tampa
Electric has agreed to a settlement which resolved the case in its entirety. The settlement is not material to the company’s financial position as of Dec. 31, 2015. 

 

A 33-year-old man made contact with a primary line in June 2013,
suffering severe burns. He and his wife sued Tampa Electric as a result. The man apparently made contact with the line as he was attempting to trim a tree at a local residence.  Plaintiffs' case against Tampa Electric alleged, among other
things, negligence and loss of consortium. Tampa Electric has agreed to a settlement which resolved the case in its entirety. The settlement is not material to the company’s financial position as of Dec. 31, 2015.

Peoples Gas Legal Proceedings 

In November 2010, heavy equipment operated at a road construction
site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen
Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014,
the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County
Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in late 2016. 

New Mexico Gas Company Legal Proceedings 

In February 2011, NMGC experienced gas shortages due to
weather-related interruptions of electric service, weather-related problems on the systems of various interstate pipelines and in gas fields that are the sources of gas supplied to NMGC, and high weather-driven usage. This gas supply disruption and
high usage resulted in the declaration of system emergencies by NMGC causing involuntary curtailments of gas utility service to approximately 28,700 customers (residential and business).  

In March 2011, a customer purporting to represent a class
consisting of all “32,000 [sic] customers” who had their gas utility service curtailed during the early-February system emergencies filed a putative class action lawsuit against NMGC. In March 2011, the Town of Bernalillo, New Mexico,
purporting to represent a class consisting of all “New Mexico municipalities and governmental entities who have suffered damages as a result of the natural gas utility shut off” also filed a putative class action lawsuit against NMGC,
four of its officers, and John and Jane Does at NMGC. In July 2011, the plaintiff in the Bernalillo class action filed an amended complaint to add an additional plaintiff purporting to represent a class of all “similarly situated New Mexico
private businesses and enterprises.”  
 In
September 2015, a settlement was reached with all the named plaintiff class representatives in both of the class actions. The settlements were on an individual basis and not a class basis. The settlements are not material to the company’s
financial position as of Dec. 31, 2015.
 In addition to the
two settled class actions described above, 18 insurance carriers have filed two subrogation lawsuits for monies paid to their insureds as a result of the curtailment of natural gas service in February 2011. In January 2016, the judge entered summary
judgement in favor of NMGC and all of the subrogation lawsuits were dismissed. The insurance carriers subsequently filed a timely appeal of the summary judgement.  

TECO Guatemala Holdings, LLC v. The Republic of Guatemala 

On Dec. 19, 2013, the ICSID Tribunal hearing the arbitration
claim of TGH, a wholly owned subsidiary of TECO Energy, against the Republic of Guatemala (Guatemala) under the DR – CAFTA, issued an award in the case (the Award). The ICSID Tribunal unanimously found in favor of TGH and awarded damages to
TGH of approximately U.S. $21.1 million, plus interest from Oct. 21, 2010 at a rate equal to the U.S. prime rate plus 2%. In addition, the ICSID Tribunal ruled that Guatemala must reimburse TGH for approximately U.S. $7.5 million of the costs
that it incurred in pursuing the arbitration. 
 On
Apr. 18, 2014, Guatemala filed an application for annulment of the entire Award (or, alternatively, certain parts of the Award) pursuant to applicable ICSID rules. 

107


 Also on Apr. 18, 2014, TGH separately filed an application for partial annulment of the Award on the basis of certain deficiencies in the ICSID Tribunal’s determination of the
amount of TGH’s damages. If TGH’s application is successful, TGH will be able to seek additional damages from Guatemala in a new arbitration proceeding. 

While the duration of the annulment proceedings is uncertain, a
hearing was held in October 2015, with a decision by the ad hoc committee expected in mid- to late-2016. Pending the outcome of annulment proceedings, results to date do not reflect any benefit of this decision. 

Proceedings in connection with the Pending Merger with Emera

Twelve securities class action lawsuits were filed against the
company and its directors by holders of TECO Energy securities following the announcement of the Emera transaction.  Eleven suits were filed in the Circuit Court for the 13th Judicial Circuit, in and for Hillsborough County,
Florida.  They alleged that TECO Energy’s board of directors breached its fiduciary duties in agreeing to the Merger Agreement and sought to enjoin the Merger.  In addition, several of these suits alleged that one or more
of TECO Energy, Emera and an Emera affiliate aided and abetted such alleged breaches. The securities class action lawsuits have been consolidated per court order.  Since the consolidation, two of the complaints have been amended. One of
those complaints has added a claim against the individual defendants for breach of fiduciary duty to disclose.  The twelfth suit was filed in the Middle District of Florida Federal Court and has subsequently been voluntarily dismissed.

The company also received two separate shareholder demand letters
from purported shareholders of the company.  Both of these letters demanded that the company maximize shareholder value and remove alleged conflicts of interest as well as eliminate allegedly preclusive deal protection
devices.  One of the letters also demanded that the company refrain from consummating the transaction with Emera. Both of these demand letters have subsequently been withdrawn.  

In November 2015, the parties to the lawsuits entered into a
Memorandum of Understanding with the various shareholder plaintiffs to settle, subject to court approval, all of the pending shareholder lawsuits challenging the proposed Merger.  As a result of the Memorandum of Understanding, the company
made additional disclosures related to the proposed Merger in a proxy supplement.  Per the terms of the Memorandum of Understanding, the parties will negotiate a settlement agreement and submit it to the court for approval after the Merger
is complete.  There can be no assurance that the parties will ultimately enter into a stipulation of settlement or that the court will approve the settlement even if the parties were to enter into a stipulation of settlement.

PGS Compliance Matter

          In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which
were identified during PGS’ implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant
corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed.  As a result of this report, the Office of Public Counsel (OPC) filed
a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On Feb. 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation
to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. PGS is continuing to work with the OPC and FPSC staff to resolve the issues.

Superfund and Former Manufactured Gas Plant Sites 

TEC, through its Tampa Electric and Peoples Gas divisions, is a
PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of
Dec. 31, 2015, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other
liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates. 

The estimated amounts represent only the portion of the cleanup
costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current
dollars, are not discounted and do not assume any insurance recoveries. 

In instances where other PRPs are involved, most of those PRPs
are creditworthy and are likely to continue to be creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. 

Factors that could impact these estimates include the ability of
other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in
laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings. 

108


 Long-Term Commitments 

TECO Energy has commitments for capacity payments and long-term
leases, primarily for building space, vehicles, office equipment and heavy equipment. Rental expense for these leases included in “Regulated operations and maintenance – Other”, “Operation & maintenance other expense
– Other” and “Discontinued Operations” on the Consolidated Statements of Income for the years ended Dec. 31, 2015, 2014 and 2013 totaled $15.3 million, $13.7 million and $7.6 million, respectively.  In addition, the
company has other purchase obligations, including Tampa Electric’s outstanding commitments for major projects and long-term capitalized maintenance agreements for its combustion turbines.  The following is a schedule of future
minimum lease payments with non-cancelable lease terms in excess of one year, capacity payments under PPAs, and other net purchase obligations/commitments at Dec. 31, 2015: 

 
 
	
 
	
 
	
Capacity
	
 
	
 
	
Operating
	
 
	
 
	
Net
Purchase
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
Payments
	
 
	
 
	
Leases(1)
	
 
	
 
	
Obligations/Commitments
(1)
	
 
	
 
	
Total
	
 

	
Year ended Dec. 31:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
2016
	
 
	
$
	
14.6
	
 
	
 
	
$
	
7.7
	
 
	
 
	
$
	
222.5
	
 
	
 
	
$
	
244.8
	
 

	
2017
	
 
	
 
	
9.9
	
 
	
 
	
 
	
7.1
	
 
	
 
	
 
	
21.5
	
 
	
 
	
 
	
38.5
	
 

	
2018
	
 
	
 
	
10.1
	
 
	
 
	
 
	
6.4
	
 
	
 
	
 
	
9.6
	
 
	
 
	
 
	
26.1
	
 

	
2019
	
 
	
 
	
0.0
	
 
	
 
	
 
	
5.7
	
 
	
 
	
 
	
9.7
	
 
	
 
	
 
	
15.4
	
 

	
2020
	
 
	
 
	
0.0
	
 
	
 
	
 
	
5.4
	
 
	
 
	
 
	
4.7
	
 
	
 
	
 
	
10.1
	
 

	
Thereafter
	
 
	
 
	
0.0
	
 
	
 
	
 
	
18.6
	
 
	
 
	
 
	
20.0
	
 
	
 
	
 
	
38.6
	
 

	
Total future minimum
payments
	
 
	
$
	
34.6
	
 
	
 
	
$
	
50.9
	
 
	
 
	
$
	
288.0
	
 
	
 
	
$
	
373.5
	
 





	 (1)
	 Reflects those contractual obligations and commitments
considered material to the respective operating companies, individually. The table above excludes payment obligations under contractual agreements of Tampa Electric, PGS and NMGC for fuel, fuel transportation and power purchases which are recovered
from customers under regulatory clauses. 




Guarantees and Letters of Credit 

TECO Energy accounts for guarantees in accordance with the
applicable accounting standards. Upon issuance or modification of a guarantee the company determines if the obligation is subject to either or both of the following: 
 
	  
	 ●
	 Initial
recognition and initial measurement of a liability, and/or 



 
	  
	 ●
	 Disclosure of
specific details of the guarantee. 




Generally, guarantees of the performance of a third party or
guarantees that are based on an underlying (where such a guarantee is not a derivative) are likely to be subject to the recognition and measurement, as well as the disclosure provisions. Such guarantees must initially be recorded at fair value, as
determined in accordance with the interpretation. 

Alternatively, guarantees between and on behalf of entities
under common control or that are similar to product warranties are subject only to the disclosure provisions of the interpretation. The company must disclose information as to the term of the guarantee and the maximum potential amount of future
gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote. 

A summary of the face amount or maximum theoretical obligation
under TECO Energy’s letters of credit and guarantees as of Dec. 31, 2015 are as follows: 




109


  

 
 
	
 (millions)
	
 
	
Year of
Expiration
	
 
	
 
	
Maximum
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
After (1)
	
 
	
 
	
Theoretical
	
 
	
 
	
Liabilities 
Recognized
	
 

	
Guarantees for the Benefit
of:
	
 
	
2016
	
 
	
 
	
2017-2020
	
 
	
 
	
2020
	
 
	
 
	
Obligation
	
 
	
 
	
at Dec. 31,
2015
	
 

	
TECO Energy
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
     Fuel sales
and transportation (2)
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
92.9
	
 
	
 
	
$
	
92.9
	
 
	
 
	
$
	
0.0
	
 

	
     Letters of
indemnity - coal mining permits (3)
	
 
	
 
	
90.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
90.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
$
	
90.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
92.9
	
 
	
 
	
$
	
182.9
	
 
	
 
	
$
	
0.0
	
 




 

 
 
	
(millions)
	
 
	
Year of
Expiration
	
 
	
 
	
Maximum
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
After (1)
	
 
	
 
	
Theoretical
	
 
	
 
	
Liabilities 
Recognized
	
 

	
Letter of Credit for the Benefit
of:
	
 
	
2016
	
 
	
 
	
2017-2020
	
 
	
 
	
2020
	
 
	
 
	
Obligation
	
 
	
 
	
at Dec. 31, 2015 (4)
	
 

	
TEC
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.5
	
 
	
 
	
$
	
0.5
	
 
	
 
	
$
	
0.1
	
 

	
NMGC
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
1.7
	
 
	
 
	
$
	
1.7
	
 
	
 
	
$
	
0.0
	
 

	
(1)    
These letters of credit and guarantees renew annually and are shown on the basis that they will continue to renew beyond 2020.

	
(2)    
The amounts shown represent the maximum theoretical amounts of cash collateral that TECO Energy would be required to post in the event of a downgrade below investment grade for its long-term debt ratings by the major credit rating agencies.
Liabilities recognized represent the associated potential obligation related to net derivative liabilities under these agreements at Dec. 31, 2015. See Note 16 for additional information.

	
(3)    
These letters of indemnity guarantee payments to certain surety companies that issued reclamation bonds to the Commonwealths of Kentucky and Virginia in connection with TECO Coal's mining operations.  Payments to the surety companies would
be triggered if the reclamation bonds are called upon by either of these states and the permit holder, TECO Coal, does not pay the surety. The amounts shown represent the maximum theoretical amounts that TECO Energy would be required to pay to the
surety companies. As discussed in Note 19, TECO Coal was sold on Sept. 21, 2015 to Cambrian.  Pursuant to the SPA, Cambrian is obligated to file applications required in connection with the change of
control with the appropriate governmental entities.  Once the applicable governmental agency deems each application to be acceptable, Cambrian is obligated to post a bond or other appropriate collateral necessary to obtain the release of
the corresponding bond secured by the TECO Energy indemnity for that permit. Until the bonds secured by TECO Energy's indemnity are released, TECO Energy's indemnity will remain effective. At the date of sale in September 2015, the letters of
indemnity guaranteed $93.8 million. The company is working with Cambrian on the process to replace the bonds and expects the process to be completed in 2016. Pursuant to the SPA, Cambrian has the obligation to indemnify and hold TECO Energy harmless
from any losses incurred that arise out of the coal mining permits during the period commencing on the closing date through the date all permit approvals are obtained.

	
(4)    
The amounts shown are the maximum theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation of TECO Energy, TEC or NMGC under these agreements at Dec. 31, 2015. The obligations under these
letters of credit include certain accrued injuries and damages when a letter of credit covers the failure to pay these claims.




 

Financial Covenants

In order to utilize their respective bank credit facilities, TECO
Energy and its subsidiaries must meet certain financial tests as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2015,
TECO Energy and its subsidiaries were in compliance with all required financial covenants. 
  

 

13. Related Party Transactions 

The company and its subsidiaries had certain transactions, in the
ordinary course of business, with entities in which directors of the company had interests. The company paid legal fees of $1.7 million for the year ended Dec. 31, 2013 to Ausley McMullen, P.A. of which Mr. DuBose Ausley (who was a director of
TECO Energy, until his retirement from the Board in May 2013) was an employee. Other transactions were not material for the years ended Dec. 31, 2015, 2014 and 2013. No material balances were payable as of Dec. 31, 2015 or 2014. 

 
  

14. Segment Information 

TECO Energy is primarily an electric and gas utility holding
company. Its diversified activities have been classified as discontinued operations. Segments are determined based on how management evaluates, measures and makes decisions with respect to the operations of the entity. The management of TECO Energy
reports segments based on each segment’s contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related 

110


 information. All significant intercompany transactions are eliminated in the Consolidated Financial Statements of TECO Energy, but are included in
determining reportable segments. 
 Tampa Electric
provides retail electric utility services to almost 719,000 customers in West Central Florida. PGS is engaged in the purchase and distribution of natural gas for approximately 361,000 residential, commercial, industrial and electric power generation
customers in the State of Florida. NMGC is engaged in the purchase and distribution of natural gas for more than 516,000 residential, commercial, industrial customers in the State of New Mexico.
 
	
 
	
 
	
Tampa
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
TECO
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
TECO
	
 

	
(millions)
	
 
	
Electric
	
 
	
 
	
PGS
	
 
	
 
	
NMGC (4)
	
 
	
 
	
Coal (2)
	
 
	
 
	
Other (4),(5)
	
 
	
 
	
Eliminations (5)
	
 
	
 
	
Energy
	
 

	
2015
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Revenues—external
	
 
	
$
	
2,014.9
	
 
	
 
	
$
	
401.5
	
 
	
 
	
$
	
316.5
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
10.6
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
2,743.5
	
 

	
Sales to affiliates
	
 
	
 
	
3.4
	
 
	
 
	
 
	
6.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.1
	
 
	
 
	
 
	
(9.5
	
)
	
 
	
 
	
0.0
	
 

	
Total revenues
	
 
	
 
	
2,018.3
	
 
	
 
	
 
	
407.5
	
 
	
 
	
 
	
316.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
10.7
	
 
	
 
	
 
	
(9.5
	
)
	
 
	
 
	
2,743.5
	
 

	
Depreciation and
amortization
	
 
	
 
	
256.7
	
 
	
 
	
 
	
56.8
	
 
	
 
	
 
	
33.8
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
349.0
	
 

	
Total interest charges (1)
	
 
	
 
	
95.1
	
 
	
 
	
 
	
14.5
	
 
	
 
	
 
	
13.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
65.1
	
 
	
 
	
 
	
(1.3
	
)
	
 
	
 
	
186.4
	
 

	
Internally allocated interest (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.3
	
 
	
 
	
 
	
(1.3
	
)
	
 
	
 
	
0.0
	
 

	
Provision for income taxes
	
 
	
 
	
143.6
	
 
	
 
	
 
	
21.9
	
 
	
 
	
 
	
15.4
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(25.6
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
155.3
	
 

	
Net income from continuing
operations
	
 
	
 
	
241.0
	
 
	
 
	
 
	
35.3
	
 
	
 
	
 
	
24.1
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(59.2
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
241.2
	
 

	
Discontinued operations, net of
tax
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(69.6
	
)
	
 
	
 
	
1.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(67.7
	
)

	
Net income
	
 
	
 
	
241.0
	
 
	
 
	
 
	
35.3
	
 
	
 
	
 
	
24.1
	
 
	
 
	
 
	
(69.6
	
)
	
 
	
 
	
(57.3
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
173.5
	
 

	
Goodwill
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
408.4
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
408.4
	
 

	
Total assets
	
 
	
 
	
7,020.7
	
 
	
 
	
 
	
1,137.4
	
 
	
 
	
 
	
1,231.3
	
 
	
 
	
 
	
0.0
	
 
	
(3)
	
 
	
1,947.9
	
 
	
 
	
 
	
(2,376.2
	
)
	
(6)
	
 
	
8,961.1
	
 

	
Capital expenditures
	
 
	
 
	
592.6
	
 
	
 
	
 
	
94.0
	
 
	
 
	
 
	
48.7
	
 
	
 
	
 
	
3.7
	
 
	
 
	
 
	
0.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
739.7
	
 

	
2014
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Revenues—external
	
 
	
$
	
2,019.9
	
 
	
 
	
$
	
398.5
	
 
	
 
	
$
	
137.5
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
10.5
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
2,566.4
	
 

	
Sales to affiliates
	
 
	
 
	
1.1
	
 
	
 
	
 
	
1.1
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
(2.4
	
)
	
 
	
 
	
0.0
	
 

	
Total revenues
	
 
	
 
	
2,021.0
	
 
	
 
	
 
	
399.6
	
 
	
 
	
 
	
137.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
10.7
	
 
	
 
	
 
	
(2.4
	
)
	
 
	
 
	
2,566.4
	
 

	
Depreciation and
amortization
	
 
	
 
	
248.6
	
 
	
 
	
 
	
54.0
	
 
	
 
	
 
	
11.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
315.3
	
 

	
Total interest charges (1)
	
 
	
 
	
92.8
	
 
	
 
	
 
	
13.8
	
 
	
 
	
 
	
4.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
66.1
	
 
	
 
	
 
	
(5.8
	
)
	
 
	
 
	
171.1
	
 

	
Internally allocated interest (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
5.8
	
 
	
 
	
 
	
(5.8
	
)
	
 
	
 
	
0.0
	
 

	
Provision for income taxes
	
 
	
 
	
133.2
	
 
	
 
	
 
	
22.7
	
 
	
 
	
 
	
7.1
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(24.1
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
138.9
	
 

	
Net income from continuing
operations
	
 
	
 
	
224.5
	
 
	
 
	
 
	
35.8
	
 
	
 
	
 
	
10.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(64.4
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
206.4
	
 

	
Discontinued operations, net of
tax
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(82.0
	
)
	
 
	
 
	
6.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(76.0
	
)

	
Net income
	
 
	
 
	
224.5
	
 
	
 
	
 
	
35.8
	
 
	
 
	
 
	
10.5
	
 
	
 
	
 
	
(82.0
	
)
	
 
	
 
	
(58.4
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
130.4
	
 

	
Goodwill
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
408.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
408.3
	
 

	
Total assets
	
 
	
 
	
6,565.4
	
 
	
 
	
 
	
1,082.8
	
 
	
 
	
 
	
1,237.2
	
 
	
 
	
 
	
227.7
	
 
	
(3)
	
 
	
1,611.6
	
 
	
 
	
 
	
(1,998.5
	
)
	
(6)
	
 
	
8,726.2
	
 

	
Capital expenditures
	
 
	
 
	
582.1
	
 
	
 
	
 
	
88.9
	
 
	
 
	
 
	
18.2
	
 
	
 
	
 
	
14.6
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
703.8
	
 

	
2013
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Revenues—external
	
 
	
$
	
1,949.6
	
 
	
 
	
$
	
392.7
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
12.8
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
2,355.1
	
 

	
Sales to affiliates
	
 
	
 
	
0.9
	
 
	
 
	
 
	
0.8
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.5
	
 
	
 
	
 
	
(2.2
	
)
	
 
	
 
	
0.0
	
 

	
Total revenues
	
 
	
 
	
1,950.5
	
 
	
 
	
 
	
393.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
13.3
	
 
	
 
	
 
	
(2.2
	
)
	
 
	
 
	
2,355.1
	
 

	
Depreciation and
amortization
	
 
	
 
	
238.8
	
 
	
 
	
 
	
51.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
291.8
	
 

	
Total interest charges (1)
	
 
	
 
	
91.8
	
 
	
 
	
 
	
13.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
63.9
	
 
	
 
	
 
	
(7.8
	
)
	
 
	
 
	
161.4
	
 

	
Internally allocated interest (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
7.8
	
 
	
 
	
 
	
(7.8
	
)
	
 
	
 
	
0.0
	
 

	
Provision for income taxes
	
 
	
 
	
116.9
	
 
	
 
	
 
	
21.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(26.2
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
112.6
	
 

	
Net income from continuing
operations
	
 
	
 
	
190.9
	
 
	
 
	
 
	
34.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(36.9
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
188.7
	
 

	
Discontinued operations, net of
tax
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
9.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
9.0
	
 

	
Net income
	
 
	
 
	
190.9
	
 
	
 
	
 
	
34.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
9.0
	
 
	
 
	
 
	
(36.9
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
197.7
	
 

	
Total assets
	
 
	
 
	
6,126.9
	
 
	
 
	
 
	
1,021.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
316.3
	
 
	
(3)
	
 
	
1,739.2
	
 
	
 
	
 
	
(1,755.6
	
)
	
(6)
	
 
	
7,448.0
	
 

	
Capital expenditures
	
 
	
 
	
422.3
	
 
	
 
	
 
	
79.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
22.4
	
 
	
 
	
 
	
2.4
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
526.1
	
 




 
 
	 (1)
	 Segment net income is reported on a basis that includes
internally allocated financing costs. Total interest charges include internally allocated interest costs that for 2015, 2014 and 2013 were at a pretax rate of 6.00%, based on an average of each subsidiary’s equity and indebtedness to TECO
Energy assuming a 50/50 debt/equity capital structure. 



 
	 (2)
	 All periods have been adjusted to reflect the reclassification of
results from operations to discontinued operations for TECO Coal and certain charges at Other, including Parent and TECO Diversified, that directly relate to TECO Coal or TECO Guatemala. See Note 19.




 111


 
	 (3)
	 The carrying value of mineral rights as of Dec. 31, 2015, 2014 and 2013 was $0.0 million, $10.9 million and $12.1 million, respectively. 



 
	 (4)
	 NMGI is included in the Other segment.




 
	 (5)
	 Certain prior year amounts have been reclassified to conform to
current year presentation.



 
	 (6)
	 Amounts primarily relate to consolidated tax
eliminations.



  
  

15. Asset Retirement Obligations 

TECO Energy accounts for AROs under the applicable accounting
standards. An ARO for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract or by legal construction under the doctrine of
promissory estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset. 

When the liability is initially recorded, the carrying amount of
the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The
liability must be revalued each period based on current market prices. 

Prior to the sale of TECO Coal on Sept. 21, 2015, TECO Energy
had recognized AROs for reclamation and site restoration obligations principally associated with coal mining, storage and transfer facilities at TECO Coal. The majority of obligations were related to environmental remediation and restoration
activities for coal-related operations. At Dec. 31, 2014, these obligations totaled $22.5 million and were classified as Liabilities Associated with Assets Held for Sale on TECO Energy’s Consolidated Balance Sheet. 

TECO Energy’s regulated utilities must file depreciation
and dismantlement studies periodically and receive approval from the FPSC or NMPRC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor, expressed as
a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. The company uses current cost of removal or dismantlement factors as part of the estimation method
to approximate the amount of cost of removal in accumulated depreciation. 

For Tampa Electric, PGS and NMGC, the original cost of utility
plant retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively. At Dec. 31,
2015 and 2014, these obligations totaled $6.8 million and $6.1 million, respectively. 

Reconciliation of beginning and ending carrying amount of asset
retirement obligations: 
  
 
	
 
	
 
	
Dec. 31,
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Beginning balance
	
 
	
$
	
6.1
	
 
	
 
	
$
	
28.6
	
 

	
Additional liabilities
	
 
	
 
	
0.9
	
 
	
 
	
 
	
0.1
	
 

	
Revisions to estimated cash
flows
	
 
	
 
	
(0.5
	
)
	
 
	
 
	
0.2
	
 

	
Acquisition of NMGC
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.8
	
 

	
Reclassification to liabilities
associated with assets held for sale
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(22.5
	
)

	
Other (1)
	
 
	
 
	
0.3
	
 
	
 
	
 
	
(1.1
	
)

	
Ending balance
	
 
	
$
	
6.8
	
 
	
 
	
$
	
6.1
	
 





	  (1)
	 2015 includes $0.3 million accretion recorded as a deferred
regulatory asset. 2014 includes $(1.3) million of activity associated with TECO Coal and classified as discontinued operations and $0.2 million accretion recorded as a deferred regulatory asset. 




 
  

16. Accounting for Derivative Instruments and Hedging Activities 

From time to time, TECO Energy and its affiliates enter into
futures, forwards, swaps and option contracts for the following purposes: 
 
	  
	 ·
	 To limit the exposure to price fluctuations for
physical purchases and sales of natural gas in the course of normal operations at Tampa Electric, PGS and NMGC; and



 
	  
	 ·
	 To limit the exposure to interest rate
fluctuations on debt securities at TECO Energy and its affiliates. 




TECO Energy and its affiliates use derivatives only to reduce
normal operating and market risks, not for speculative purposes. The regulated utilities’ primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers. 

112


 The risk management policies adopted by TECO Energy provide a framework through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by
a centralized risk management group, which is independent of all operating companies. 

The company applies the accounting standards for derivative
instruments and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of
those instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 17). The changes in fair value that are recorded in OCI are not immediately recognized
in current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the
instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction. 

The company applies the accounting standards for regulated
operations to financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC and NMPRC, permit the changes in fair value of natural gas derivatives to be recorded as
regulatory assets or liabilities reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3). 

The company’s physical contracts qualify for the NPNS
exception to derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if the company deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical
delivery of the commodity, if the company intends to receive physical delivery and if the transaction is reasonable in relation to the company’s business needs. As of Dec. 31, 2015, all of the company’s physical contracts qualify for the
NPNS exception.
 The derivatives that are designated as cash
flow hedges at Dec. 31, 2015 and 2014 are reflected on the company’s Consolidated Balance Sheets and classified accordingly as current and long term assets and liabilities on a net basis as permitted by their respective master netting
agreements. Derivative assets totaled $0.2 and $0.0 million as of Dec. 31, 2015 and 2014, respectively, and are included in “Prepayments and other current assets” on the Consolidated Balance Sheet. Derivative liabilities totaled $26.2
million and $42.7 million as of Dec. 31, 2015 and 2014, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated Balance Sheets. There was no
collateral posted with or received from any counterparties. 

All of the derivative asset and liabilities at Dec. 31, 2015 and
2014 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The
corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Balance Sheets as current and long term regulatory assets and liabilities. Based on the
fair value of the instruments at Dec. 31, 2015, net pretax losses of $23.9 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months. 

The Dec. 31, 2015 and 2014 balance in AOCI related to the cash
flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 10. 

For derivative instruments that meet cash flow hedge criteria,
the effective portion of the gain or loss on the derivative is reported as a component of OCI and reclassified into earnings in the same period or period during which the hedged transaction affects earnings. Gains and losses on the derivatives
representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the years ended Dec. 31, 2015, 2014 and 2013, all hedges were effective. The derivative after-tax
effect on OCI and the amount of after-tax gain or loss reclassified from AOCI into earnings for the years ended Dec. 31, 2015, 2014 and 2013 is presented in Note 10. These gains and losses were the result of
interest rate contracts for TEC and diesel fuel derivatives related to TECO Coal operations. The locations of the reclassifications to income were reflected in “Interest expense” for TEC and “Income (loss) from discontinued
operations” for TECO Coal. 
 The maximum length of time
over which the company is hedging its exposure to the variability in future cash flows extends to Nov. 30, 2017 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Dec. 31, 2015, are
expected to settle during the 2016 and 2017 fiscal years: 

 
 
	
 
	
 
	
Natural Gas
Contracts
	
 

	
(millions)
	
 
	
(MMBTUs)
	
 

	
Year
	
 
	
Physical
	
 
	
 
	
Financial
	
 

	
2016
	
 
	
 
	
0.0
	
 
	
 
	
 
	
38.4
	
 

	
2017
	
 
	
 
	
0.0
	
 
	
 
	
 
	
5.1
	
 

	
Total
	
 
	
 
	
0.0
	
 
	
 
	
 
	
43.5
	
 




113


 The company is exposed to credit risk by entering into derivative instruments with counterparties to limit its exposure
to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. The company manages credit risk with policies and procedures for, among other things,
counterparty analysis, exposure measurement and exposure monitoring and mitigation. 

It is possible that volatility in commodity prices could cause
the company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the company could suffer a material financial loss. However, as of Dec. 31,
2015, substantially all of the counterparties with transaction amounts outstanding in the company’s energy portfolio were rated investment grade by the major rating agencies. The company assesses credit risk internally for counterparties that
are not rated. 
 The company has entered into commodity master
arrangements with its counterparties to mitigate credit exposure to those counterparties. The company generally enters into the following master arrangements: (1) EEI agreements—standardized power sales contracts in the electric industry;
(2) ISDA agreements—standardized financial gas and electric contracts; and (3) NAESB agreements—standardized physical gas contracts. The company believes that entering into such agreements reduces the risk from default by
creating contractual rights relating to creditworthiness, collateral and termination. 

The company has implemented procedures to monitor the
creditworthiness of its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as the company uses derivative
transactions as hedges and has the ability and intent to perform under each of these contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific
counterparties in evaluating the potential impact of nonperformance risk to derivative positions. 

Certain TECO Energy derivative instruments contain provisions
that require the company’s debt, or in the case of derivative instruments where TEC is the counterparty, TEC’s debt, to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings,
including TEC’s, were to fall below investment grade, it could trigger these provisions, and the counterparties to the derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net
liability positions. The company has no other contingent risk features associated with any derivative instruments. 
  

 

17. Fair Value Measurements 

Items Measured at Fair Value on a Recurring Basis 

Accounting guidance governing fair value measurements and
disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a
market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value
hierarchy, which prioritizes the inputs used in measuring fair value as follows: 

Level 1: Observable inputs, such as quoted prices in active
markets; 
 Level 2: Inputs, other than quoted prices in active
markets, that are observable either directly or indirectly; and 

Level 3: Unobservable inputs for which there
is little or no market data, which require the reporting entity to develop its own assumptions. 

Assets and liabilities are measured at fair value based on one
or more of the following three valuation techniques noted under accounting guidance: 
 
	  
	 (A)
	 Market approach: Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities; 



 
	  
	 (B)
	 Cost approach: Amount that would be required to replace the service capacity of an asset (replacement cost); and 



 
	  
	 (C)
	 Income approach: Techniques to convert future amounts to a single present amount based upon market expectations (including present value techniques, option-pricing and excess earnings models). 




The fair value of financial instruments is determined by using
various market data and other valuation techniques. 
 The
following tables set forth by level within the fair value hierarchy, the company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Dec. 31, 2015 and 2014. As required by accounting standards
for fair value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The company’s assessment of the significance of a particular
input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. 

114


 Recurring Fair Value Measures 

 
 
	
 
	
 
	
As of Dec. 31,
2015
	
 

	
(millions)
	
 
	
Level 
1
	
 
	
 
	
Level 
2
	
 
	
 
	
Level 
3
	
 
	
 
	
Total
	
 

	
Assets
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Natural gas derivatives
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.2
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.2
	
 

	
Liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Natural gas derivatives
	
 
	
$
	
0.0
	
 
	
 
	
$
	
26.2
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
26.2
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
As of Dec. 31,
2014
	
 

	
(millions)
	
 
	
Level 
1
	
 
	
 
	
Level 
2
	
 
	
 
	
Level 
3
	
 
	
 
	
Total
	
 

	
Liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Natural gas derivatives
	
 
	
$
	
0.0
	
 
	
 
	
$
	
42.7
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
42.7
	
 




 

The natural gas derivatives are OTC swap and option
instruments.  Fair values of swaps and options are estimated utilizing the market and income approach, respectively.  The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. The price of
options is calculated using the Black-Scholes model with observable exchange-traded futures as the primary pricing inputs to the model. Additional inputs to the model include historical volatility, discount rate, and a locational basis adjustment to
NYMEX. The resulting prices are applied to the notional quantities of active swap and option positions to determine the fair value (see Note 16).  

The company considered the impact of nonperformance risk in
determining the fair value of derivatives. The company considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which the
company transacts have experienced dislocation. At Dec. 31, 2015, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented. 

See Notes 5, 7 and 19 for
information regarding the fair value of the company’s pension plan investments, long-term debt, and asset impairment charge, respectively.
  

 

18. Variable Interest Entities 

The determination of a VIE’s primary beneficiary is the
enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or
the right to receive benefits from the entity that could potentially be significant to the VIE. 

Tampa Electric has entered into multiple PPAs with wholesale
energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 157 MW of available capacity, are with similar entities
and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include:
operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of
the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, Tampa Electric is not required to
consolidate any of these entities. Tampa Electric purchased $33.6 million, $25.7 million and $22.1 million, under these PPAs for the three years ended Dec. 31, 2015, 2014 and 2013, respectively. 

The company does not provide any material financial or other
support to any of the VIEs it is involved with, nor is the company under any obligation to absorb losses associated with these VIEs. In the normal course of business, the company’s involvement with these VIEs does not affect its Consolidated
Balance Sheets, Statements of Income or Cash Flows. 
  
  

115


 19. Discontinued Operations, Assets Held for Sale and Asset Impairments 

TECO Coal 

In 2013, TECO Coal temporarily idled some of its mines due to the
softened coal market. As a result, the company performed impairment analyses in the fourth quarter of 2013 on the mining complexes with closed mines and the coal reserves. The company used an undiscounted cash flows approach in determining the
recoverability amount of the assets in accordance with applicable accounting guidance. All assets were determined to have carrying values that were recoverable; therefore, no impairment charge was deemed necessary in 2013. Additionally, the company
performed sensitivity analyses for the effects of inflation and noted that if inflation affected costs more than revenues by one percent each year, all assets would still be recoverable. 

In September 2014, the Board of Directors of TECO Energy
authorized management to actively pursue the sale of TECO Coal. As a result of this and other factors, the TECO Coal segment was accounted for as an asset held for sale and reported as a discontinued operation beginning in the third quarter of 2014.
All periods have been adjusted to reflect the reclassification of results from operations to discontinued operations for TECO Coal and certain charges at Parent that directly relate to the sale of TECO Coal. 

In 2014, the company recorded impairment charges totaling $115.9
million pretax to write down the held-for-sale TECO Coal assets to their implied fair value based on the price specified in an agreement of sale entered into in October 2014, which agreement had conditions to closing that were not satisfied, less
estimated costs of the transaction. In the second quarter of 2015, based on management’s assessment of current market conditions and discussions with interested parties, an additional impairment charge of $78.6 million pretax was recorded,
which included the estimated selling costs associated with the transaction completed in September 2015. The fair value measurements were considered Level 2 measurements since the market is not active as defined by accounting standards (i.e.
transactions for these assets are too infrequent to provide pricing information on an ongoing basis). None of these impairments had cash flow impacts. The asset impairment charges are recorded in the “Income (loss) from discontinued
operations” line item in the Consolidated Statements of Income and the “Asset impairment” line item in the Consolidated Statements of Cash Flows for the years ended Dec. 31, 2014 and 2015.   

On Sept. 21, 2015, TECO Energy’s
subsidiary, TECO Diversified, entered into the SPA and completed the sale of all of its ownership interest in TECO Coal to Cambrian.  The SPA did not provide for an up-front purchase payment, but provides for future contingent
consideration of up to $60 million that may be paid yearly through 2019 if certain coal benchmark prices reach certain levels. The 2015 benchmark price was not reached and no contingent consideration payment was triggered. TECO Energy retains
certain deferred tax assets and personnel-related liabilities, but all other TECO Coal assets and liabilities, including working capital, asset retirement obligations and workers compensation reserves, were transferred in the
transaction.  The retained liabilities included pension liability, which was fully funded at Sept. 30, 2015, and severance agreements, which were accrued at June 30, 2015 and paid in the third quarter of 2015. Letters of indemnity related
to TECO Coal reclamation bonds will remain in effect until the bonds are replaced by Cambrian, which is expected to be completed in 2016 (see description of guarantees in Note 12).  The company
recorded a loss on sale of $10.0 million pretax, which is reflected in discontinued operations in the company’s Consolidated Condensed Statement of Income, primarily to write off an after-tax settlement charge of $7.7 million related to the
unfunded black lung obligations previously recorded in AOCI. Transaction-related costs of $12.3 million pretax, comprised of $2.5 million of legal and other consultant costs and $9.8 million of severance and other employee costs, were accrued at
June 30, 2015 and reflected in discontinued operations in the company’s Consolidated Condensed Statement of Income. The transaction-related costs were paid in 2015, with the exception of a minor amount of severance payments. 

Since the closing of the sale, TECO Energy has not and will not
have influence over operations of TECO Coal, therefore the contingent payments are not considered to meet the definition of direct cash flows under the applicable discontinued operations FASB guidance.

The following table provides a summary of the carrying amounts
of the significant assets and liabilities reported in the combined current and non-current “Assets held for sale” and “Liabilities associated with assets held for sale” line items: 

 
 
	
Assets held for sale
	
 
	
 
	
 

	
(millions)
	
Dec. 31,
2014
	
 

	
Current assets
	
$
	
109.6
	
 

	
Property, plant and equipment, net
and other long-term assets
	
 
	
59.8
	
 

	
Total assets held for
sale
	
$
	
169.4
	
 

	
 
	
 
	
 
	
 

	
Liabilities associated with assets held for sale
	
 
	
 
	
 

	
(millions)
	
 
	
 
	
 

	
Current liabilities
	
$
	
39.4
	
 

	
Long-term liabilities
	
 
	
65.4
	
 

	
Total liabilities associated
with assets held for sale
	
$
	
104.8
	
 



 116


 TECO Guatemala 

In 2012, TECO Guatemala completed the sale of its interests in
the Alborada and San José power stations, and related solid fuel handling and port facilities in Guatemala. All periods presented reflect the classification of results from operations for TECO Guatemala and certain charges at Parent that
directly relate to TECO Guatemala as discontinued operations. While TECO Energy and its subsidiaries no longer have assets or operations in Guatemala, its subsidiary, TECO Guatemala Holdings, LLC, has retained its rights under its arbitration claim
filed against the Republic of Guatemala (see Note 12). The 2015 charges shown in the table below are legal costs associated with that claim.  Additionally, in March 2014, an indemnification provision
for an uncertain tax position at TCAE that was provided for in the 2012 purchase agreement was reversed due to a favorable final decision by the highest court in Guatemala, resulting in the income from operations amount shown in the table below.

 Combined components of income from discontinued operations 

The following table provides selected components of discontinued
operations related to TECO Coal and TECO Guatemala: 
  


	
Components of income from discontinued
operations
	
 
	
 
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Revenues—TECO Coal
	
 
	
$
	
200.4
	
 
	
 
	
$
	
443.6
	
 
	
 
	
$
	
496.2
	
 

	
Income (loss) from
operations—TECO Coal
	
 
	
 
	
(16.9
	
)
	
 
	
 
	
(13.9
	
)
	
 
	
 
	
5.4
	
 

	
Income (loss) from
operations—TECO Guatemala
	
 
	
 
	
(0.8
	
)
	
 
	
 
	
4.4
	
 
	
 
	
 
	
(0.2
	
)

	
Loss on impairment—TECO
Coal
	
 
	
 
	
(78.6
	
)
	
 
	
 
	
(115.9
	
)
	
 
	
 
	
0.0
	
 

	
Loss on sale—TECO
Coal
	
 
	
 
	
(10.0
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Income (loss) from discontinued
operations—TECO Coal
	
 
	
 
	
(105.5
	
)
	
 
	
 
	
(129.8
	
)
	
 
	
 
	
5.4
	
 

	
Income (loss) from discontinued
operations—TECO Guatemala
	
 
	
 
	
(0.8
	
)
	
 
	
 
	
4.4
	
 
	
 
	
 
	
(0.2
	
)

	
Income (loss) from discontinued
operations
	
 
	
 
	
(106.3
	
)
	
 
	
 
	
(125.4
	
)
	
 
	
 
	
5.2
	
 

	
Provision (benefit) for income
taxes
	
 
	
 
	
(38.6
	
)
	
 
	
 
	
(49.4
	
)
	
 
	
 
	
(3.8
	
)

	
Income (loss) from discontinued
operations, net
	
 
	
 $
	
(67.7
	
)
	
 
	
 $
	
(76.0
	
)
	
 
	
 $
	
9.0
	
 




 
  

20. Goodwill 

The following table presents the changes in the carrying amount
of goodwill for the years ended Dec. 31, 2015, 2014 and 2013. 

 
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
NMGC
	
 
	
 
	
Total
	
 

	
Balance as of Dec. 31,
2013
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 

	
Acquisition of NMGC
	
 
	
 
	
408.3
	
 
	
 
	
 
	
408.3
	
 

	
Balance as of Dec. 31,
2014
	
 
	
 
	
408.3
	
 
	
 
	
 
	
408.3
	
 

	
Measurement period adjustments (1)
	
 
	
 
	
0.1
	
 
	
 
	
 
	
0.1
	
 

	
Balance as of Dec. 31,
2015
	
 
	
$
	
408.4
	
 
	
 
	
$
	
408.4
	
 





	 (1)
	 Due to immateriality, the measurement period adjustment was not
applied retrospectively to the opening balance sheet.




The goodwill on the company’s balance sheet related to the
NMGC segment was recorded upon acquisition of NMGI on Sept. 2, 2014 (see Note 21). Under the accounting guidance for goodwill, goodwill is not subject to amortization. Rather, goodwill is subject to an annual
assessment for impairment at the reporting unit level. Reporting units are generally determined at the operating segment level or one level below the operating segment level; reporting units with similar characteristics are grouped for the purpose
of determining the impairment, if any, of goodwill. Since NMGC is the lowest level of identifiable cash flows, this is the level at which goodwill is tested. Entities assessing goodwill for impairment have the option of first performing a
qualitative assessment to determine whether a quantitative assessment is necessary. If an entity performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount or if an entity
bypasses the qualitative assessment, a quantitative two-step, fair value-based test is performed. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit
exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation accounting guidance in order to determine the implied fair value of
goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. TECO Energy reviews recorded goodwill at least annually (during the fourth
quarter) for each reporting unit.
 The fair value for NMGC
was determined in the fourth quarter using a weighted combination of a discounted cash flow analysis, a market multiple analysis, and a comparable transactions analysis. The discounted cash flow analysis relies on management’s best estimate of
NMGC’s projected cash flows. It includes an estimate of NMGC’s terminal value based on these expected cash flows using the Gordon Growth Formula, which derives a valuation using an assumed perpetual annuity based on the entity’s
residual cash 
 117


 flows. The discount rate is a market participant rate based on a peer group of publicly traded comparable companies and
represents the weighted average cost of capital of comparable companies. The market multiples analysis
utilizes multiples of business enterprise value to EBITDA of comparable public companies in estimating fair value. The comparable transaction analysis identified comparable company acquisitions within the industry and calculates the implied EBITDA multiple from the transaction, which is then applied to the
last-twelve-months EBITDA of the subject company. Significant assumptions used in estimating the fair value include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows and the calculation of the
terminal value. 
 The company determined the fair
value of NMGC exceeds the book value and related goodwill carrying amounts at Dec. 31, 2015 and 2014, resulting in no impairment charge. Adverse changes in assumptions described above could result in a future material impairment of NMGC’s
goodwill.
  
  

21. Mergers and Acquisitions

Pending Merger with Emera Inc.

On Sept. 4, 2015, TECO Energy and Emera entered into the
Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned indirect subsidiary of Emera. 

Upon the terms and subject to the conditions set forth in the
Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation. 

Pursuant to the Merger Agreement, upon the closing of the Merger,
which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This
represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt. 

The closing of the Merger is subject to certain conditions,
including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock (which approval was obtained at the special meeting of shareholders held on Dec. 3, 2015),
(ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period (which expired on Feb. 5, 2016), (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign
Investment in the United States (which, with respect to the FERC, was obtained on Jan. 20, 2016) (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material
adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement. 

The Merger Agreement contains customary representations,
warranties and covenants of TECO Energy, Emera and Merger Sub. The Merger Agreement contains covenants by TECO Energy, among others, that (i) TECO Energy will conduct its business in the ordinary course during the interim period between the
execution of the Merger Agreement and the closing of the Merger and (ii) TECO Energy will not engage in certain transactions during such interim period. The Merger Agreement contains covenants by Emera, among others, that Emera will use its
reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals. 

In addition, the Merger Agreement requires Emera (i) to
maintain TECO Energy’s historic levels of community involvement and charitable contributions and support in TECO Energy’s existing service territories, (ii) to maintain TECO Energy’s headquarters in Tampa, Florida,
(iii) to honor current union contracts in accordance with their terms and (iv) to provide each continuing non-union employee, for a period of two years following the closing of the Merger, with a base salary or wage rate no less favorable than,
and incentive compensation and employee benefits, respectively, substantially comparable in the aggregate to those, that they received as of immediately prior to the closing. 

TECO Energy is also subject to a “no shop”
restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties. 

The Merger Agreement contains certain termination rights for both
TECO Energy and Emera. Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals), (ii) a
law or judgment preventing or prohibiting the closing of the Merger has become final, (iii) TECO Energy’s shareholders do not approve the Merger or (iv) TECO Energy’s board of directors changes its recommendation so that it is
no longer in favor of the Merger. If either party terminates the Merger Agreement because TECO Energy’s board of directors changes its recommendation, TECO Energy must pay Emera a termination fee of $212.5 million. If the Merger Agreement is
terminated under certain other circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million. 

118


 During the year ended Dec. 31, 2015, TECO Energy incurred approximately $17.0 million pretax of incremental transaction-related costs, which are included in “Operations and maintenance other expense” on the Consolidated Condensed Statements of Income.

 

Acquisition of New Mexico Gas Company

Description of Transaction 

On Sept. 2, 2014, the company completed the acquisition of NMGI
contemplated by the acquisition agreement dated May 25, 2013 by and among the company, NMGI and Continental Energy Systems LLC. As a result of that acquisition, the company acquired all of the capital stock of NMGI. NMGI is the parent company
of NMGC. The aggregate purchase price was $950 million, which included the assumption of $200 million of senior secured notes at NMGC, plus certain working capital adjustments. 

Description of NMGC 

On the acquisition date, NMGC, with approximately 720 employees,
served more than 513,000 customers, predominately residential, in New Mexico with the majority located in the Central Rio Grande Corridor region, which is one of the fastest growing regions in the state. The company served approximately 60 percent
of the state’s population with customers in 23 of New Mexico’s 33 counties. Customers are served through a combination of approximately 1,600 miles of transmission pipeline and 10,000 miles of distribution lines. 

Strategic Rationale for Acquisition 
 
	  
	 ·
	 A transformative transaction that immediately
added more than 513,000 customers in a single state. 



 
	  
	 ·
	 Provides an opportunity for TECO Energy’s
experienced management team to share marketing expertise to a new and growing service territory, and for both companies to share best practices to support growth. 



 
	  
	 ·
	 Diversifies TECO Energy’s operating
footprint. 



 
	  
	 ·
	 Provides immediate to near-term shareholder and
customer benefits through organic growth opportunities. 




Acquisition-Related Regulatory Matters 

NMGC is a rate-regulated natural gas utility subject to the
regulation of the NMPRC, including with respect to its rates, service standards, accounting, securities issuances, construction of major new transmission and distribution facilities and other matters affecting, directly or indirectly, the provision
of natural gas sales and transportation services to NMGC’s customers. 

In May 2014, TECO Energy reached a settlement with the New
Mexico Industrial Energy Consumers (which represents large customers), the New Mexico Attorney General’s office (which represents the New Mexico residential and small business customers) and the U.S. Department of Energy. As part of this
settlement of the application for approval of the acquisition by the NMPRC, TECO Energy agreed, among other things, to: 
 
	  
	 ·
	 freeze rates for NMGC customers until the end of
2017, 



 
	  
	 ·
	 credit NMGC customers with a $2 million rate
credit to customer bills in 2015, increasing to $4 million per year in 2016 and each year after 2016 until NMGC’s next rate case, 



 
	  
	 ·
	 cap job losses in New Mexico at 99 over three
years, many of which will be through attrition, 



 
	  
	 ·
	 maintain the NMGC name and headquarters in
Albuquerque, 



 
	  
	 ·
	 support new economic development opportunities
designed to attract new businesses to New Mexico through maintaining good service and reasonable customer rates, 



 
	  
	 ·
	 maintain or increase NMGC’s current level of
community involvement and support, and 



 
	  
	 ·
	 own NMGC for at least 10 years.




 On Aug. 13, 2014, the NMPRC
approved the acquisition with the conditions set forth in the settlement agreements described above. The transaction closed on Sept. 2, 2014. 

119


 Purchase Price 

The total consideration in the acquisition was as follows: 

Consideration Transferred 
 
	
(millions)
	
 
	
 
	
 
	
 

	
Cash paid to seller
	
 
	
$
	
530.1
	
 

	
Cash paid to settle long-term debt,
including accrued interest and fees
	
 
	
 
	
219.9
	
 

	
Long-term debt assumed
	
 
	
 
	
200.0
	
 

	
Total consideration transferred,
excluding cash and working capital adjustments
	
 
	
$
	
950.0
	
 



 Purchase Price Allocation 

The majority of NMGI’s assets acquired and liabilities
assumed relate to deferred income taxes associated with its NOL. These were recorded in accordance with the applicable accounting guidance. Additionally, the company paid off the existing outstanding debt at NMGI and issued $200 million of new NMGI
debt at closing. Since the refinancing took place at closing, face value approximated fair value. 

The majority of NMGC’s operations are subject to the
rate-setting authority of the NMPRC and are accounted for pursuant to U.S. GAAP, including the accounting guidance for regulated operations. Rate-setting and cost recovery provisions currently in place for NMGC’s regulated operations provide
revenues derived from costs, including a return on investment of assets and liabilities included in rate base. Except for long-term debt, the ARO, derivatives, OPEB plans, and deferred taxes, fair values of tangible and intangible assets and
liabilities subject to these rate-setting provisions approximate their carrying values. Accordingly, assets acquired and liabilities assumed and pro-forma financial information do not reflect any net adjustments related to these amounts. The
difference between fair value and pre-merger carrying amounts for long-term debt, derivatives, and the OPEB plan for regulated operations were recorded as regulatory assets or liabilities. 

The excess of the purchase price over the estimated fair values
of assets acquired and liabilities assumed was recognized as goodwill at the acquisition date. The goodwill reflects the value paid primarily for opportunities for growth, synergies and an improved risk profile. Goodwill resulting from the
acquisition was allocated entirely to the NMGC segment. Goodwill of $146.1 million related to the formation of NMGC in 2009 is tax deductible. The incremental goodwill recognized as part of this transaction is not deductible for income tax purposes,
and as such, no deferred taxes were recorded related to this portion of the goodwill. 

The final purchase price allocation of the acquisition of NMGI
and NMGC was as follows: 
  
 
	
Purchase Price Allocation
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
 
	
 
	
 

	
Current assets (1)
	
 
	
$
	
48.7
	
 

	
Property, plant and
equipment
	
 
	
 
	
616.4
	
 

	
OPEB regulatory asset
	
 
	
 
	
6.4
	
 

	
Debt-related regulatory
asset
	
 
	
 
	
23.9
	
 

	
Goodwill
	
 
	
 
	
408.4
	
 

	
Deferred tax assets
	
 
	
 
	
52.8
	
 

	
Other assets
	
 
	
 
	
29.3
	
 

	
Total assets
	
 
	
$
	
1,185.9
	
 

	
Current liabilities
	
 
	
$
	
(38.2
	
)

	
Long-term debt fair value
adjustment and interest assumed
	
 
	
 
	
(22.7
	
)

	
Cost of removal regulatory
liability
	
 
	
 
	
(100.6
	
)

	
Deferred tax liabilities
	
 
	
 
	
(60.8
	
)

	
OPEB liability
	
 
	
 
	
(9.8
	
)

	
Deferred credits and other
liabilities
	
 
	
 
	
(3.8
	
)

	
Total liabilities
	
 
	
$
	
(235.9
	
)

	
Total purchase price allocation,
excluding cash and working

   capital
adjustments
	
 
	
$
	
950.0
	
 




120


 
	 (1) 
	 Includes accounts receivables with fair value of $18.9 million, gross contract value of $19.6 million, and $0.7 million of contractual receivables not expected to be collected. 




Impact of Acquisition 

The impact of NMGI and NMGC on the company’s revenues in
the Consolidated Statements of Operations for the years ended Dec. 31, 2015 and 2014 was an increase of $316.5 million and $137.5 million, respectively. The impact of NMGI and NMGC on the company’s net income in the Consolidated Statements of
Operations for the years ended Dec. 31, 2015 and 2014 was an increase of $19.6 million and $8.2 million, respectively. 

Pro Forma Impact of the Acquisition 

The following unaudited pro forma financial information reflects
the consolidated results of operations of the company and reflects the amortization of purchase accounting adjustments assuming the acquisition had taken place on Jan. 1, 2013. The unaudited pro forma financial information has been presented for
illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the company. 

Pro forma earnings presented below include adjustments related
to non-recurring acquisition consummation, integration and other costs incurred by the company during the period. After-tax non-recurring acquisition consummation, integration and other costs incurred by the company were $8.6 million and $6.2
million for the years ended Dec. 31, 2014 and 2013, respectively. 

 
 
	
Pro Forma Impact of
Acquisition
	
 
	
For the year ended
Dec. 31,
	
 

	
(millions, except per share
amounts)
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Revenues
	
 
	
$
	
2,806.6
	
 
	
 
	
$
	
2,704.0
	
 

	
Net income from continuing
operations
	
 
	
 
	
223.8
	
 
	
 
	
 
	
216.8
	
 

	
Basic and diluted EPS from
continuing operations
	
 
	
 
	
0.96
	
 
	
 
	
 
	
0.93
	
 



 Transaction and Integration Costs 

The following after-tax transaction and integration charges were
recognized in connection with the acquisition and are included in the TECO Energy Consolidated Statement of Income for the years ended Dec. 31, 2015 and 2014. 

 
 
	
Transaction and Integration
Costs
	
 
	
For the year ended
Dec. 31,
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Legal and other
consultants
	
 
	
$
	
0.5
	
 
	
 
	
$
	
8.0
	
 

	
Bridge loan costs
	
 
	
 
	
0.0
	
 
	
 
	
 
	
3.3
	
 

	
Severance and relocation
costs
	
 
	
 
	
1.0
	
 
	
 
	
 
	
2.8
	
 

	
Other costs and tax
benefit
	
 
	
 
	
0.4
	
 
	
 
	
 
	
(5.5
	
)

	
Total accounting
charges
	
 
	
$
	
1.9
	
 
	
 
	
$
	
8.6
	
 




The company has an ongoing severance plan under which, in
general, the longer a terminated employee worked prior to termination, the greater the amount of severance benefits. The company records a liability and expense for severance once terminations are probable of occurrence and the related severance
benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the company measures the obligation and records the expense at its fair value at the
communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period. 

In conjunction with the acquisition, in September 2014, TECO
Energy and NMGC each offered a severance plan to certain eligible employees. Severance costs incurred were recorded primarily within Operation and maintenance other expense in the Consolidated Condensed Statements of Income. Cash payments under the
severance plan began in the third quarter of 2014, and substantially all cash payments under the plan are expected to be made by the end of 2017 resulting in the substantial completion of the acquisition integration plan. As of Dec. 31, 2015 and
2014, the obligations associated with the severance benefits costs were $0.7 million and $2.6 million, respectively. 
  

 

121


 22. Quarterly Data (unaudited) 

Financial data by quarter is as follows: 

 
 
	
 (millions, except per share
amounts)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Quarter ended
	
 
	
Dec. 
31
	
 
	
 
	
Sept. 30
	
 
	
 
	
June 30
	
 
	
 
	
Mar. 31
	
 

	
2015
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Revenues
	
 
	
$
	
676.1
	
 
	
 
	
$
	
693.8
	
 
	
 
	
$
	
680.6
	
 
	
 
	
$
	
693.0
	
 

	
Income from operations
	
 
	
 
	
126.0
	
 
	
 
	
 
	
146.6
	
 
	
 
	
 
	
143.3
	
 
	
 
	
 
	
146.2
	
 

	
Net income from continuing
operations
	
 
	
 
	
51.0
	
 
	
 
	
 
	
64.9
	
 
	
 
	
 
	
61.5
	
 
	
 
	
 
	
63.8
	
 

	
Net income
	
 
	
 
	
50.5
	
 
	
 
	
 
	
53.2
	
 
	
 
	
 
	
11.8
	
 
	
 
	
 
	
58.0
	
 

	
EPS—Basic
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net income from continuing
operations
	
 
	
$
	
0.22
	
 
	
 
	
$
	
0.28
	
 
	
 
	
$
	
0.26
	
 
	
 
	
$
	
0.27
	
 

	
Net income
	
 
	
 
	
0.21
	
 
	
 
	
 
	
0.23
	
 
	
 
	
 
	
0.05
	
 
	
 
	
 
	
0.25
	
 

	
EPS—Diluted
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net income from continuing
operations
	
 
	
$
	
0.22
	
 
	
 
	
$
	
0.28
	
 
	
 
	
$
	
0.26
	
 
	
 
	
$
	
0.27
	
 

	
Net income
	
 
	
 
	
0.21
	
 
	
 
	
 
	
0.23
	
 
	
 
	
 
	
0.05
	
 
	
 
	
 
	
0.25
	
 

	
Dividends paid per common share
outstanding
	
 
	
$
	
0.225
	
 
	
 
	
$
	
0.225
	
 
	
 
	
$
	
0.225
	
 
	
 
	
$
	
0.225
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Quarter ended
	
 
	
Dec. 
31
	
 
	
 
	
Sept. 30
	
 
	
 
	
June 30
	
 
	
 
	
Mar. 31
	
 

	
2014
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Revenues
	
 
	
$
	
695.5
	
 
	
 
	
$
	
687.2
	
 
	
 
	
$
	
605.7
	
 
	
 
	
$
	
578.0
	
 

	
Income from operations
	
 
	
 
	
112.1
	
 
	
 
	
 
	
145.7
	
 
	
 
	
 
	
132.0
	
 
	
 
	
 
	
115.6
	
 

	
Net income from continuing
operations
	
 
	
 
	
27.4
	
 
	
 
	
 
	
73.0
	
 
	
 
	
 
	
57.6
	
 
	
 
	
 
	
48.4
	
 

	
Net income
	
 
	
 
	
10.8
	
 
	
 
	
 
	
11.1
	
 
	
 
	
 
	
58.4
	
 
	
 
	
 
	
50.1
	
 

	
EPS—Basic
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net income from continuing
operations
	
 
	
$
	
0.11
	
 
	
 
	
$
	
0.32
	
 
	
 
	
$
	
0.27
	
 
	
 
	
$
	
0.22
	
 

	
Net income
	
 
	
 
	
0.04
	
 
	
 
	
 
	
0.04
	
 
	
 
	
 
	
0.27
	
 
	
 
	
 
	
0.23
	
 

	
EPS—Diluted
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net income from continuing
operations
	
 
	
$
	
0.11
	
 
	
 
	
$
	
0.32
	
 
	
 
	
$
	
0.27
	
 
	
 
	
$
	
0.22
	
 

	
Net income
	
 
	
 
	
0.04
	
 
	
 
	
 
	
0.04
	
 
	
 
	
 
	
0.27
	
 
	
 
	
 
	
0.23
	
 

	
Dividends paid per common share
outstanding
	
 
	
$
	
0.220
	
 
	
 
	
$
	
0.220
	
 
	
 
	
$
	
0.220
	
 
	
 
	
$
	
0.220
	
 




Amounts shown include reclassifications to reflect discontinued
operations as discussed in Note 19. 
  
  

23. Subsequent Events

Amendment of TECO Energy/TECO Finance Credit Facility

On Feb. 24, 2016, TECO Energy and TECO Finance entered into
Amendment No. 3 to its Fourth Amended and Restated Credit Agreement (the TECO Credit Facility) with JPMorgan Chase Bank, N.A., as administrative agent, and certain lenders named therein.  The amendment provides that the closing of the Merger
will not constitute an event of default under the TECO Credit Facility. 

TECO Energy/TECO Finance One-Year Term Loan Facility

In February 2016, TECO Energy (as guarantor) and TECO Finance (as
borrower) secured commitments for a $400 million one-year term loan facility, the terms of which provide for closing and funding on Mar. 14, 2016.  The proceeds of the facility are to be used to repay at maturity the $250 million aggregate
principal amount of TECO Finance 4.00% Notes due Mar. 15, 2016, repay a portion of the drawings under the TECO Credit Facility and for general corporate purposes. 

 
  

 
  

122


 This Page Intentionally Left Blank




123


 TAMPA ELECTRIC COMPANY 

 


Report of Independent Registered Certified Public Accounting Firm 

To the Board of Directors and Shareholder of Tampa Electric
Company: 
  

In our opinion, the consolidated financial statements listed in the
index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Tampa Electric Company and its subsidiaries at December 31, 2015 and 2014, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.  In
addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated
financial statements.  These financial statements and the financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements and the
financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

 

As discussed in Note 2 to the financial statements, the Company
changed the manner in which it classifies deferred taxes in 2015.
  

/s/ PricewaterhouseCoopers LLP 

Tampa, Florida 

February 26, 2016 

 
  

 

124


 TAMPA ELECTRIC COMPANY 


Consolidated Balance Sheets 
  
 
	
Assets
	
 
	
Dec. 31,
	
 
	
 
	
Dec. 31,
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Property, plant and
equipment
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Utility plant in
service
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Electric
	
 
	
$
	
7,270.3
	
 
	
 
	
$
	
7,094.8
	
 

	
Gas
	
 
	
 
	
1,398.6
	
 
	
 
	
 
	
1,308.9
	
 

	
Construction work in
progress
	
 
	
 
	
771.1
	
 
	
 
	
 
	
624.2
	
 

	
Utility plant in service, at
original costs
	
 
	
 
	
9,440.0
	
 
	
 
	
 
	
9,027.9
	
 

	
Accumulated
depreciation
	
 
	
 
	
(2,676.8
	
)
	
 
	
 
	
(2,633.8
	
)

	
Utility plant in service,
net
	
 
	
 
	
6,763.2
	
 
	
 
	
 
	
6,394.1
	
 

	
Other property
	
 
	
 
	
9.7
	
 
	
 
	
 
	
8.6
	
 

	
Total property, plant and
equipment, net
	
 
	
 
	
6,772.9
	
 
	
 
	
 
	
6,402.7
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Current assets
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Cash and cash
equivalents
	
 
	
 
	
9.1
	
 
	
 
	
 
	
10.4
	
 

	
Receivables, less allowance for
uncollectibles of $1.5 and $1.4 at Dec. 31, 2015 and 2014, respectively
	
 
	
 
	
230.2
	
 
	
 
	
 
	
227.2
	
 

	
Inventories, at average
cost
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Fuel
	
 
	
 
	
105.6
	
 
	
 
	
 
	
85.2
	
 

	
Materials and supplies
	
 
	
 
	
73.1
	
 
	
 
	
 
	
72.2
	
 

	
Regulatory assets
	
 
	
 
	
44.3
	
 
	
 
	
 
	
52.1
	
 

	
Taxes receivable from
affiliate
	
 
	
 
	
61.3
	
 
	
 
	
 
	
43.3
	
 

	
Deferred income taxes
	
 
	
 
	
0.0
	
 
	
 
	
 
	
24.8
	
 

	
Prepayments and other current
assets
	
 
	
 
	
21.5
	
 
	
 
	
 
	
17.4
	
 

	
Total current assets
	
 
	
 
	
545.1
	
 
	
 
	
 
	
532.6
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Deferred debits
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Unamortized debt
expense
	
 
	
 
	
18.1
	
 
	
 
	
 
	
16.8
	
 

	
Regulatory assets
	
 
	
 
	
373.8
	
 
	
 
	
 
	
319.6
	
 

	
Other
	
 
	
 
	
16.8
	
 
	
 
	
 
	
2.6
	
 

	
Total deferred debits
	
 
	
 
	
408.7
	
 
	
 
	
 
	
339.0
	
 

	
Total assets
	
 
	
$
	
7,726.7
	
 
	
 
	
$
	
7,274.3
	
 




 

The accompanying notes are an integral part of the
consolidated financial statements.
  

 
  

125


 TAMPA ELECTRIC COMPANY 

Consolidated Balance Sheets—continued 
  
 
	
Liabilities and Capital
	
 
	
Dec. 31,
	
 
	
 
	
Dec. 31,
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Capitalization
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Common stock
	
 
	
$
	
2,305.4
	
 
	
 
	
$
	
2,130.4
	
 

	
Accumulated other comprehensive
loss
	
 
	
 
	
(3.6
	
)
	
 
	
 
	
(7.1
	
)

	
Retained earnings
	
 
	
 
	
313.7
	
 
	
 
	
 
	
305.8
	
 

	
Total capital
	
 
	
 
	
2,615.5
	
 
	
 
	
 
	
2,429.1
	
 

	
Long-term debt, less amount due
within one year
	
 
	
 
	
2,179.8
	
 
	
 
	
 
	
2,013.8
	
 

	
Total capital
	
 
	
 
	
4,795.3
	
 
	
 
	
 
	
4,442.9
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Current liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Long-term debt due within one
year
	
 
	
 
	
83.3
	
 
	
 
	
 
	
83.3
	
 

	
Notes payable
	
 
	
 
	
61.0
	
 
	
 
	
 
	
58.0
	
 

	
Accounts payable
	
 
	
 
	
221.6
	
 
	
 
	
 
	
242.3
	
 

	
Customer deposits
	
 
	
 
	
176.3
	
 
	
 
	
 
	
170.4
	
 

	
Regulatory liabilities
	
 
	
 
	
83.2
	
 
	
 
	
 
	
54.7
	
 

	
Derivative liabilities
	
 
	
 
	
24.1
	
 
	
 
	
 
	
36.6
	
 

	
Interest accrued
	
 
	
 
	
16.9
	
 
	
 
	
 
	
17.0
	
 

	
Taxes accrued
	
 
	
 
	
13.2
	
 
	
 
	
 
	
12.4
	
 

	
Other
	
 
	
 
	
10.2
	
 
	
 
	
 
	
10.0
	
 

	
Total current
liabilities
	
 
	
 
	
689.8
	
 
	
 
	
 
	
684.7
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Deferred credits
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Deferred income taxes
	
 
	
 
	
1,308.8
	
 
	
 
	
 
	
1,209.1
	
 

	
Investment tax credits
	
 
	
 
	
10.5
	
 
	
 
	
 
	
9.0
	
 

	
Derivative liabilities
	
 
	
 
	
2.1
	
 
	
 
	
 
	
6.1
	
 

	
Regulatory liabilities
	
 
	
 
	
603.5
	
 
	
 
	
 
	
623.4
	
 

	
Deferred credits and other
liabilities
	
 
	
 
	
316.7
	
 
	
 
	
 
	
299.1
	
 

	
Total deferred credits
	
 
	
 
	
2,241.6
	
 
	
 
	
 
	
2,146.7
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Commitments and Contingencies (see
Note 9)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Total liabilities and
capital
	
 
	
$
	
7,726.7
	
 
	
 
	
$
	
7,274.3
	
 




 

The accompanying notes are an integral part of the
consolidated financial statements.
  

 
  

126


 TAMPA ELECTRIC COMPANY 


Consolidated Statements of Income and Comprehensive Income 

 
 
	
 (millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
For the years ended Dec.
31,
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Revenues
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Electric
	
 
	
$
	
2,017.7
	
 
	
 
	
$
	
2,020.5
	
 
	
 
	
$
	
1,950.1
	
 

	
Gas
	
 
	
 
	
401.5
	
 
	
 
	
 
	
398.5
	
 
	
 
	
 
	
392.7
	
 

	
Total revenues
	
 
	
 
	
2,419.2
	
 
	
 
	
 
	
2,419.0
	
 
	
 
	
 
	
2,342.8
	
 

	
Expenses
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulated operations &
maintenance
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Fuel
	
 
	
 
	
638.6
	
 
	
 
	
 
	
692.3
	
 
	
 
	
 
	
680.2
	
 

	
Purchased power
	
 
	
 
	
78.9
	
 
	
 
	
 
	
71.4
	
 
	
 
	
 
	
64.7
	
 

	
Cost of natural gas
sold
	
 
	
 
	
135.5
	
 
	
 
	
 
	
137.0
	
 
	
 
	
 
	
142.6
	
 

	
Other
	
 
	
 
	
528.9
	
 
	
 
	
 
	
518.4
	
 
	
 
	
 
	
523.6
	
 

	
Depreciation and
amortization
	
 
	
 
	
313.5
	
 
	
 
	
 
	
302.6
	
 
	
 
	
 
	
290.3
	
 

	
Taxes, other than
income
	
 
	
 
	
192.0
	
 
	
 
	
 
	
189.8
	
 
	
 
	
 
	
183.1
	
 

	
Total expenses
	
 
	
 
	
1,887.4
	
 
	
 
	
 
	
1,911.5
	
 
	
 
	
 
	
1,884.5
	
 

	
Income from operations
	
 
	
 
	
531.8
	
 
	
 
	
 
	
507.5
	
 
	
 
	
 
	
458.3
	
 

	
Other income
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Allowance for other funds used
during construction
	
 
	
 
	
17.2
	
 
	
 
	
 
	
10.5
	
 
	
 
	
 
	
6.3
	
 

	
Other income, net
	
 
	
 
	
2.4
	
 
	
 
	
 
	
4.8
	
 
	
 
	
 
	
5.1
	
 

	
Total other income
	
 
	
 
	
19.6
	
 
	
 
	
 
	
15.3
	
 
	
 
	
 
	
11.4
	
 

	
Interest charges
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Interest expense
	
 
	
 
	
117.9
	
 
	
 
	
 
	
111.7
	
 
	
 
	
 
	
108.9
	
 

	
Allowance for borrowed funds
used during construction
	
 
	
 
	
(8.3
	
)
	
 
	
 
	
(5.1
	
)
	
 
	
 
	
(3.6
	
)

	
Total interest charges
	
 
	
 
	
109.6
	
 
	
 
	
 
	
106.6
	
 
	
 
	
 
	
105.3
	
 

	
Income before provision for income
taxes
	
 
	
 
	
441.8
	
 
	
 
	
 
	
416.2
	
 
	
 
	
 
	
364.4
	
 

	
Provision for income
taxes
	
 
	
 
	
165.5
	
 
	
 
	
 
	
155.9
	
 
	
 
	
 
	
138.8
	
 

	
Net income
	
 
	
 
	
276.3
	
 
	
 
	
 
	
260.3
	
 
	
 
	
 
	
225.6
	
 

	
Other comprehensive income, net of
tax
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Gain on cash flow
hedges
	
 
	
 
	
3.5
	
 
	
 
	
 
	
0.7
	
 
	
 
	
 
	
0.9
	
 

	
Total other comprehensive
income,  net of tax
	
 
	
 
	
3.5
	
 
	
 
	
 
	
0.7
	
 
	
 
	
 
	
0.9
	
 

	
Comprehensive income
	
 
	
$
	
279.8
	
 
	
 
	
$
	
261.0
	
 
	
 
	
$
	
226.5
	
 




 

The accompanying notes are an integral part of the
consolidated financial statements.
  

 
  

127


 TAMPA ELECTRIC COMPANY 


Consolidated Statements of Cash Flows 

 
 
	
 (millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
For the years ended Dec.
31,
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Cash flows from operating
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net income
	
 
	
$
	
276.3
	
 
	
 
	
$
	
260.3
	
 
	
 
	
$
	
225.6
	
 

	
Adjustments to reconcile net
income to net cash from operating activities:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Depreciation and
amortization
	
 
	
 
	
313.5
	
 
	
 
	
 
	
302.6
	
 
	
 
	
 
	
290.3
	
 

	
Deferred income taxes and
investment tax credits
	
 
	
 
	
118.9
	
 
	
 
	
 
	
92.2
	
 
	
 
	
 
	
118.1
	
 

	
Allowance for other funds used
during construction
	
 
	
 
	
(17.2
	
)
	
 
	
 
	
(10.5
	
)
	
 
	
 
	
(6.3
	
)

	
Loss on disposal of assets,
pretax
	
 
	
 
	
3.1
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Deferred recovery
clauses
	
 
	
 
	
26.5
	
 
	
 
	
 
	
(16.2
	
)
	
 
	
 
	
(6.2
	
)

	
Receivables, less allowance for
uncollectibles
	
 
	
 
	
(3.0
	
)
	
 
	
 
	
0.4
	
 
	
 
	
 
	
(13.8
	
)

	
Inventories
	
 
	
 
	
(21.3
	
)
	
 
	
 
	
13.1
	
 
	
 
	
 
	
(9.0
	
)

	
Prepayments and other
deposits
	
 
	
 
	
(4.0
	
)
	
 
	
 
	
1.5
	
 
	
 
	
 
	
0.0
	
 

	
Taxes accrued
	
 
	
 
	
(17.2
	
)
	
 
	
 
	
11.8
	
 
	
 
	
 
	
(34.3
	
)

	
Interest accrued
	
 
	
 
	
(0.1
	
)
	
 
	
 
	
0.6
	
 
	
 
	
 
	
(0.9
	
)

	
Accounts payable
	
 
	
 
	
(26.8
	
)
	
 
	
 
	
5.9
	
 
	
 
	
 
	
34.8
	
 

	
Other
	
 
	
 
	
(40.8
	
)
	
 
	
 
	
(14.5
	
)
	
 
	
 
	
(2.8
	
)

	
Cash flows from operating
activities
	
 
	
 
	
607.9
	
 
	
 
	
 
	
647.2
	
 
	
 
	
 
	
595.5
	
 

	
Cash flows from investing
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Capital expenditures
	
 
	
 
	
(686.6
	
)
	
 
	
 
	
(671.0
	
)
	
 
	
 
	
(501.3
	
)

	
Net proceeds from sale of
assets
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.1
	
 

	
Cash flows used in investing
activities
	
 
	
 
	
(686.6
	
)
	
 
	
 
	
(671.0
	
)
	
 
	
 
	
(501.2
	
)

	
Cash flows from financing
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Common stock
	
 
	
 
	
175.0
	
 
	
 
	
 
	
100.0
	
 
	
 
	
 
	
60.0
	
 

	
Proceeds from long-term debt
issuance
	
 
	
 
	
251.1
	
 
	
 
	
 
	
296.3
	
 
	
 
	
 
	
0.0
	
 

	
Repayment of long-term
debt/Purchase in lieu of redemption
	
 
	
 
	
(83.3
	
)
	
 
	
 
	
(83.3
	
)
	
 
	
 
	
(51.6
	
)

	
Net change in short-term
debt
	
 
	
 
	
3.0
	
 
	
 
	
 
	
(26.0
	
)
	
 
	
 
	
84.0
	
 

	
Dividends paid
	
 
	
 
	
(268.4
	
)
	
 
	
 
	
(262.6
	
)
	
 
	
 
	
(222.1
	
)

	
Cash flows from/(used in)
financing activities
	
 
	
 
	
77.4
	
 
	
 
	
 
	
24.4
	
 
	
 
	
 
	
(129.7
	
)

	
Net increase (decrease) in cash
and cash equivalents
	
 
	
 
	
(1.3
	
)
	
 
	
 
	
0.6
	
 
	
 
	
 
	
(35.4
	
)

	
Cash and cash equivalents at
beginning of the year
	
 
	
 
	
10.4
	
 
	
 
	
 
	
9.8
	
 
	
 
	
 
	
45.2
	
 

	
Cash and cash equivalents at end
of the year
	
 
	
$
	
9.1
	
 
	
 
	
$
	
10.4
	
 
	
 
	
$
	
9.8
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Supplemental disclosure of cash flow
information
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Cash paid (received) during the
year for:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Interest
	
 
	
$
	
106.2
	
 
	
 
	
$
	
102.5
	
 
	
 
	
$
	
102.4
	
 

	
Income taxes
	
 
	
$
	
63.7
	
 
	
 
	
$
	
52.6
	
 
	
 
	
$
	
56.4
	
 

	
Supplemental disclosure of cash flow
information
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Change in accrued capital
expenditures
	
 
	
$
	
6.9
	
 
	
 
	
$
	
14.3
	
 
	
 
	
$
	
4.7
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 




The accompanying notes are an integral part of
the consolidated financial statements. 
  

 
  

128


 TAMPA ELECTRIC COMPANY 


Consolidated Statements of Retained Earnings 
  


	
 (millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
For the years ended Dec.
31,
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Balance, beginning of year
	
 
	
$
	
305.8
	
 
	
 
	
$
	
308.1
	
 
	
 
	
$
	
304.6
	
 

	
Add: Net income
	
 
	
 
	
276.3
	
 
	
 
	
 
	
260.3
	
 
	
 
	
 
	
225.6
	
 

	
 
	
 
	
 
	
582.1
	
 
	
 
	
 
	
568.4
	
 
	
 
	
 
	
530.2
	
 

	
Deduct: Cash dividends on
capital stock—common
	
 
	
 
	
268.4
	
 
	
 
	
 
	
262.6
	
 
	
 
	
 
	
222.1
	
 

	
Balance, end of year
	
 
	
$
	
313.7
	
 
	
 
	
$
	
305.8
	
 
	
 
	
$
	
308.1
	
 




The accompanying notes are an integral part of
the consolidated financial statements. 
  

 
  

129


 TAMPA ELECTRIC COMPANY 


Consolidated Statements of Capitalization 
  
 
	
 
	
 
	
 
	
 
	
Capital 
Stock Outstanding
	
 
	
 
	
Cash 
Dividends
	
 

	
 
	
 
	
Current
	
 
	
Dec. 
31,
	
 
	
 
	
Paid (1)
	
 

	
 
	
 
	
Redemption
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Per
	
 
	
 
	
 
	
 
	
 

	
(millions, except share
amounts)
	
 
	
Price
	
 
	
Shares
	
 
	
Amount
	
 
	
 
	
Share
	
 
	
 
	
Amount
	
 

	
Common stock - without par
value
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
25 million shares
authorized
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
2015 (3)
	
 
	
N/A
	
 
	
10
	
 
	
$
	
2,305.4
	
 
	
 
	
 
	
(2
	
)
	
 
	
$
	
268.4
	
 

	
2014 (3)
	
 
	
N/A
	
 
	
10
	
 
	
$
	
2,130.4
	
 
	
 
	
 
	
(2
	
)
	
 
	
$
	
262.6
	
 




Preferred stock – $100 par value 

1.5 million shares authorized, none outstanding. 

Preferred stock – no par 

2.5 million shares authorized, none outstanding. 

Preference stock – no par 

2.5 million shares authorized, none outstanding. 

 
 
	  



 
	 (1)
	 Quarterly dividends paid on Mar. 2, May 28, Aug. 28 and
Nov. 30 during 2015. 



 Quarterly
dividends paid on Feb. 28, May 28, Aug. 28 and Nov. 28 during 2014. 
 
	 (2)
	 Not meaningful. 



 
	 (3)
	 TECO Energy made equity contributions to TEC of $175.0 million in
2015 and $100.0 million in 2014. 




The accompanying notes are an integral part of
the consolidated financial statements. 
  

 
  

130


 TAMPA ELECTRIC COMPANY 

Consolidated Statements of Capitalization – continued 
 At
Dec. 31, 2015 and 2014, TEC had the following long-term debt outstanding: 

 
 
	
Long-Term Debt
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
 
	
 
	
Due
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Tampa Electric
	
 
	
Installment contracts payable (1) :
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
5.65% Refunding 
bonds
	
 
	
2018
	
 
	
$
	
54.2
	
 
	
 
	
$
	
54.2
	
 

	
 
	
 
	
Variable rate bonds repurchased
in 2008 (2)
	
 
	
2020
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
5.15% Refunding bonds
repurchased in 2013 (3)
	
 
	
2025
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
1.5% Term rate bonds repurchased
in 2011 (4)
	
 
	
2030
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
5.0% Refunding bonds repurchased
in 2012 (5)
	
 
	
2034
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
Notes (6)(7) : 6.25%
	
 
	
2015-2016
	
 
	
 
	
83.3
	
 
	
 
	
 
	
166.7
	
 

	
 
	
 
	
6.10%
	
 
	
2018
	
 
	
 
	
200.0
	
 
	
 
	
 
	
200.0
	
 

	
 
	
 
	
5.40%
	
 
	
2021
	
 
	
 
	
231.7
	
 
	
 
	
 
	
231.7
	
 

	
 
	
 
	
2.60%
	
 
	
2022
	
 
	
 
	
225.0
	
 
	
 
	
 
	
225.0
	
 

	
 
	
 
	
6.55%
	
 
	
2036
	
 
	
 
	
250.0
	
 
	
 
	
 
	
250.0
	
 

	
 
	
 
	
6.15%
	
 
	
2037
	
 
	
 
	
190.0
	
 
	
 
	
 
	
190.0
	
 

	
 
	
 
	
4.10%
	
 
	
2042
	
 
	
 
	
250.0
	
 
	
 
	
 
	
250.0
	
 

	
 
	
 
	
4.35%
	
 
	
2044
	
 
	
 
	
290.0
	
 
	
 
	
 
	
290.0
	
 

	
 
	
 
	
4.20%
	
 
	
2045
	
 
	
 
	
230.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
Total long-term debt of Tampa
Electric
	
 
	
 
	
 
	
 
	
2,004.2
	
 
	
 
	
 
	
1,857.6
	
 

	
PGS
	
 
	
Notes (6)(7) : 6.10%
	
 
	
2018
	
 
	
 
	
50.0
	
 
	
 
	
 
	
50.0
	
 

	
 
	
 
	
5.40%
	
 
	
2021
	
 
	
 
	
46.7
	
 
	
 
	
 
	
46.7
	
 

	
 
	
 
	
2.60%
	
 
	
2022
	
 
	
 
	
25.0
	
 
	
 
	
 
	
25.0
	
 

	
 
	
 
	
6.15%
	
 
	
2037
	
 
	
 
	
60.0
	
 
	
 
	
 
	
60.0
	
 

	
 
	
 
	
4.10%
	
 
	
2042
	
 
	
 
	
50.0
	
 
	
 
	
 
	
50.0
	
 

	
 
	
 
	
4.35%
	
 
	
2044
	
 
	
 
	
10.0
	
 
	
 
	
 
	
10.0
	
 

	
 
	
 
	
4.20%
	
 
	
2045
	
 
	
 
	
20.0
	
 
	
 
	
 
	
0.0
	
 

	
 
	
 
	
Total long-term debt of
PGS
	
 
	
 
	
 
	
 
	
261.7
	
 
	
 
	
 
	
241.7
	
 

	
Total long-term debt of
TEC
	
 
	
 
	
 
	
 
	
2,265.9
	
 
	
 
	
 
	
2,099.3
	
 

	
Unamortized debt discount, net

	
 
	
 
	
 
	
 
	
(2.8
	
)
	
 
	
 
	
(2.2
	
)

	
Total carrying amount of
long-term debt
	
 
	
 
	
 
	
 
	
2,263.1
	
 
	
 
	
 
	
2,097.1
	
 

	
Less amount due within one year

	
 
	
 
	
 
	
 
	
83.3
	
 
	
 
	
 
	
83.3
	
 

	
Total long-term debt
	
 
	
 
	
 
	
 
	
 
	
$
	
2,179.8
	
 
	
 
	
$
	
2,013.8
	
 





	 (1)
	 Tax-exempt securities. 





	 (2)
	 In March 2008 these bonds, which were in auction rate mode, were
purchased in lieu of redemption by TEC. These held variable rate bonds have a par amount of $20.0 million due in 2020.  



 
	 (3)
	 In September 2013 these bonds, which were in term rate mode, were
purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $51.6 million due in 2025. 



 
	 (4)
	 In March 2011 these bonds, which were in term rate mode, were
purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $75.0 million due in 2030. 



 
	 (5)
	 In March 2012 these bonds, which were in term rate mode, were
purchased in lieu of redemption by TEC. These held term rate bonds have a par amount of $86.0 million due in 2034. 



 
	 (6)
	 These securities are subject to redemption in whole or in part,
at any time, at the option of the issuer. 



 
	 (7)
	 These long-term debt agreements contain various restrictive
covenants. 



 The
accompanying notes are an integral part of the consolidated financial statements. 
  

 
  

131


 TAMPA ELECTRIC COMPANY 

Consolidated Statements of Capitalization—continued 
 At Dec.
31, 2015, total long-term debt had a carrying amount of $2,263.1 million and an estimated fair market value of $2,433.3 million. At Dec. 31, 2014, total long-term debt had a carrying amount of $2,097.1 million and an estimated fair market value of
$2,372.2 million. TEC uses the market approach in determining fair value. The majority of the outstanding debt is valued using real-time financial market data obtained from Bloomberg Professional Service. The remaining securities are valued using
prices obtained from the Municipal Securities Rulemaking Board and by applying estimated credit spreads obtained from a third party to the par value of the security. All debt securities are Level 2 instruments. 

A substantial part of Tampa Electric’s tangible assets are
pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at
any time. Gross maturities and annual sinking fund requirements of long-term debt for the years 2016 through 2020 and thereafter are as follows: 

Long-Term Debt Maturities

 
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Total
	
 

	
As of Dec. 31, 2015
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Long-Term
	
 

	
(millions)
	
 
	
2016
	
 
	
 
	
2017
	
 
	
 
	
2018
	
 
	
 
	
2019
	
 
	
 
	
2020
	
 
	
 
	
Thereafter
	
 
	
 
	
Debt
	
 

	
Tampa Electric
	
 
	
$
	
83.3
	
 
	
 
	
$
	
0.0
	
 
	
 
	
 
	
254.2
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
1,666.7
	
 
	
 
	
$
	
2,004.2
	
 

	
PGS
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
50.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
211.7
	
 
	
 
	
 
	
261.7
	
 

	
Total long-term debt
maturities
	
 
	
$
	
83.3
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
304.2
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
1,878.4
	
 
	
 
	
$
	
2,265.9
	
 




The accompanying notes are an integral part of
the consolidated financial statements. 
  

 
  

132


 TAMPA ELECTRIC COMPANY 


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
  

 

1. Significant Accounting Policies 

TEC has two business segments. Its Tampa Electric division provides retail electric services in West Central Florida, and PGS, the gas division of TEC, is engaged in the purchase, distribution and sale of natural gas for residential, commercial, industrial and
electric power generation customers in Florida. TEC’s significant accounting policies are as follows: 

Basis of Accounting 

TEC maintains its accounts in accordance with recognized policies
prescribed or permitted by the FPSC and the FERC. These policies conform with U.S. GAAP in all material respects. 

The impact of the accounting guidance for the effects of certain
types of regulation has been minimal in the company’s experience, but when cost recovery is ordered over a period longer than a fiscal year, costs are recognized in the period that the regulatory agency recognizes them in accordance with this
guidance (see Note 3 for additional details). 

TEC’s retail and wholesale businesses are regulated by the
FPSC and FERC, respectively. Prices allowed by both agencies are generally based on recovery of prudent costs incurred plus a reasonable return on invested capital. 

Principles of Consolidation 

TEC is a wholly-owned subsidiary of TECO Energy, Inc., and is
comprised of the Electric division, generally referred to as Tampa Electric, and the Natural Gas division, PGS. Intercompany balances and intercompany transactions have been eliminated in consolidation. The use of estimates is inherent in the
preparation of financial statements in accordance with U.S. GAAP. Actual results could differ from these estimates. 

For entities that are determined to meet the definition of a
VIE, TEC obtains information, where possible, to determine if it is the primary beneficiary of the VIE. If TEC is determined to be the primary beneficiary, then the VIE is consolidated and a noncontrolling interest is recognized for any other
third-party interests. If TEC is not the primary beneficiary, then the VIE is accounted for using the equity or cost method of accounting. In certain circumstances this can result in TEC consolidating entities in which it has less than a 50% equity
investment and deconsolidating entities in which it has a majority equity interest (see Note 15). 

On Sept. 4, 2015, TECO Energy and Emera entered into the
Merger Agreement. Upon closing, TECO Energy will become a wholly owned subsidiary of Emera. See Note 16 for further information.

Cash Equivalents 

Cash equivalents are highly liquid, high-quality investments
purchased with an original maturity of three months or less. The carrying amount of cash equivalents approximated fair market value because of the short maturity of these instruments. 

Property, Plant and Equipment 

          

          
Property, plant and equipment is stated at original cost, which includes labor, material, applicable taxes, overhead and AFUDC. Concurrent with a planned major maintenance outage or with new construction, the cost of adding or replacing retirement
units-of-property is capitalized in conformity with the regulations of FERC and FPSC. The cost of maintenance, repairs and replacement of minor items of property is expensed as incurred. 

In general, when regulated depreciable property is retired or
disposed, its original cost less salvage is charged to accumulated depreciation. For other property dispositions, the cost and accumulated depreciation are removed from the balance sheet and a gain or loss is recognized.

 

133


  Depreciation 

Tampa Electric and PGS compute depreciation and amortization for
electric generation, electric transmission and distribution, gas distribution and general plant facilities using the following methods: 
 
	  
	 ·
	 the group remaining life method, approved by the
FPSC, is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property; 



 
	  
	 ·
	 the amortizable life method, approved by the FPSC,
is applied to the net book value to date over the remaining life of those assets not classified as depreciable property above. 




The provision for total regulated utility plant in service,
expressed as a percentage of the original cost of depreciable property, was 3.7% for 2015, 2014 and 2013. Construction work in progress is not depreciated until the asset is completed or placed in service. Total depreciation expense for the years
ended Dec. 31, 2015, 2014 and 2013 was $306.0 million, $295.8 million and $284.2 million, respectively. 

On Sept. 11, 2013, the FPSC unanimously voted to approve a
stipulation and settlement agreement between Tampa Electric and all of the intervenors in its Tampa Electric division base rate proceeding. As a result, Tampa Electric began using a 15-year amortization period for all computer software retroactive
to Jan. 1, 2013. 
 Allowance for Funds Used During Construction

 AFUDC is a non-cash credit to income with a corresponding
charge to utility plant which represents the cost of borrowed funds and a reasonable return on other funds used for construction. The FPSC approved rate used to calculate AFUDC is revised periodically to reflect significant changes in Tampa
Electric’s cost of capital. The rate was 8.16% for May 2009 through December 2013. In March 2014, the rate was revised to 6.46% effective Jan. 1, 2014. Total AFUDC for the years ended Dec. 31, 2015, 2014 and 2013 was $25.5 million, $15.6
million and $9.9 million, respectively. 
 Inventory 

TEC values materials, supplies and fossil fuel inventory (coal,
oil and natural gas) using a weighted-average cost method. These materials, supplies and fuel inventories are carried at the lower of weighted-average cost or market, unless evidence indicates that the weighted-average cost (even if in excess of
market) will be recovered with a normal profit upon sale in the ordinary course of business. 

 Deferred Income Taxes 

TEC uses the asset and liability method in the measurement of
deferred income taxes. Under the asset and liability method, the temporary differences between the financial statement and tax bases of assets and liabilities are reported as deferred taxes measured at current tax rates. Tampa Electric and PGS are
regulated, and their books and records reflect approved regulatory treatment, including certain adjustments to accumulated deferred income taxes and the establishment of a corresponding regulatory tax liability reflecting the amount payable to
customers through future rates. 
 Investment Tax Credits 

ITCs have been recorded as deferred credits and are being
amortized as reductions to income tax expense over the service lives of the related property. 

Revenue Recognition 

TEC recognizes revenues consistent with accounting standards for
revenue recognition. Except as discussed below, TEC recognizes revenues on a gross basis when earned for the physical delivery of products or services and the risks and rewards of ownership have transferred to the buyer. 

The regulated utilities’ (Tampa Electric and PGS) retail
businesses and the prices charged to customers are regulated by the FPSC. Tampa Electric’s wholesale business is regulated by the FERC. See Note 3 for a discussion of significant regulatory matters and
the applicability of the accounting guidance for certain types of regulation to the company. 

Revenues and Cost Recovery 

Revenues include amounts resulting from cost-recovery clauses
which provide for monthly billing charges to reflect increases or decreases in fuel, purchased power, conservation and environmental costs for Tampa Electric and purchased gas, interstate pipeline 

134


 capacity and conservation costs for PGS. These adjustment factors are based on costs incurred and projected for a specific recovery period. Any over- or under-recovery of costs plus an interest factor are taken into
account in the process of setting adjustment factors for subsequent recovery periods. Over-recoveries of costs are recorded as regulatory liabilities, and under-recoveries of costs are recorded as regulatory assets. 

Certain other costs incurred by the regulated utilities are
allowed to be recovered from customers through prices approved in the regulatory process. These costs are recognized as the associated revenues are billed. The regulated utilities accrue base revenues for services rendered but unbilled to provide
for a closer matching of revenues and expenses (see Note 3). As of Dec. 31, 2015 and 2014, unbilled revenues of $53.7 million and $49.3 million, respectively, are included in the “Receivables” line
item on TEC’s Consolidated Balance Sheets. 
 Tampa
Electric purchases power on a regular basis primarily to meet the needs of its retail customers. Tampa Electric purchased power from non-TECO Energy affiliates at a cost of $78.9 million, $71.4 million and $64.7 million, for the years ended Dec. 31,
2015, 2014 and 2013, respectively. The prudently incurred purchased power costs at Tampa Electric have historically been recovered through an FPSC-approved cost-recovery clause. 

Receivables and Allowance for Uncollectible Accounts 

Receivables consist of services billed to
residential, commercial, industrial and other customers. An allowance for uncollectible accounts is established based on TEC’s collection experience. Circumstances that could affect Tampa Electric’s and PGS’s estimates of
uncollectible receivables include, but are not limited to, customer credit issues, the level of natural gas prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible. 
 Accounting for Excise Taxes,
Franchise Fees and Gross Receipts 
 TEC is allowed to recover
certain costs on a dollar-for-dollar basis incurred from customers through prices approved by the FPSC. The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as revenues on the Consolidated Statements
of Income. Franchise fees and gross receipt taxes payable by the regulated utilities are included as an expense on the Consolidated Statements of Income in “Taxes, other than income”. These amounts totaled $116.9 million, $113.9 million
and $108.5 million for the years ended Dec. 31, 2015, 2014 and 2013, respectively. Excise taxes paid by the regulated utilities are not material and are expensed as incurred. 

Deferred Credits and Other Liabilities 

Other deferred credits primarily include the accrued
postretirement and pension liabilities (see Note 5), MGP environmental remediation liability (see Note 9), and medical and general liability claims incurred but not
reported. TECO Energy and its subsidiaries, including TEC, have a self-insurance program supplemented by excess insurance coverage for the cost of claims whose ultimate value exceeds the company’s retention amounts. TEC estimates its
liabilities for auto, general and workers’ compensation using discount rates mandated by statute or otherwise deemed appropriate for the circumstances. Discount rates used in estimating these other self-insurance liabilities at Dec. 31, 2015
and 2014 ranged from 2.92% to 4.00% and 2.71% to 4.00%, respectively. 

Cash Flows Related to Derivatives and Hedging Activities 

TEC classifies cash inflows and outflows related to derivative
and hedging instruments in the appropriate cash flow sections associated with the item being hedged. For natural gas, the cash inflows and outflows are included in the operating section of the Consolidated Statements of Cash Flows. For interest rate
swaps that settle coincident with the debt issuance, the cash inflows and outflows are treated as premiums or discounts and included in the financing section of the Consolidated Statements of Cash Flows. 

Reclassifications

Certain reclassifications were made to prior year amounts to
conform to current period presentation. None of the reclassifications affected TEC’s net income in any period.
  

 

2. New Accounting Pronouncements 

Revenue from Contracts with Customers 

In May 2014, the FASB issued guidance regarding the accounting
for revenue from contracts with customers. The standard is principle-based and provides a five-step model to determine when and how revenue is recognized. The core principle is that a company should recognize revenue when it transfers promised goods
or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In addition, the guidance will 

135


 require additional disclosures regarding the nature, amount, timing and uncertainty of revenue arising from contracts with customers. This guidance will be effective for TEC beginning in 2018, with early adoption permitted in 2017, and will allow for
either full retrospective adoption or modified retrospective adoption. TEC expects to adopt this guidance effective Jan. 1, 2018, and is continuing to evaluate the available adoption methods and the impact of the adoption of this guidance on its financial statements, but does not expect the impact to be significant. 

Presentation of Debt Issuance Costs 

In April 2015, the FASB issued guidance regarding the
presentation of debt issuance costs on the balance sheet. Under the new guidance, an entity is required to present debt issuance costs as a direct deduction from the carrying amount of the related debt liability rather than as a deferred charge
(i.e., as an asset) under current guidance. In August 2015, the FASB amended the guidance to include an SEC staff announcement that it will not object to a company presenting debt issuance costs related to line-of-credit arrangements as an asset,
regardless of whether a balance is outstanding. This guidance will be effective for TEC beginning in 2016 and will be required to be applied on a retrospective basis for all periods presented. As of Dec. 31, 2015, $18.1 million of debt issuance
costs, which does not include costs for line-of-credit arrangements, are included in “Deferred debits” on TEC’s Consolidated Condensed Balance Sheet. The guidance will not affect TEC’s results of operations or cash flows.

Disclosure of Investments Using Net Asset Value 

In May 2015, the FASB issued guidance stating that investments
for which fair value is measured using the NAV per share practical expedient should not be categorized in the fair value hierarchy but should be provided to reconcile to total investments on the balance sheet. In addition, the guidance clarifies
that a plan sponsor’s pension assets are eligible to be measured at NAV as a practical expedient and that those investments should also not be categorized in the fair value hierarchy. TECO Energy’s pension plan, in which TEC
participates, has such investments as disclosed in Note 5. This standard will be required for TEC beginning in 2016. As early adoption is permitted, TEC adopted the standard for its 2015 fiscal year and applied
the presentation on a retrospective basis for all periods presented in the pension plan assets fair value hierarchy. The guidance did not affect TEC’s balance sheets, results of operations or cash flows.

Measurement Period Adjustments in Business Combinations

In September 2015, the FASB issued guidance requiring an acquirer
in a business combination to account for measurement period adjustments during the reporting period in which the adjustment is determined, rather than retrospectively. When measurements are incomplete as of the end of the reporting period covering a
business combination, an acquirer may record adjustments to provisional amounts based on events and circumstances that existed as of the acquisition date during the period from the date of acquisition to the date information is received, not to
exceed one year. The guidance will be effective for TEC beginning in 2016 and will be applied prospectively. The guidance will not affect TEC’s current financial statements. However, TEC will assess the potential impact of the guidance on
future acquisitions. 
 Balance Sheet Classification of Deferred
Taxes
 In November 2015, the FASB issued guidance regarding
the classification of deferred taxes on the balance sheet. To simplify the presentation of deferred income taxes, the new guidance requires that all deferred tax assets and liabilities be classified as noncurrent on the balance sheet rather than be
classified as current or noncurrent under current guidance. The guidance will be required for TEC beginning in 2017 and may be applied on a prospective or retrospective basis. As early adoption is permitted, TEC adopted the standard in December 2015
and applied the balance sheet presentation on a prospective basis. Therefore, prior period balance sheets were not retrospectively adjusted. The guidance did not affect TEC’s results of operations or cash flows.

 

Recognition and Measurement of Financial Assets and Financial
Liabilities
 In January 2016, the FASB issued guidance related
to accounting for financial instruments, including equity investments, financial liabilities under the fair value option, valuation allowances for available-for-sale debt securities, and the presentation and disclosure requirements for financial
instruments. TEC does not have equity investments or available-for-sale debt securities and it does not record financial liabilities under the fair value option. However, it is evaluating the impact of the adoption of this guidance on its financial
statement disclosures, including those regarding the fair value of its long-term debt, but it does not expect the impact to be significant. The guidance will be effective for TEC beginning in 2018.

 

Leases

 In February 2016, the FASB
issued guidance regarding the accounting for leases. The objective is to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet for leases with a lease term of more than 12
months. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. Under the existing guidance, operating leases are not recorded as lease assets and lease liabilities on the balance sheet.
The dual model for income statement classification is maintained under the new guidance and as a result is expected to limit the impact of the changes on the income statement and statement of cash flows. This guidance will be effective for TEC
beginning in 2019, with early adoption 

136



permitted, and will be applied using a modified retrospective approach. TEC is currently evaluating the impacts of the adoption of the guidance on its financial
statements.
  

3. Regulatory 

Tampa Electric’s retail business and PGS are regulated by
the FPSC. Tampa Electric is also subject to regulation by the FERC. The operations of PGS are regulated by the FPSC separately from the operations of Tampa Electric. The FPSC has jurisdiction over rates, service, issuance of securities, safety,
accounting and depreciation practices and other matters. In general, the FPSC sets rates at a level that allows utilities such as Tampa Electric and PGS to collect total revenues (revenue requirements) equal to their cost of providing service, plus
a reasonable return on invested capital. 
 Base Rates-Tampa
Electric 
 Tampa Electric’s results for the first ten
months of 2013 reflect base rates established in March 2009, when the FPSC awarded $104 million higher revenue requirements effective in May 2009 that authorized an ROE midpoint of 11.25%, 54.0% equity in the capital structure and 2009 13-month
average rate base of $3.4 billion. In a series of subsequent decisions in 2009 and 2010, related to a calculation error and a step increase for CTs and rail unloading facilities that entered service before the end of 2009, base rates increased an
additional $33.5 million. 
 Tampa Electric’s results
for 2015, 2014 and the last two months of 2013 reflect the results of a Stipulation and Settlement Agreement entered on Sept. 6, 2013, between Tampa Electric and all of the intervenors in its Tampa Electric division base rate proceeding, which
resolved all matters in Tampa Electric’s 2013 base rate proceeding. On Sept. 11, 2013, the FPSC unanimously voted to approve the stipulation and settlement agreement.

This agreement provided for the following revenue increases:
$57.5 million effective Nov. 1, 2013, an additional $7.5 million effective Nov. 1, 2014, an additional $5.0 million effective Nov. 1, 2015, and an additional $110.0 million effective Jan. 1, 2017 or the date that the expansion of
Tampa Electric’s Polk Power Station goes into service, whichever is later. The agreement provides that Tampa Electric’s allowed regulatory ROE would be a mid-point of 10.25% with a range of plus or minus 1%, with a potential increase to
10.50% if U.S. Treasury bond yields exceed a specified threshold. The agreement provides that Tampa Electric cannot file for additional rate increases until 2017 (to be effective no sooner than Jan. 1, 2018), unless its earned ROE were to fall below
9.25% (or 9.5% if the allowed ROE is increased as described above) before that time. If its earned ROE were to rise above 11.25% (or 11.5% if the allowed ROE is increased as described above) any party to the agreement other than Tampa Electric could
seek a review of its base rates. Under the agreement, the allowed equity in the capital structure is 54% from investor sources of capital and Tampa Electric began using a 15-year amortization period for all computer software retroactive to Jan. 1,
2013. 
 Tampa Electric is also subject to regulation by the
FERC in various respects, including wholesale power sales, certain wholesale power purchases, transmission and ancillary services and accounting practices. 

Storm Damage Cost Recovery 

Prior to the above-mentioned stipulation and settlement
agreement, Tampa Electric was accruing $8.0 million annually to a FPSC-approved self-insured storm damage reserve. This reserve was created after Florida’s IOUs were unable to obtain transmission and distribution insurance coverage due to
destructive acts of nature. Effective Nov. 1, 2013, Tampa Electric ceased accruing for this storm damage reserve as a result of the 2013 rate case settlement. However, in the event of a named storm that results in damage to its system, Tampa
Electric can petition the FPSC to seek recovery of those costs over a 12-month period or longer as determined by the FPSC, as well as replenish its reserve to $56.1 million; the level it was as of Oct. 31, 2013. Tampa Electric’s storm reserve
remained $56.1 million at both Dec. 31, 2015 and 2014. 
 Base
Rates-PGS 
 PGS’s base rates were established in May
2009 and reflect an ROE of 10.75%, which is the middle of a range between 9.75% to 11.75%. The allowed equity in capital structure is 54.7% from all investor sources of capital, on an allowed rate base of $560.8 million. 

Regulatory Assets and Liabilities 

Tampa Electric and PGS apply the accounting standards for
regulated operations. Areas of applicability include: deferral of revenues under approved regulatory agreements; revenue recognition resulting from cost-recovery clauses that provide for monthly billing charges to reflect increases or decreases in
fuel, purchased power, conservation and environmental costs; the deferral of costs as regulatory assets to the period in which the regulatory agency recognizes them, when cost recovery is ordered over a period longer 

137


 than a fiscal year; and the advance recovery of expenditures for approved costs such as future storm damage or the future removal
of property. All regulatory assets are recovered through the regulatory process.

Details of the regulatory assets and liabilities as of Dec. 31,
2015 and 2014 are presented in the following table: 
 Regulatory
Assets and Liabilities
  
 
	
 
	
 
	
Dec. 
31,
	
 
	
 
	
Dec. 
31,
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Regulatory assets:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulatory tax asset (1)
	
 
	
$
	
74.6
	
 
	
 
	
$
	
69.2
	
 

	
Cost-recovery clauses - deferred
balances (2)
	
 
	
5.2
	
 
	
 
	
0.9
	
 

	
Cost-recovery clauses - offsets
to derivative liabilities (2)
	
 
	
 
	
26.2
	
 
	
 
	
 
	
42.7
	
 

	
Environmental remediation (3)
	
 
	
 
	
54.0
	
 
	
 
	
 
	
53.1
	
 

	
Postretirement benefits (4)
	
 
	
 
	
238.3
	
 
	
 
	
 
	
187.8
	
 

	
Deferred bond refinancing costs (5)
	
 
	
 
	
6.5
	
 
	
 
	
 
	
7.2
	
 

	
Competitive rate adjustment (2)
	
 
	
 
	
2.6
	
 
	
 
	
 
	
2.8
	
 

	
Other
	
 
	
 
	
10.7
	
 
	
 
	
 
	
8.0
	
 

	
Total regulatory assets
	
 
	
 
	
418.1
	
 
	
 
	
 
	
371.7
	
 

	
Less: Current portion
	
 
	
 
	
44.3
	
 
	
 
	
 
	
52.1
	
 

	
Long-term regulatory
assets
	
 
	
$
	
373.8
	
 
	
 
	
$
	
319.6
	
 

	
Regulatory liabilities:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulatory tax
liability
	
 
	
$
	
5.7
	
 
	
 
	
$
	
5.1
	
 

	
Cost-recovery clauses (2)
	
 
	
 
	
54.2
	
 
	
 
	
 
	
23.5
	
 

	
Transmission and delivery storm
reserve
	
 
	
 
	
56.1
	
 
	
 
	
 
	
56.1
	
 

	
Accumulated reserve—cost
of removal (6)
	
 
	
 
	
570.0
	
 
	
 
	
 
	
591.5
	
 

	
Other
	
 
	
 
	
0.7
	
 
	
 
	
 
	
1.9
	
 

	
Total regulatory
liabilities
	
 
	
 
	
686.7
	
 
	
 
	
 
	
678.1
	
 

	
Less: Current portion
	
 
	
 
	
83.2
	
 
	
 
	
 
	
54.7
	
 

	
Long-term regulatory
liabilities
	
 
	
$
	
603.5
	
 
	
 
	
$
	
623.4
	
 





	 (1)
	 The regulatory tax asset is primarily associated with the
depreciation and recovery of AFUDC-equity. This asset does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be recovered
over the expected life of the related assets.  



 
	 (2)
	 These assets and liabilities are related to FPSC clauses and
riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC on a dollar-for-dollar basis in the next year. In the case of the regulatory asset related to derivative liabilities, recovery occurs in the year following
the settlement of the derivative position.



 
	 (3)
	 This asset is related to costs associated with environmental
remediation primarily at manufactured gas plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is impacted by the timing of the
expenditures related to remediation.



 
	 (4)
	 This asset is related to the deferred costs of postretirement
benefits. It is included in rate base and earns a rate of return as permitted by the FPSC. It is amortized over the remaining service life of plan participants.



 
	 (5)
	 This asset represents the past costs associated with refinancing
debt. It does not earn a return but rather is included in capital structure, which is used in the calculation of the weighted cost of capital used to determine revenue requirements. It will be amortized over the term of the related debt instruments.




 
	 (6)
	 This item represents the non-ARO cost of removal in the
accumulated reserve for depreciation. 



  
  

4. Income Taxes 

Income Tax Expense

TEC is included in the filing of a consolidated federal income
tax return with TECO Energy and its affiliates. TEC’s income tax expense is based upon a separate return computation. For the three years presented, TEC’s effective tax rate differs from the statutory rate principally due to state income
taxes. 
 138


 Income tax expense consists of the following components: 

Income Tax Expense (Benefit)

 
 
	
 (millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
For the year ending Dec.
31,
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Current income taxes
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Federal
	
 
	
$
	
38.2
	
 
	
 
	
$
	
54.8
	
 
	
 
	
$
	
19.4
	
 

	
State
	
 
	
 
	
8.4
	
 
	
 
	
 
	
8.9
	
 
	
 
	
 
	
1.3
	
 

	
Deferred income taxes
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Federal
	
 
	
 
	
102.9
	
 
	
 
	
 
	
79.0
	
 
	
 
	
 
	
99.8
	
 

	
State
	
 
	
 
	
14.5
	
 
	
 
	
 
	
13.5
	
 
	
 
	
 
	
18.6
	
 

	
Amortization of investment tax
credits
	
 
	
 
	
1.5
	
 
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
(0.3
	
)

	
Total income tax
expense
	
 
	
$
	
165.5
	
 
	
 
	
$
	
155.9
	
 
	
 
	
$
	
138.8
	
 




The total income tax provisions differ from amounts computed by
applying the federal statutory tax rate to income before income taxes as follows: 

Effective Income Tax Rate

 
 
	
 (millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
For the years ended Dec.
31,
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Income tax expense at the federal
statutory rate of 35%
	
 
	
$
	
154.6
	
 
	
 
	
$
	
145.7
	
 
	
 
	
$
	
127.5
	
 

	
Increase (decrease) due to
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
State income tax, net of federal
income tax
	
 
	
 
	
14.8
	
 
	
 
	
 
	
14.5
	
 
	
 
	
 
	
13.0
	
 

	
Other
	
 
	
 
	
(3.9
	
)
	
 
	
 
	
(4.3
	
)
	
 
	
 
	
(1.7
	
)

	
Total income tax expense on
consolidated statements of income
	
 
	
$
	
165.5
	
 
	
 
	
$
	
155.9
	
 
	
 
	
$
	
138.8
	
 

	
Income tax expense as a percent of
income from continuing operations,

   before income
taxes
	
 
	
 
	
37.5
	
%
	
 
	
 
	
37.5
	
%
	
 
	
 
	
38.1
	
%




Deferred Income Taxes

Deferred taxes result from temporary differences in the
recognition of certain liabilities or assets for tax and financial reporting purposes. The principal components of TEC’s deferred tax assets and liabilities recognized in the balance sheet are as follows: 

 
 
	
 (millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
As of Dec. 31,
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Deferred tax liabilities (1)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Property related
	
 
	
$
	
1,431.9
	
 
	
 
	
$
	
1,328.8
	
 

	
Pension and postretirement
benefits
	
 
	
 
	
92.0
	
 
	
 
	
 
	
72.5
	
 

	
Pension
	
 
	
 
	
71.1
	
 
	
 
	
 
	
51.8
	
 

	
Total deferred tax
liabilities
	
 
	
 
	
1,595.0
	
 
	
 
	
 
	
1,453.1
	
 

	
Deferred tax assets (1)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Loss and credit
carryforwards
	
 
	
 
	
80.0
	
 
	
 
	
 
	
77.7
	
 

	
Medical benefits
	
 
	
 
	
47.7
	
 
	
 
	
 
	
51.0
	
 

	
Insurance reserves
	
 
	
 
	
27.6
	
 
	
 
	
 
	
29.0
	
 

	
Pension and postretirement
benefits
	
 
	
 
	
92.0
	
 
	
 
	
 
	
72.5
	
 

	
Capitalized energy conservation
assistance costs
	
 
	
 
	
21.4
	
 
	
 
	
 
	
20.3
	
 

	
Other
	
 
	
 
	
17.5
	
 
	
 
	
 
	
18.3
	
 

	
Total deferred tax assets
	
 
	
 
	
286.2
	
 
	
 
	
 
	
268.8
	
 

	
Total deferred tax liability,
net
	
 
	
 
	
1,308.8
	
 
	
 
	
 
	
1,184.3
	
 

	
Less: Current portion of deferred
tax asset
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(24.8
	
)

	
Long-term portion of deferred tax
liability, net
	
 
	
$
	
1,308.8
	
 
	
 
	
$
	
1,209.1
	
 





	  (1)
	 Certain property related assets and liabilities have been
netted. 



 139


 At Dec. 31, 2015, TEC had cumulative unused federal and Florida NOLs for income tax purposes of $194.1 million and $268.5 million, respectively,
expiring in 2033. In addition, TEC has unused general business credits of $1.9 million, expiring between
2028 and 2035.
 Unrecognized Tax Benefits

TEC accounts for uncertain tax positions as required by FASB
accounting guidance. This guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under the guidance, TEC may recognize the tax benefit from an
uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from
such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The guidance also provides standards on derecognition, classification, interest and
penalties on income taxes, accounting in interim periods and requires increased disclosures. 

As of Dec. 31, 2015 and 2014, TEC does not have a liability for
unrecognized tax benefits. Based on current information, TEC does not anticipate that this will change materially in 2016. As of Dec. 31, 2015 and 2014, TEC does not have a liability recorded for payment of interest and penalties associated with
uncertain tax positions. 
 The IRS concluded its examination
of TECO Energy’s 2014 consolidated federal income tax return in December 2015. The U.S. federal statute of limitations remains open for the year 2012 and onward. Years 2015 and 2016 are currently under examination by the IRS under its
Compliance Assurance Program. Florida’s statute of limitations is three years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year
after formal notification to the states. Years still open to examination by Florida’s tax authorities include 2005 and forward as a result of TECO Energy’s consolidated Florida net operating loss still being utilized. TEC does not expect
the settlement of audit examinations to significantly change the total amount of unrecognized tax benefits within the next 12 months. 
  

 

5. Employee Postretirement Benefits

Pension Benefits 

TEC is a participant in the comprehensive retirement plans of
TECO Energy, including a qualified, non-contributory defined benefit retirement plan that covers substantially all employees. Benefits are based on the employees’ age, years of service and final average earnings. Where appropriate and
reasonably determinable, the portion of expenses, income, gains or losses allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy retirement plans. 

Amounts disclosed for pension benefits in the following tables
and discussion also include the fully-funded obligations for the SERP. This is a non-qualified, non-contributory defined benefit retirement plan available to certain members of senior management. 

Other Postretirement Benefits 

TECO Energy and its subsidiaries currently provide certain
postretirement health care and life insurance benefits (Other Benefits) for most employees retiring after age 50 meeting certain service requirements. Where appropriate and reasonably determinable, the portion of expenses, income, gains or losses
allocable to TEC are presented. Otherwise, such amounts presented reflect the amount allocable to all participants of the TECO Energy postretirement health care and life insurance plans. Postretirement benefit levels are substantially unrelated to
salary. TECO Energy reserves the right to terminate or modify the plans in whole or in part at any time. 

MMA added prescription drug coverage to Medicare, with a 28%
tax-free subsidy to encourage employers to retain their prescription drug programs for retirees, along with other key provisions. TECO Energy’s current retiree medical program for those eligible for Medicare (generally over age 65) includes
coverage for prescription drugs. The company has determined that prescription drug benefits available to certain Medicare-eligible participants under its defined-dollar-benefit postretirement health care plan are at least “actuarially
equivalent” to the standard drug benefits that are offered under Medicare Part D. 

The FASB issued accounting guidance and disclosure requirements
related to the MMA. The guidance requires (a) that the effects of the federal subsidy be considered an actuarial gain and recognized in the same manner as other actuarial gains and losses and (b) certain disclosures for employers that
sponsor postretirement health care plans that provide prescription drug benefits. 

In March 2010, the Patient Protection and Affordable Care Act and
a companion bill, the Health Care and Education Reconciliation Act, collectively referred to as the Health Care Reform Acts, were signed into law. Among other things, both acts reduced the tax benefits available to an employer that receives the
Medicare Part D subsidy, resulting in a write-off of any associated deferred tax asset. As a result, TEC reduced its deferred tax asset and recorded a corresponding regulatory asset in 2010. This amount was trued up in 2013. TEC is amortizing the
regulatory asset over the remaining average service life at the time of 12 years. 

140


 Additionally, the Health Care Reform Acts contain other provisions that may impact TECO Energy’s obligation for
retiree medical benefits. In particular, the Health Care Reform Acts include a provision that imposes an
excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. TECO Energy does not currently believe the excise tax or other provisions of the Health Care Reform Acts will
materially increase its PBO. TECO Energy will continue to monitor and assess the impact of the Health Care
Reform Acts, including any clarifying regulations issued to address how the provisions are to be implemented, on its future results of operations, cash flows or financial position. 

Effective Jan. 1, 2013, the company implemented an EGWP for its
post-65 retiree prescription drug plan. The EGWP is a private Medicare Part D plan designed to provide benefits that are at least equivalent to Medicare Part D. The EGWP reduces net periodic benefit cost by taking advantage of rebate and discount
enhancements provided under the Health Care Reform Acts, which are greater than the subsidy payments previously received by the company under Medicare Part D for its post-65 retiree prescription drug plan. 

Obligations and Funded Status 

TEC recognizes in its statement of financial position the
over-funded or under-funded status of its postretirement benefit plans. This status is measured as the difference between the fair value of plan assets and the PBO in the case of its defined benefit plan, or the APBO in the case of its other
postretirement benefit plan. Changes in the funded status are reflected, net of estimated tax benefits, in benefit liabilities and regulatory assets. The results of operations are not impacted. 

The following table provides a detail of the change in TECO
Energy’s benefit obligations and change in plan assets for combined pension plans (pension benefits) and combined other postretirement benefit plans (other benefits). 
 
	
TECO Energy
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
Obligations and Funded
Status
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Change in benefit obligation
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net benefit obligation at beginning
of year
	
 
	
$
	
728.9
	
 
	
 
	
$
	
666.0
	
 
	
 
	
$
	
201.5
	
 
	
 
	
$
	
208.1
	
 

	
Service cost
	
 
	
 
	
20.9
	
 
	
 
	
 
	
18.3
	
 
	
 
	
 
	
2.2
	
 
	
 
	
 
	
2.5
	
 

	
Interest cost
	
 
	
 
	
30.3
	
 
	
 
	
 
	
32.0
	
 
	
 
	
 
	
8.2
	
 
	
 
	
 
	
10.8
	
 

	
Plan participants’
contributions
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
2.0
	
 
	
 
	
 
	
2.8
	
 

	
Plan amendments
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(3.7
	
)
	
 
	
 
	
(23.2
	
)

	
Actuarial loss (gain)
	
 
	
 
	
5.8
	
 
	
 
	
 
	
48.3
	
 
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
1.5
	
 

	
Benefits paid
	
 
	
 
	
(53.0
	
)
	
 
	
 
	
(39.9
	
)
	
 
	
 
	
(14.6
	
)
	
 
	
 
	
(16.0
	
)

	
Transfer in due to the effect of
business combination
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
26.7
	
 

	
Plan curtailment
	
 
	
 
	
0.0
	
 
	
 
	
 
	
4.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(11.7
	
)

	
Special termination
benefit
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Net benefit obligation at end of
year
	
 
	
$
	
732.9
	
 
	
 
	
$
	
728.9
	
 
	
 
	
$
	
195.2
	
 
	
 
	
$
	
201.5
	
 




 
  
 
	
Change in plan assets
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Fair value of plan assets at
beginning of year
	
 
	
$
	
648.0
	
 
	
 
	
$
	
593.0
	
 
	
 
	
$
	
18.8
	
 
	
 
	
$
	
0.0
	
 

	
Actual return on plan
assets
	
 
	
 
	
(25.5
	
)
	
 
	
 
	
46.4
	
 
	
 
	
 
	
(0.6
	
)
	
 
	
 
	
0.1
	
 

	
Employer contributions
	
 
	
 
	
55.0
	
 
	
 
	
 
	
47.5
	
 
	
 
	
 
	
1.5
	
 
	
 
	
 
	
(1.0
	
)

	
Employer direct benefit
payments
	
 
	
 
	
0.9
	
 
	
 
	
 
	
1.0
	
 
	
 
	
 
	
13.5
	
 
	
 
	
 
	
16.0
	
 

	
Plan participants’
contributions
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
2.0
	
 
	
 
	
 
	
2.8
	
 

	
Transfer in due to
acquisition
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
16.9
	
 

	
Benefits paid
	
 
	
 
	
(53.0
	
)
	
 
	
 
	
(39.9
	
)
	
 
	
 
	
(14.6
	
)
	
 
	
 
	
(16.0
	
)

	
Fair value of plan assets at end of
year (1)
	
 
	
$
	
625.4
	
 
	
 
	
$
	
648.0
	
 
	
 
	
$
	
20.6
	
 
	
 
	
 
	
18.8
	
 




 
 
	 (1)
	 The MRV of plan assets is used as the basis for calculating the
EROA component of periodic pension expense. MRV reflects the fair value of plan assets adjusted for experience gains and losses (i.e. the differences between actual investment returns and expected returns) spread over five years.




 141


  At Dec. 31, the aggregate financial position for TECO Energy pension plans and other postretirement plans with benefit
obligations in excess of plan assets was as follows:
 
	
Funded Status
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Benefit obligation
(PBO/APBO)
	
 
	
$
	
732.9
	
 
	
 
	
$
	
728.9
	
 
	
 
	
$
	
195.2
	
 
	
 
	
$
	
201.5
	
 

	
Less: Fair value of plan
assets
	
 
	
 
	
625.4
	
 
	
 
	
 
	
648.0
	
 
	
 
	
 
	
20.6
	
 
	
 
	
 
	
18.8
	
 

	
Funded status at end of
year
	
 
	
$
	
(107.5
	
)
	
 
	
$
	
(80.9
	
)
	
 
	
$
	
(174.6
	
)
	
 
	
$
	
(182.7
	
)




The accumulated benefit obligation for TECO Energy consolidated
defined benefit pension plans was $686.9 million at Dec. 31, 2015 and $685.0 million at Dec. 31, 2014. 

The amounts recognized in TEC’s Consolidated Balance Sheets
for pension and other postretirement benefit obligations, plan assets, and unrecognized costs at Dec. 31 were as follows:
  
 
	
Tampa Electric Company
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
Amounts recognized in balance
sheet
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Regulatory assets
	
 
	
$
	
208.2
	
 
	
 
	
$
	
167.4
	
 
	
 
	
$
	
30.2
	
 
	
 
	
$
	
20.4
	
 

	
Accrued benefit costs and other
current liabilities
	
 
	
 
	
(0.6
	
)
	
 
	
 
	
(0.6
	
)
	
 
	
 
	
(9.2
	
)
	
 
	
 
	
(9.1
	
)

	
Deferred credits and other
liabilities
	
 
	
 
	
(69.3
	
)
	
 
	
 
	
(53.5
	
)
	
 
	
 
	
(142.3
	
)
	
 
	
 
	
(137.1
	
)

	
 
	
 
	
$
	
138.3
	
 
	
 
	
$
	
113.3
	
 
	
 
	
$
	
(121.3
	
)
	
 
	
$
	
(125.8
	
)




Unrecognized gains and losses and prior service credits and costs
are recorded in regulatory assets for TEC. The following table provides a detail of the unrecognized gains and losses and prior service credits and costs.
  


	
Amounts recognized in regulatory
assets
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Net actuarial loss (gain)
	
 
	
$
	
208.2
	
 
	
 
	
$
	
167.7
	
 
	
 
	
$
	
47.2
	
 
	
 
	
$
	
39.5
	
 

	
Prior service cost
(credit)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
(17.0
	
)
	
 
	
 
	
(19.1
	
)

	
Amount recognized
	
 
	
$
	
208.2
	
 
	
 
	
$
	
167.4
	
 
	
 
	
$
	
30.2
	
 
	
 
	
$
	
20.4
	
 




Assumptions used to determine benefit obligations at Dec. 31: 

 
 
	
 
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
 
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Discount rate
	
 
	
 
	
4.688
	
%
	
 
	
 
	
4.258
	
%
	
 
	
 
	
4.669
	
%
	
 
	
 
	
4.211
	
%

	
Rate of compensation
increase-weighted average
	
 
	
 
	
3.87
	
%
	
 
	
 
	
3.87
	
%
	
 
	
 
	
2.50
	
%
	
 
	
 
	
3.86
	
%

	
Healthcare cost trend rate
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Immediate rate
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
 
	
7.05
	
%
	
 
	
 
	
7.09
	
%

	
Ultimate rate
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
 
	
4.50
	
%
	
 
	
 
	
4.57
	
%

	
Year rate reaches
ultimate
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
2038
	
 
	
 
	
2025
	
 




 

A one-percentage-point change in assumed health care cost trend
rates would have the following effect on TEC’s benefit obligation: 

 
 
	
 (millions)
	
 
	
1% 
Increase
	
 
	
 
	
1 % 
Decrease
	
 

	
Effect on postretirement benefit
obligation
	
 
	
$
	
6.1
	
 
	
 
	
$
	
(5.2
	
)




The discount rate assumption used to determine the Dec. 31, 2015
benefit obligation was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate
bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits
and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate. 

142


 Amounts recognized in Net Periodic Benefit Cost, OCI, and Regulatory
Assets 

 
 
	
TECO Energy
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
 
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
(millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Service cost
	
 
	
$
	
20.9
	
 
	
 
	
$
	
18.3
	
 
	
 
	
$
	
18.2
	
 
	
 
	
$
	
2.2
	
 
	
 
	
$
	
2.5
	
 
	
 
	
$
	
2.5
	
 

	
Interest cost
	
 
	
 
	
30.3
	
 
	
 
	
 
	
32.0
	
 
	
 
	
 
	
28.9
	
 
	
 
	
 
	
8.2
	
 
	
 
	
 
	
10.8
	
 
	
 
	
 
	
9.3
	
 

	
Expected return on plan
assets
	
 
	
 
	
(43.3
	
)
	
 
	
 
	
(41.8
	
)
	
 
	
 
	
(38.4
	
)
	
 
	
 
	
(1.1
	
)
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
0.0
	
 

	
Amortization of:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Actuarial loss
	
 
	
 
	
15.1
	
 
	
 
	
 
	
13.5
	
 
	
 
	
 
	
20.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
1.0
	
 

	
Prior service (benefit)
cost
	
 
	
 
	
(0.2
	
)
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
(2.4
	
)
	
 
	
 
	
(0.2
	
)
	
 
	
 
	
(0.4
	
)

	
Curtailment loss (gain)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
3.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.2
	
)
	
 
	
 
	
0.0
	
 

	
Special termination
benefit
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Settlement loss
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Net periodic benefit
cost
	
 
	
$
	
22.8
	
 
	
 
	
$
	
25.7
	
 
	
 
	
$
	
29.8
	
 
	
 
	
$
	
6.9
	
 
	
 
	
$
	
12.8
	
 
	
 
	
$
	
12.4
	
 




 
 
	
New prior service cost
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
(3.7
	
)
	
 
	
$
	
(23.6
	
)
	
 
	
$
	
0.0
	
 

	
Net loss (gain) arising during the
year
	
 
	
 
	
74.5
	
 
	
 
	
 
	
44.1
	
 
	
 
	
 
	
(75.7
	
)
	
 
	
 
	
1.3
	
 
	
 
	
 
	
(9.9
	
)
	
 
	
 
	
(15.6
	
)

	
Unrecognized costs in regulated
asset acquired in business combination
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
6.4
	
 
	
 
	
 
	
0.0
	
 

	
Amounts recognized as component of
net periodic benefit cost:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Amortization of actuarial gain
(loss)
	
 
	
 
	
(15.1
	
)
	
 
	
 
	
(13.5
	
)
	
 
	
 
	
(21.5
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.2
	
)
	
 
	
 
	
(1.0
	
)

	
Amortization of prior service
(benefit) cost
	
 
	
 
	
0.2
	
 
	
 
	
0.4
	
 
	
 
	
 
	
0.4
	
 
	
 
	
 
	
2.4
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
0.3
	
 

	
Total recognized in OCI and
regulatory assets
	
 
	
$
	
59.6
	
 
	
 
	
$
	
31.0
	
 
	
 
	
$
	
(96.8
	
)
	
 
	
$
	
0.0
	
 
	
 
	
$
	
(27.1
	
)
	
 
	
$
	
(16.3
	
)

	
Total recognized in net periodic
benefit cost, OCI and regulatory assets
	
 
	
$
	
82.4
	
 
	
 
	
$
	
56.7
	
 
	
 
	
$
	
(67.0
	
)
	
 
	
$
	
6.9
	
 
	
 
	
$
	
(14.3
	
)
	
 
	
$
	
(3.9
	
)




 

TEC’s portion of the net periodic benefit costs for pension
benefits was $13.5 million, $14.8 million and $21.7 million for 2015, 2014 and 2013, respectively. TEC’s portion of the net periodic benefit costs for other benefits was $5.7 million, $10.4 million and $10.0 million for 2015, 2014 and 2013,
respectively. 
 The estimated net loss for the defined benefit
pension plans that will be amortized by TEC from regulatory assets into net periodic benefit cost over the next fiscal year are $9.8 million. There will be an estimated $1.9 million prior service credit that will be amortized from regulatory assets
into net periodic benefit cost over the next fiscal year for the other postretirement benefit plan. 

Assumptions used to determine net periodic benefit cost for years
ended Dec. 31: 
  
 
	
 
	
 
	
Pension
Benefits
	
 
	
 
	
Other
Benefits
	
 

	
 
	
 
	
2015
	
 
	
 
	
2014 (1)
	
 
	
 
	
2013
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Discount rate
	
 
	
 
	
4.258
	
%
	
 
	
5.118%/4.277%/4.331%

	
 
	
 
	
 
	
4.196
	
%
	
 
	
 
	
4.211
	
%
	
 
	
 
	
5.096
	
%
	
 
	
 
	
4.180
	
%

	
Expected long-term return on plan
assets
	
 
	
 
	
7.00
	
%
	
 
	
7.25%/7.00%/7.00%

	
 
	
 
	
 
	
7.50
	
%
	
 
	
 
	
5.75
	
 
	
 
	
 
	
5.75
	
 
	
 
	
n/a
	
 

	
Rate of compensation
increase
	
 
	
 
	
3.87
	
%
	
 
	
 
	
3.73
	
%
	
 
	
 
	
3.76
	
%
	
 
	
 
	
3.86
	
%
	
 
	
 
	
3.71
	
%
	
 
	
 
	
3.74
	
%

	
Healthcare cost trend rate
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Initial rate
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
 
	
7.09
	
%
	
 
	
 
	
7.25
	
%
	
 
	
 
	
7.50
	
%

	
Ultimate rate
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
 
	
4.57
	
%
	
 
	
 
	
4.50
	
%
	
 
	
 
	
4.50
	
%

	
Year rate reaches
ultimate
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
n/a
	
 
	
 
	
2025
	
 
	
 
	
2025
	
 
	
 
	
2025
	
 

	
(1)TECO Energy performed a
valuation as of Jan. 1, 2014. TECO remeasured its Retirement Plan on Sept. 2, 2014 for the acquisition of NMGC and on Oct. 31, 2014 for the expected curtailment of TECO Coal, resulting in the respective updated discount rates and EROAs.
	
 



 The discount rate assumption used to determine the
2015 benefit cost was based on a cash flow matching technique developed by outside actuaries and a review of current economic conditions. This technique constructs hypothetical bond portfolios using high-quality (AA or better by S&P) corporate
bonds available from the Barclays Capital database at the measurement date to meet the plan’s year-by-year projected cash flows. The technique calculates all possible bond portfolios that produce adequate cash flows to pay the yearly benefits
and then selects the portfolio with the highest yield and uses that yield as the recommended discount rate. 

The expected return on assets assumption was based on historical
returns, fixed income spreads and equity premiums consistent with the portfolio and asset allocation. A change in asset allocations could have a significant impact on the expected return on assets. 

143


 Additionally, expectations of long-term inflation, real growth in the economy and a provision for active
management and expenses paid were incorporated in the assumption. For the year ended Dec. 31, 2015, TECO
Energy’s pension plan’s assets decreased approximately 3.5%. 

The compensation increase assumption was based on the same
underlying expectation of long-term inflation together with assumptions regarding real growth in wages and company-specific merit and promotion increases. 

A one-percentage-point change in assumed health care cost trend
rates would have the following effect on TEC’s expense: 

 
 
	
 (millions)
	
 
	
1% 
Increase
	
 
	
 
	
1% 
Decrease
	
 

	
Effect on periodic cost
	
 
	
$
	
0.2
	
 
	
 
	
$
	
(0.2
	
)




Pension Plan Assets 

Pension plan assets (plan assets) are invested in a mix of equity
and fixed income securities. TECO Energy’s investment objective is to obtain above-average returns while minimizing volatility of expected returns and funding requirements over the long term. TECO Energy’s strategy is to hire proven
managers and allocate assets to reflect a mix of investment styles, emphasize preservation of principal to minimize the impact of declining markets, and stay fully invested except for cash to meet benefit payment obligations and plan expenses. 

 
 
	
 
	
 
	
Target 
Allocation
	
 
	
 
	
Actual Allocation, End of Year
	
 

	
Asset Category
	
 
	
 
	
 
	
 
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Equity securities
	
 
	
47%-53%
	
 
	
 
	
 
	
53
	
%
	
 
	
 
	
50
	
%

	
Fixed income securities
	
 
	
47%-53%
	
 
	
 
	
 
	
47
	
%
	
 
	
 
	
50
	
%

	
Total
	
 
	
 
	
100%
	
 
	
 
	
 
	
100
	
%
	
 
	
 
	
100
	
%




TECO Energy reviews the plan’s asset allocation
periodically and re-balances the investment mix to maximize asset returns, optimize the matching of investment yields with the plan’s expected benefit obligations, and minimize pension cost and funding. TECO Energy, Inc. expects to take
additional steps to more closely match plan assets with plan liabilities. 

The plan’s investments are held by a trust fund
administered by JP Morgan Chase Bank, N.A. (JP Morgan). Investments are valued using quoted market prices on an exchange when available. Such investments are classified Level 1. In some cases where a market exchange price is available but the
investments are traded in a secondary market, acceptable practical expedients are used to calculate fair value. 

If observable transactions and other market data are not
available, fair value is based upon third-party developed models that use, when available, current market-based or independently-sourced market parameters such as interest rates, currency rates or option volatilities. Items valued using third-party
generated models are classified according to the lowest level input or value driver that is most significant to the valuation. Thus, an item may be classified in Level 3 even though there may be significant inputs that are readily observable. 

144


 As required by the fair value accounting standards, the investments are classified in their entirety based on the
lowest level of input that is significant to the fair value measurement. The plan’s assessment of
the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. For cash equivalents, the cost approach was used in determining fair value. For bonds and U.S. government agencies, the income
approach was used. For other investments, the market approach was used. The following table sets forth by level within the fair value hierarchy the plan’s investments as of Dec. 31, 2015 and 2014. 

Pension Plan Investments

 
 
	
 (millions)
	
 
	
At Fair Value as of
Dec. 31, 2015
	
 

	
 
	
 
	
Level 1
	
 
	
 
	
Level 2
	
 
	
 
	
Level 
3
	
 
	
 
	
Using NAV (1)
	
 
	
 
	
Total
	
 

	
Net cash
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Cash
	
 
	
$
	
1.9
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
1.9
	
 

	
Accounts receivable
	
 
	
 
	
14.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
14.3
	
 

	
Accounts payable
	
 
	
 
	
(27.2
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(27.2
	
)

	
Total net cash
	
 
	
 
	
(11.0
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(11.0
	
)

	
Cash equivalents
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Money markets
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 

	
Discounted notes
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.7
	
 

	
Short-term investment funds
(STIFs) (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
12.4
	
 
	
 
	
 
	
12.4
	
 

	
Total cash equivalents
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
12.4
	
 
	
 
	
 
	
13.3
	
 

	
Equity securities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Common stocks
	
 
	
 
	
90.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
90.9
	
 

	
American depository receipts
(ADRs)
	
 
	
 
	
5.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
5.7
	
 

	
Real estate investment trusts
(REITs)
	
 
	
 
	
4.8
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
4.8
	
 

	
Commingled fund
	
 
	
 
	
0.0
	
 
	
 
	
 
	
53.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
53.7
	
 

	
Mutual funds (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
175.6
	
 
	
 
	
 
	
175.6
	
 

	
Total equity securities
	
 
	
 
	
101.4
	
 
	
 
	
 
	
53.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
175.6
	
 
	
 
	
 
	
330.7
	
 

	
Fixed income securities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Municipal bonds
	
 
	
 
	
0.0
	
 
	
 
	
 
	
5.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
5.0
	
 

	
Government bonds
	
 
	
 
	
0.0
	
 
	
 
	
 
	
56.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
56.2
	
 

	
Corporate bonds
	
 
	
 
	
0.0
	
 
	
 
	
 
	
32.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
32.2
	
 

	
Asset backed securities
(ABS)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.3
	
 

	
Mortgage-backed securities
(MBS), net short sales
	
 
	
 
	
0.0
	
 
	
 
	
 
	
8.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
8.7
	
 

	
Collateralized mortgage
obligations (CMOs)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.5
	
 

	
Commingled fund (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
117.9
	
 
	
 
	
 
	
117.9
	
 

	
Mutual fund (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
71.3
	
 
	
 
	
 
	
71.3
	
 

	
Total fixed income
securities
	
 
	
 
	
0.0
	
 
	
 
	
 
	
103.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
189.2
	
 
	
 
	
 
	
293.1
	
 

	
Derivatives
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Swaps
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.9
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.9
	
)

	
Purchased options
(swaptions)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.1
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.1
	
 

	
Written options
(swaptions)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(1.0
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(1.0
	
)

	
Total derivatives
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.8
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.8
	
)

	
Miscellaneous
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.1
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.1
	
 

	
Total
	
 
	
$
	
90.4
	
 
	
 
	
$
	
157.8
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
377.2
	
 
	
 
	
$
	
625.4
	
 





	 (1)
	 In accordance with accounting standards, certain
investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy
to amounts presented in the Consolidated Balance Sheet.



  

145


  
 
	
 (millions)
	
 
	
At Fair Value as of
Dec. 31, 2014
	
 

	
 
	
 
	
Level 1
	
 
	
 
	
Level 2
	
 
	
 
	
Level 
3
	
 
	
 
	
Using NAV (1)
	
 
	
 
	
Total
	
 

	
Net cash
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Cash
	
 
	
$
	
0.4
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.4
	
 

	
Accounts receivable
	
 
	
 
	
1.4
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.4
	
 

	
Accounts payable
	
 
	
 
	
(5.3
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(5.3
	
)

	
Total net cash
	
 
	
 
	
(3.5
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(3.5
	
)

	
Cash equivalents
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Treasury bills (T
bills)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 

	
Discounted notes
	
 
	
 
	
0.0
	
 
	
 
	
 
	
8.8
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
8.8
	
 

	
Short-term investment funds
(STIFs) (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
7.6
	
 
	
 
	
 
	
7.6
	
 

	
Total cash equivalents
	
 
	
 
	
0.0
	
 
	
 
	
 
	
9.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
7.6
	
 
	
 
	
 
	
16.6
	
 

	
Equity securities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Common stocks
	
 
	
 
	
98.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
98.0
	
 

	
American depository receipts
(ADRs)
	
 
	
 
	
1.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.3
	
 

	
Real estate investment trusts
(REITs)
	
 
	
 
	
2.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
2.5
	
 

	
Preferred stock
	
 
	
 
	
0.8
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.8
	
 

	
Commingled fund
	
 
	
 
	
0.0
	
 
	
 
	
 
	
45.6
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
45.6
	
 

	
Mutual funds (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
171.3
	
 
	
 
	
 
	
171.3
	
 

	
Total equity securities
	
 
	
 
	
102.6
	
 
	
 
	
 
	
45.6
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
171.3
	
 
	
 
	
 
	
319.5
	
 

	
Fixed income securities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Municipal bonds
	
 
	
 
	
0.0
	
 
	
 
	
 
	
6.1
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
6.1
	
 

	
Government bonds
	
 
	
 
	
0.0
	
 
	
 
	
 
	
47.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
47.9
	
 

	
Corporate bonds
	
 
	
 
	
0.0
	
 
	
 
	
 
	
22.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
22.0
	
 

	
Asset backed securities
(ABS)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.3
	
 

	
Mortgage-backed securities
(MBS), net short sales
	
 
	
 
	
0.0
	
 
	
 
	
 
	
9.6
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
9.6
	
 

	
Collateralized mortgage
obligations (CMOs)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
2.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
2.0
	
 

	
Commingled fund (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
129.20
	
 
	
 
	
 
	
129.2
	
 

	
Mutual fund (1)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
98.6
	
 
	
 
	
 
	
98.6
	
 

	
Total fixed income
securities
	
 
	
 
	
0.0
	
 
	
 
	
 
	
87.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
227.8
	
 
	
 
	
 
	
315.7
	
 

	
Derivatives
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Short futures
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.3
	
)

	
Purchased options
(swaptions)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.7
	
 

	
Written options
(swaptions)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.8
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.8
	
)

	
Total derivatives
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(0.4
	
)

	
Miscellaneous
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.1
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.1
	
 

	
Total
	
 
	
$
	
99.1
	
 
	
 
	
$
	
142.2
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
406.7
	
 
	
 
	
$
	
648.0
	
 





	 (1)
	 In accordance with accounting standards, certain
investments that are measured at fair value using the net asset value per share practical expedient have not been classified in the fair value hierarchy. The fair value amounts in this table are to permit reconciliation of the fair value hierarchy
to amounts presented in the Consolidated Balance Sheet.




The following list details the pricing inputs and
methodologies used to value the investments in the pension plan:
 
	  
	 ●
	 The primary
pricing inputs in determining the fair value of the Level 1 assets are closing quoted prices in active markets. 



 
	  
	 ●
	 The methodology
and inputs used to value the investment in the equity commingled fund are broker dealer quotes sourced by State Street Custody System.  The fund holds primarily international equity securities that are actively traded in over-the-counter
markets. The fund honors subscription and redemption activity on an “as of” basis. 



 
	  
	 ●
	 The money markets
are valued at cost due to their short-term nature. Discounted notes are valued at amortized cost.



 
	  
	 ●
	 The primary
pricing inputs in determining the fair value Level 2 municipal bonds are benchmark yields, historical spreads, sector curves, rating updates, and prepayment schedules. The primary pricing inputs in determining the fair value of government bonds are
the U.S. treasury curve, CPI, and broker quotes, if available. The primary pricing inputs in determining the fair value of corporate bonds are the U.S. treasury curve, base spreads, YTM, and benchmark quotes. ABS and CMO are priced using TBA prices,
treasury curves, swap curves, cash flow information, and bids and offers as inputs. MBS are priced using TBA prices, treasury curves, average lives, spreads, and cash flow information. 




146


 
	  
	 ●
	 Futures are valued using futures data, cash rate data, swap rates, and cash flow
analyses.



 
	  
	 ●
	 Swaps are valued
using benchmark yields, swap curves, and cash flow analyses.



 
	  
	 ●
	 Options are
valued using the bid-ask spread and the last price. 



 
	  
	 ●
	 The STIF is
valued at NAV as determined by JP Morgan. The funds are open-end investments. Additionally, shares may be redeemed any business day at the NAV calculated after the order is accepted. The NAV is validated with purchases and sales at NAV.




 
	  
	 ●
	 The primary
pricing inputs in determining the equity mutual funds are the mutual funds’ NAVs. The funds are registered open-ended mutual funds and the NAVs are validated with purchases and sales at NAV.



 
	  
	 ●
	 The primary
pricing input in determining the fair value of the fixed asset mutual fund is its NAV. It is an unregistered open-ended mutual fund. 



 
	  
	 ●
	 The fixed income
commingled fund is a private fund valued at NAV. The fund invests in long duration U.S. investment-grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The NAV is calculated based on bid
prices of the underlying securities. The fund honors subscription activity on the first business day of the month and the first business day following the 15th calendar day of the month.
Redemptions are honored on the 15th or last business day of the month, providing written notice is given at least ten business days prior to withdrawal date. 




Additionally, the unqualified SERP had $43.5 million and $0.9
million of assets as of Dec. 31, 2015 and 2014, respectively. Since the plan is unqualified, its assets are included in the “Deferred charges and other assets” line item in TECO Energy’s Consolidated Balance Sheets rather than
being netted with the related liability. The fund holds investments in a money market fund, which is valued at cost due to its short-term nature, making this a level 2 asset. The SERP was fully funded as of Dec. 31, 2015.

Other Postretirement Benefit Plan Assets 

There are no assets associated with TECO Energy’s other
postretirement benefits plan. Asset amounts shown in the tables above relate to a separate NMGC other postretirement benefit plan.

Contributions 

The Pension Protection Act became effective Jan. 1, 2008 and
requires companies to, among other things, maintain certain defined minimum funding thresholds (or face plan benefit restrictions), pay higher premiums to the PBGC if they sponsor defined benefit plans, amend plan documents and provide additional
plan disclosures in regulatory filings and to plan participants. 

WRERA was signed into law on Dec. 23, 2008. WRERA grants plan
sponsors relief from certain funding requirements and benefits restrictions, and also provides some technical corrections to the Pension Protection Act. There are two primary provisions that impact funding results for TECO Energy. First, for plans
funded less than 100%, required shortfall contributions will be based on a percentage of the funding target until 2013, rather than the funding target of 100%. Second, one of the technical corrections, referred to as asset smoothing, allows the use
of asset averaging subject to certain limitations in the determination of funding requirements. TECO Energy utilizes asset smoothing in determining funding requirements.

In August 2014, the President signed into law HAFTA, which
modified MAP-21. HAFTA and MAP-21 provide funding relief for pension plan sponsors by stabilizing discount rates used in calculating the required minimum pension contributions and increasing PBGC premium rates to be paid by plan sponsors. TECO
Energy expects the required minimum pension contributions to be lower than the levels previously projected; however, TECO Energy plans on funding at levels above the required minimum pension contributions under HAFTA and MAP-21. In November 2015,
the President signed into law the Bipartisan Budget Act of 2015, which extended pension funding relief of MAP-21 and HAFTA through 2022.

The qualified pension plan’s actuarial value of assets,
including credit balance, was 120.1% of the Pension Protection Act funded target as of Jan. 1, 2015 and is estimated at 114.1% of the Pension Protection Act funded target as of Jan. 1, 2016.

TECO Energy’s policy is to fund the qualified pension plan
at or above amounts determined by its actuaries to meet ERISA guidelines for minimum annual contributions and minimize PBGC premiums paid by the plan. TECO Energy made $55.0 million of contributions to this plan in 2015 and $47.5 million in 2014,
which met the minimum funding requirements for both 2015 and 2014. TEC’s portion of the contribution in 2015 was $43.9 million and in 2014 was $38.2 million. These amounts are reflected in the “Other” line on the Consolidated
Statements of Cash Flows. TECO Energy estimates its contribution in 2016 to be $37.4 million, with TEC’s portion being $30.9 million. TECO Energy estimates it will make annual contributions from 2017 to 2020 ranging from $12.2 to $44.6 million
per year based on current assumptions, with TEC’s portion to range from $8.0 million to $35.0 million. These amounts are in excess of the minimum funding required under ERISA guidelines. 

TECO Energy made contributions of $43.4 million and $1.2 million
to the SERP in 2015 and 2014, respectively. TEC’s portion of the contributions in 2015 and 2014 were $14.9 million and $0.8 million, respectively. TECO Energy’s contribution in October 2015 to the SERP’s trust was made in order to
fully fund its SERP obligation following the signing of the Merger Agreement with Emera. 

147


 The execution of the Merger Agreement constituted a potential change in control under the trust; therefore, TECO Energy
is required to maintain such funding as of the end of each calendar year, including 2015. The fully funded
amount is equal to the aggregate present value of all benefits then in pay status under the SERP plus the current value of benefits that would become payable under the SERP to current participants. Since the SERP is fully funded, TECO Energy does not expect to make significant contributions to this plan in 2016. 

The other postretirement benefits are funded annually to meet
benefit obligations. TECO Energy’s contribution toward health care coverage for most employees who retired after the age of 55 between Jan. 1, 1990 and Jun. 30, 2001 is limited to a defined dollar benefit based on service. TECO Energy’s
contribution toward pre-65 and post-65 health care coverage for most employees retiring on or after July 1, 2001 is limited to a defined dollar benefit based on an age and service schedule. In 2016, TECO Energy expects to make a contribution of
about $14.3 million. TEC’s portion of the expected contribution is $9.3 million. Postretirement benefit levels are substantially unrelated to salary. 

Benefit Payments 

The following benefit payments, which reflect expected future
service, as appropriate, are expected to be paid: 
 Expected Benefit
Payments—TECO Energy
 
	
 (including projected service and net
of employee contributions)
	
 
	
 
	
 
	
 
	
 
	
Other
	
 

	
 
	
 
	
Pension
	
 
	
 
	
Postretirement
	
 

	
(millions)
	
 
	
Benefits
	
 
	
 
	
Benefits
	
 

	
2016
	
 
	
$
	
77.8
	
 
	
 
	
$
	
11.5
	
 

	
2017
	
 
	
 
	
49.5
	
 
	
 
	
 
	
11.9
	
 

	
2018
	
 
	
 
	
52.7
	
 
	
 
	
 
	
12.5
	
 

	
2019
	
 
	
 
	
59.2
	
 
	
 
	
 
	
13.0
	
 

	
2020
	
 
	
 
	
54.9
	
 
	
 
	
 
	
13.3
	
 

	
2021-2025
	
 
	
 
	
299.1
	
 
	
 
	
 
	
68.6
	
 




Defined Contribution Plan 

TECO Energy has a defined contribution savings plan covering
substantially all employees of TECO Energy and its subsidiaries that enables participants to save a portion of their compensation up to the limits allowed by IRS guidelines. TECO Energy and its subsidiaries match up to 6% of the participant’s
payroll savings deductions. Effective Jan. 1, 2015, the employer matching contributions were 70% of eligible participant contributions with additional incentive match of up to 30% of eligible participant contributions based on the achievement of
certain operating company financial goals. During the period from April 2013 to December 2014, employer matching contributions were 65% of eligible participant contributions with additional incentive match of up to 35% of eligible participant
contributions based on the achievement of certain operating company financial goals. Prior to this, the employer matching contributions were 60% of eligible participant contributions with additional incentive match of up to 40%. For the years ended
Dec. 31, 2015, 2014 and 2013, TECO Energy and its subsidiaries recognized expense totaling $11.1 million, $13.1 million and $11.3 million, respectively, related to the matching contributions made to this plan. TEC’s portion of expense totaled
$7.5 million, $10.2 million and $9.1 million for 2015, 2014 and 2013, respectively.

 

 

6. Short-Term Debt 

At Dec. 31, 2015 and 2014, the following credit facilities and
related borrowings existed: 
 Credit Facilities

 
 
	
 
	
 
	
Dec. 31, 
2015
	
 
	
 
	
Dec. 31, 
2014
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Letters
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Letters
	
 

	
 
	
 
	
Credit
	
 
	
 
	
Borrowings
	
 
	
 
	
of Credit
	
 
	
 
	
Credit
	
 
	
 
	
Borrowings
	
 
	
 
	
of Credit
	
 

	
(millions)
	
 
	
Facilities
	
 
	
 
	
Outstanding (1)
	
 
	
 
	
Outstanding
	
 
	
 
	
Facilities
	
 
	
 
	
Outstanding (1)
	
 
	
 
	
Outstanding
	
 

	
Tampa Electric Company:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
5-year facility (2)
	
 
	
$
	
325.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.5
	
 
	
 
	
$
	
325.0
	
 
	
 
	
$
	
12.0
	
 
	
 
	
$
	
0.6
	
 

	
3-year accounts receivable
facility (3)
	
 
	
 
	
150.0
	
 
	
 
	
 
	
61.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
150.0
	
 
	
 
	
 
	
46.0
	
 
	
 
	
 
	
0.0
	
 

	
Total
	
 
	
$
	
475.0
	
 
	
 
	
$
	
61.0
	
 
	
 
	
$
	
0.5
	
 
	
 
	
$
	
475.0
	
 
	
 
	
$
	
58.0
	
 
	
 
	
$
	
0.6
	
 





	 (1)
	 Borrowings outstanding are reported as notes payable.




 
	 (2)
	 This 5-year facility matures Dec. 17, 2018.




 
	 (3)
	 Prior to Mar. 24, 2015, this was a 1-year facility. This 3-year
facility matures Mar. 23, 2018.




148


 At Dec. 31, 2015, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on borrowings outstanding under the credit facilities at Dec. 31, 2015 and 2014 was 0.89% and 0.7%, respectively.

Tampa Electric Company Accounts Receivable Facility 

On Mar. 24, 2015, TEC and TRC amended and restated their $150
million accounts receivable collateralized borrowing facility in order to (i) appoint The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch (BTMU), as Program Agent, replacing the previous Program Agent, Citibank, N.A., (ii) add new lenders, and
(iii) extend the scheduled termination date from Apr. 14, 2015 to Mar. 23, 2018, by entering into (a) an Amended and Restated Purchase and Contribution Agreement dated as of Mar. 24, 2015 between TEC and TRC and (b) a Loan and Servicing Agreement
dated as of Mar. 24, 2015, among TEC as Servicer, TRC as Borrower, certain lenders named therein and BTMU, as Program Agent (the Loan Agreement). Pursuant to the Loan Agreement, TRC will pay program and liquidity fees, which total 65 basis points as
of Dec. 31, 2015. Interest rates on the borrowings are based on prevailing asset-backed commercial paper rates, unless such rates are not available from conduit lenders, in which case the rates will be at an interest rate equal to, at TEC’s
option, either the BTMU’s prime rate (or the federal funds rate plus 50 basis points, if higher) or a rate based on the London interbank deposit rate (if available) plus a margin.  In addition, under the terms of the Loan Agreement,
TEC has pledged as collateral a pool of receivables equal to the borrowings outstanding in the case of default. TEC continues to service, administer and collect the pledged receivables, which are classified as receivables on the balance sheet. As of
Dec. 31, 2015, TEC and TRC were in compliance with the requirements of the Loan Agreement.  

Amendment of Tampa Electric Company Credit Facility

On Dec. 17, 2013, TEC amended and restated its $325 million bank
credit facility, entering into a Fourth Amended and Restated Credit Agreement. The amendment (i) extended the maturity date of the credit facility from Oct. 25, 2016 to Dec. 17, 2018 (subject to further
extension with the consent of each lender); (ii) continues to allow TEC, as borrower, to borrow funds at a rate equal to the London interbank deposit rate plus a margin; (iii) as an alternative to the above interest rate, allows TEC to borrow
funds at an interest rate equal to a margin plus the higher of Citibank's prime rate, the federal funds rate plus 50 basis points, or the London interbank deposit rate plus 1.00%; (iv) allows TEC to borrow funds on a same-day basis under a swingline
loan provision, which loans mature on the fourth banking day after which any such loans are made and bear interest at an interest rate as agreed by the borrower and the relevant swingline lender prior to the making of any such loans; (v) continues
to allow TEC to request the lenders to increase their commitments under the credit facility by up to $175 million in the aggregate; (vi) includes a $200 million letter of credit facility; and (vii) made other technical changes.

On Sept. 30, 2014, TEC entered into an amendment of its $325
million bank credit facility, which reallocated commitments among the lenders and made certain other technical changes. 
  

 
  

7. Long-Term Debt  

A substantial part of Tampa Electric’s tangible assets are
pledged as collateral to secure its first mortgage bonds. There are currently no bonds outstanding under Tampa Electric’s first mortgage bond indenture, and Tampa Electric could cause the lien associated with this indenture to be released at
any time. 
 Issuance of Tampa Electric Company 4.20% Notes due
2045
 On May 20, 2015, TEC completed an offering of $250
million aggregate principal amount of 4.20% Notes due May 15, 2045 (the TEC 2015 Notes).  The TEC 2015 Notes were sold at 99.814% of par. The offering resulted in net proceeds to TEC (after deducting underwriting discounts, commissions,
estimated offering expenses and before settlement of interest rate swaps) of approximately $246.8 million. Net proceeds were used to repay short-term debt and for general corporate purposes. Until Nov. 15, 2044, TEC may redeem all or any part of the
TEC 2015 Notes at its option at any time and from time to time at a redemption price equal to the greater of (i) 100% of the principal amount of the TEC 2015 Notes to be redeemed or (ii) the sum of the present value of the remaining payments of
principal and interest on the TEC 2015 Notes to be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 20 basis points; in either case, the redemption price would include accrued and unpaid interest to the
redemption date.  At any time on or after Nov. 15, 2044, TEC may, at its option, redeem the TEC 2015 Notes, in whole or in part, at 100% of the principal amount of the TEC 2015 Notes being redeemed plus accrued and unpaid interest thereon
to but excluding the date of redemption.
 Issuance of Tampa
Electric Company 4.35% Notes due 2044 
 On May 15, 2014,
TEC completed an offering of $300 million aggregate principal amount of 4.35% Notes due 2044 (the TEC 2014 Notes). The TEC 2014 Notes were sold at 99.933% of par. The offering resulted in net proceeds to TEC (after deducting 

149


 underwriting discounts, commissions, estimated offering expenses and before settlement of interest rate swaps) of
approximately $296.6 million. Net proceeds were used to repay short-term debt and for general corporate
purposes. TEC may redeem all or any part of the TEC 2014 Notes at its option at any time and from time to
time before Nov. 15, 2043 at a redemption price equal to the greater of (i) 100% of the principal amount of TEC 2014 Notes to be redeemed or
(ii) the sum of the present value of the remaining payments of principal and interest on the notes to
be redeemed, discounted at an applicable treasury rate (as defined in the indenture), plus 15 basis points; in either case, the redemption price would include accrued and unpaid interest to the redemption date. At any time on or after Nov. 15, 2043, TEC may at its option redeem the
TEC 2014 Notes, in whole or in part, at 100% of the principal amount of the notes being redeemed plus accrued and unpaid interest thereon to but excluding the date of redemption. 

Purchase in Lieu of Redemption of Revenue Refunding Bonds      

On Mar. 15, 2012, TEC purchased in lieu of redemption $86.0
million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2006 (Non-AMT) (the Series 2006 HCIDA Bonds). On Mar. 19, 2008, the HCIDA had remarketed the Series 2006 HCIDA Bonds in a term-rate mode pursuant
to the terms of the Loan and Trust Agreement governing those bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 5.00% per annum from Mar. 19, 2008 to Mar. 15, 2012. TEC is responsible for payment of the interest and
principal associated with the Series 2006 HCIDA Bonds. Regularly scheduled principal and interest when due, are insured by Ambac Assurance Corporation. 

On Sept. 3, 2013, TEC purchased in lieu of redemption $51.6
million HCIDA Pollution Control Revenue Refunding Bonds (Tampa Electric Company Project), Series 2007 B (the Series 2007 B HCIDA Bonds). On Mar. 26, 2008, the HCIDA had remarketed the Series 2007 B HCIDA Bonds in a term-rate mode pursuant to
the terms of the Loan and Trust Agreement governing those bonds. The Series 2007 B HCIDA Bonds bore interest at a term rate of 5.15% per annum from Mar. 26, 2008 to Sept. 1, 2013. TEC is responsible for payment of the interest and
principal associated with the Series 2007 B HCIDA Bonds. 
 As
of Dec. 31, 2015, $232.6 million of bonds purchased in lieu of redemption were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives. 

 
  

8. Other Comprehensive Income 

TEC reported the following OCI (loss) for the years ended Dec.
31, 2015, 2014 and 2013, related to the amortization of prior settled amounts and changes in the fair value of cash flow hedges: 

Other Comprehensive Income

 
 
	
 (millions)
	
 
	
Gross
	
 
	
 
	
Tax
	
 
	
 
	
Net
	
 

	
2015
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Unrealized gain (loss) on cash flow
hedges
	
 
	
$
	
4.3
	
 
	
 
	
$
	
(1.5
	
)
	
 
	
$
	
2.8
	
 

	
Reclassification from AOCI to net
income
	
 
	
 
	
1.4
	
 
	
 
	
 
	
(0.7
	
)
	
 
	
 
	
0.7
	
 

	
Gain (Loss) on cash flow
hedges
	
 
	
 
	
5.7
	
 
	
 
	
 
	
(2.2
	
)
	
 
	
 
	
3.5
	
 

	
Total other comprehensive income
(loss)
	
 
	
$
	
5.7
	
 
	
 
	
$
	
(2.2
	
)
	
 
	
$
	
3.5
	
 

	
2014
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Unrealized gain (loss) on cash flow
hedges
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 

	
Reclassification from AOCI to net
income
	
 
	
 
	
1.1
	
 
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
0.7
	
 

	
Gain (Loss) on cash flow
hedges
	
 
	
 
	
1.1
	
 
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
0.7
	
 

	
Total other comprehensive income
(loss)
	
 
	
$
	
1.1
	
 
	
 
	
$
	
(0.4
	
)
	
 
	
$
	
0.7
	
 

	
2013
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Unrealized gain (loss) on cash flow
hedges
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 

	
Reclassification from AOCI to net
income
	
 
	
 
	
1.4
	
 
	
 
	
 
	
(0.5
	
)
	
 
	
 
	
0.9
	
 

	
Gain (Loss) on cash flow
hedges
	
 
	
 
	
1.4
	
 
	
 
	
 
	
(0.5
	
)
	
 
	
 
	
0.9
	
 

	
Total other comprehensive income
(loss)
	
 
	
$
	
1.4
	
 
	
 
	
$
	
(0.5
	
)
	
 
	
$
	
0.9
	
 




Accumulated Other Comprehensive
Loss 
  
 
	
 (millions) As of Dec. 31,
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Net unrealized losses from cash
flow hedges (1)
	
 
	
$
	
(3.6
	
)
	
 
	
$
	
(7.1
	
)

	
Total accumulated other
comprehensive loss
	
 
	
$
	
(3.6
	
)
	
 
	
$
	
(7.1
	
)





	 (1)
	 Net of tax benefit of $2.3 million and $4.5 million as of Dec.
31, 2015 and 2014, respectively. 




150


  
  

9. Commitments and Contingencies 

Legal Contingencies 

From time to time, TEC and its subsidiaries are involved in
various legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies in the ordinary course of its business. Where appropriate, accruals are made in accordance with accounting standards for
contingencies to provide for matters that are probable of resulting in an estimable loss. The company believes the claims in the pending actions described below are without merit and intends to defend the matters vigorously. TEC is unable at this
time to estimate the possible loss or range of loss with respect to these matters. While the outcome of such proceedings is uncertain, management does not believe that their ultimate resolution will have a material adverse effect on the TEC’s
results of operations, financial condition or cash flows. 

Tampa Electric Legal Proceedings

A 36-year-old man died from mesothelioma in March 2014. His
estate and his family sued Tampa Electric as a result. The man allegedly suffered exposure to asbestos dust brought home by his father and grandfather, both of whom had been employed as insulators and worked at various job sites throughout the Tampa
area. Plaintiff’s case against Tampa Electric and 14 other defendants had alleged, among other things, negligence, strict liability, household exposure, loss of consortium, and wrongful death. Tampa Electric has agreed to a settlement which
resolved the case in its entirety. The settlement is not material to TEC’s financial position as of Dec. 31, 2015. 
  

A 33-year-old man made contact with a primary line in June 2013,
suffering severe burns. He and his wife sued Tampa Electric as a result. The man apparently made contact with the line as he was attempting to trim a tree at a local residence.  Plaintiffs' case against Tampa Electric alleged, among other
things, negligence and loss of consortium.  Tampa Electric has agreed to a settlement which resolved the case in its entirety. The settlement is not material to TEC’s financial position as of Dec. 31, 2015.

 

Peoples Gas Legal Proceedings 

In November 2010, heavy equipment operated at a road construction
site being conducted by Posen Construction, Inc. struck a natural gas line causing a rupture and ignition of the gas and an outage in the natural gas service to Lee and Collier counties, Florida.  PGS filed suit in April 2011 against Posen
Construction, Inc. in Federal Court for the Middle District of Florida to recover damages for repair and restoration relating to the incident and Posen Construction, Inc. counter-claimed against PGS alleging negligence. In the first quarter of 2014,
the parties entered into a settlement agreement that resolves the claims of the parties. In addition, the suit filed in November 2011 by the Posen Construction, Inc. employee operating the heavy equipment involved in the incident in Lee County
Circuit Court against PGS and a PGS contractor involved in the project, seeking damages for his injuries, remains pending, with a trial currently expected in late 2016. 

PGS Compliance Matter

          In 2015, FPSC staff presented PGS with a summary of alleged safety rule violations, many of which
were identified during PGS’ implementation of an action plan it instituted as a result of audit findings cited by FPSC audit staff in 2013. Following the 2013 audit and 2015 discussions with FPSC staff, PGS took immediate and significant
corrective actions. The FPSC audit staff published a follow-up audit report that acknowledged the progress that had been made and found that further improvements were needed.  As a result of this report, the Office of Public Counsel (OPC) filed
a petition with the FPSC pointing to the violations of rules for safety inspections seeking fines or possible refunds to customers by PGS. On Feb. 25, 2016, the FPSC staff issued a notice informing PGS that the staff would be making a recommendation
to the FPSC to initiate a show cause proceeding against PGS for alleged safety rule violations, with total potential penalties of up to $3.9 million. PGS is continuing to work with the OPC and FPSC staff to resolve the issues.

Superfund and Former Manufactured Gas Plant Sites 

TEC, through its Tampa Electric and Peoples Gas divisions, is a
PRP for certain superfund sites and, through its Peoples Gas division, for certain former manufactured gas plant sites. While the joint and several liability associated with these sites presents the potential for significant response costs, as of
Dec. 31, 2015, TEC has estimated its ultimate financial liability to be $33.9 million, primarily at PGS. This amount has been accrued and is primarily reflected in the long-term liability section under “Deferred credits and other
liabilities” on the Consolidated Condensed Balance Sheets. The environmental remediation costs associated with these sites, which are expected to be paid over many years, are not expected to have a significant impact on customer rates. 

The estimated amounts represent only the portion of the cleanup
costs attributable to TEC. The estimates to perform the work are based on TEC’s experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current
dollars, are not discounted and do not assume any insurance recoveries. 

151


 In instances where other PRPs are involved, most of those PRPs are creditworthy and are likely to continue to be
creditworthy for the duration of the remediation work. However, in those instances that they are not, TEC could be liable for more than TEC’s actual percentage of the remediation costs. 

Factors that could impact these estimates include the ability of
other PRPs to pay their pro-rata portion of the cleanup costs, additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in
laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in subsequent base rate proceedings. 

Long-Term Commitments

TEC has commitments for capacity payments and long-term leases,
primarily for building space, vehicles, office equipment and heavy equipment. Rental expense for these leases included in “Regulated operations & maintenance – Other” on the Consolidated Statements of Income for the years
ended Dec. 31, 2015, 2014 and 2013, totaled $3.8 million, $4.1 million and $2.3 million, respectively. In addition, Tampa Electric has other purchase obligations, including its outstanding commitments for major projects and long-term capitalized
maintenance agreements for its combustion turbines.   The following is a schedule of future minimum lease payments with non-cancelable lease terms in excess of one year, capacity payments under PPAs, and other net purchase
obligations/commitments at Dec. 31, 2015: 
  
 
	
 
	
 
	
Capacity
	
 
	
 
	
Operating
	
 
	
 
	
Net
Purchase
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
Payments
	
 
	
 
	
Leases(1)
	
 
	
 
	
Obligations/Commitments
(1)
	
 
	
 
	
Total
	
 

	
Year ended Dec. 31:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
2016
	
 
	
$
	
14.6
	
 
	
 
	
$
	
5.7
	
 
	
 
	
$
	
218.3
	
 
	
 
	
$
	
238.6
	
 

	
2017
	
 
	
 
	
9.9
	
 
	
 
	
 
	
5.2
	
 
	
 
	
 
	
21.5
	
 
	
 
	
 
	
36.6
	
 

	
2018
	
 
	
 
	
10.1
	
 
	
 
	
 
	
4.7
	
 
	
 
	
 
	
9.6
	
 
	
 
	
 
	
24.4
	
 

	
2019
	
 
	
 
	
0.0
	
 
	
 
	
 
	
4.4
	
 
	
 
	
 
	
9.7
	
 
	
 
	
 
	
14.1
	
 

	
2020
	
 
	
 
	
0.0
	
 
	
 
	
 
	
4.1
	
 
	
 
	
 
	
4.7
	
 
	
 
	
 
	
8.8
	
 

	
Thereafter
	
 
	
 
	
0.0
	
 
	
 
	
 
	
14.5
	
 
	
 
	
 
	
20.0
	
 
	
 
	
 
	
34.5
	
 

	
Total future minimum
payments
	
 
	
$
	
34.6
	
 
	
 
	
$
	
38.6
	
 
	
 
	
$
	
283.8
	
 
	
 
	
$
	
357.0
	
 





	 (1)
	 Excludes payment obligations under contractual agreements of
Tampa Electric and PGS for fuel, fuel transportation and power purchases which are recovered from customers under regulatory clauses approved by the FPSC annually. 




Guarantees and Letters of Credit 

At Dec. 31, 2015, TEC was not obligated under guarantees, but had
the following letters of credit outstanding. 
 
	
 (millions)
	
 
	
Year of
Expiration
	
 
	
 
	
Maximum
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
After (1)
	
 
	
 
	
Theoretical
	
 
	
 
	
Liabilities 
Recognized
	
 

	
Letter of Credit for the Benefit
of:
	
 
	
2016
	
 
	
 
	
2017-2020
	
 
	
 
	
2020
	
 
	
 
	
Obligation
	
 
	
 
	
at Dec. 31, 2015 (2)
	
 

	
TEC
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.5
	
 
	
 
	
$
	
0.5
	
 
	
 
	
$
	
0.1
	
 





	 (1)
	 These letters of credit and guarantees renew annually and are
shown on the basis that they will continue to renew beyond 2020. 



 
	 (2)
	 The amounts shown are the maximum
theoretical amounts guaranteed under current agreements. Liabilities recognized represent the associated obligation under these agreements at Dec. 31, 2015. The obligations under these letters of credit include certain accrued injuries and damages
when a letter of credit covers the failure to pay these claims. 




Financial Covenants 

In order to utilize their respective bank credit facilities, TEC
must meet certain financial tests as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Dec. 31, 2015, TEC was in compliance with all required financial covenants.

  

152


 10. Related Party Transactions 

A summary of activities between TEC and its affiliates follows:

 Net transactions with affiliates: 

 
 
	
 (millions)
	
 
	
2015
	
 
	
 
	
2014
	
 
	
 
	
2013
	
 

	
Natural gas sales, net
	
 
	
$
	
0.8
	
 
	
 
	
$
	
0.3
	
 
	
 
	
$
	
18.3
	
 

	
Administrative and general, net(1)
	
 
	
$
	
69.4
	
 
	
 
	
$
	
22.5
	
 
	
 
	
$
	
27.2
	
 





	 (1)
	 The 2015 increase in transactions with affiliates is attributable
to shared services being provided to TEC from TSI, TECO Energy’s centralized services company subsidiary, beginning in Jan. 1, 2015. 




Amounts due from or to affiliates at Dec. 31, 

 
 
	
 (millions)
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Accounts receivable(1)
	
 
	
$
	
2.3
	
 
	
 
	
$
	
2.4
	
 

	
Accounts payable(1)
	
 
	
 
	
15.9
	
 
	
 
	
 
	
9.7
	
 

	
Taxes receivable(2)
	
 
	
 
	
61.3
	
 
	
 
	
 
	
43.3
	
 

	
Taxes payable(2)
	
 
	
 
	
1.0
	
 
	
 
	
 
	
0.0
	
 





	 (1)
	 Accounts receivable and accounts payable were incurred in the
ordinary course of business and do not bear interest. 



 
	 (2)
	 Taxes receivable are due from, and taxes payable are due to, TECO
Energy.



 TEC had certain
transactions, in the ordinary course of business, with entities in which directors of TEC had interests. TEC paid legal fees of $1.7 million for the year ended Dec. 31, 2013 to Ausley McMullen, P.A. of which Mr. Ausley (who was a director of
TEC, until his retirement from the Board in May 2013) was an employee. 
  
  

11. Segment Information 

TEC is a public utility operating within the State of Florida.
Through its Tampa Electric division, it is engaged in the generation, purchase, transmission, distribution and sale of electric energy to almost 719,000 customers in West Central Florida. Its PGS division is engaged in the purchase, distribution and
marketing of natural gas for approximately 361,000 residential, commercial, industrial and electric power generation customers in the State of Florida. 

153


  
 
	
 
	
 
	
Tampa
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
Electric
	
 
	
 
	
PGS
	
 
	
 
	
Eliminations
	
 
	
 
	
TEC
	
 

	
2015
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Revenues - external
	
 
	
$
	
2,017.7
	
 
	
 
	
$
	
401.5
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
2,419.2
	
 

	
Sales to affiliates
	
 
	
 
	
0.6
	
 
	
 
	
 
	
6.0
	
 
	
 
	
 
	
(6.6
	
)
	
 
	
 
	
0.0
	
 

	
Total revenues
	
 
	
 
	
2,018.3
	
 
	
 
	
 
	
407.5
	
 
	
 
	
 
	
(6.6
	
)
	
 
	
 
	
2,419.2
	
 

	
Depreciation and
amortization
	
 
	
 
	
256.7
	
 
	
 
	
 
	
56.8
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
313.5
	
 

	
Total interest charges
	
 
	
 
	
95.1
	
 
	
 
	
 
	
14.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
109.6
	
 

	
Provision for income taxes
	
 
	
 
	
143.6
	
 
	
 
	
 
	
21.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
165.5
	
 

	
Net income
	
 
	
 
	
241.0
	
 
	
 
	
 
	
35.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
276.3
	
 

	
Total assets
	
 
	
 
	
6,637.1
	
 
	
 
	
 
	
1,099.0
	
 
	
 
	
 
	
(9.4
	
)
	
 
	
 
	
7,726.7
	
 

	
Capital expenditures
	
 
	
 
	
592.6
	
 
	
 
	
 
	
94.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
686.6
	
 

	
2014
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Revenues - external
	
 
	
$
	
2,020.5
	
 
	
 
	
$
	
398.5
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
2,419.0
	
 

	
Sales to affiliates
	
 
	
 
	
0.5
	
 
	
 
	
 
	
1.1
	
 
	
 
	
 
	
(1.6
	
)
	
 
	
 
	
0.0
	
 

	
Total revenues
	
 
	
 
	
2,021.0
	
 
	
 
	
 
	
399.6
	
 
	
 
	
 
	
(1.6
	
)
	
 
	
 
	
2,419.0
	
 

	
Depreciation and
amortization
	
 
	
 
	
248.6
	
 
	
 
	
 
	
54.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
302.6
	
 

	
Total interest charges
	
 
	
 
	
92.8
	
 
	
 
	
 
	
13.8
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
106.6
	
 

	
Provision for income taxes
	
 
	
 
	
133.2
	
 
	
 
	
 
	
22.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
155.9
	
 

	
Net income
	
 
	
 
	
224.5
	
 
	
 
	
 
	
35.8
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
260.3
	
 

	
Total assets
	
 
	
 
	
6,234.4
	
 
	
 
	
 
	
1,047.0
	
 
	
 
	
 
	
(7.1
	
)
	
 
	
 
	
7,274.3
	
 

	
Capital expenditures
	
 
	
 
	
582.1
	
 
	
 
	
 
	
88.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
671.0
	
 

	
2013
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Revenues - external
	
 
	
$
	
1,950.1
	
 
	
 
	
$
	
392.7
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
2,342.8
	
 

	
Sales to affiliates
	
 
	
 
	
0.4
	
 
	
 
	
 
	
0.8
	
 
	
 
	
 
	
(1.2
	
)
	
 
	
 
	
0.0
	
 

	
Total revenues
	
 
	
 
	
1,950.5
	
 
	
 
	
 
	
393.5
	
 
	
 
	
 
	
(1.2
	
)
	
 
	
 
	
2,342.8
	
 

	
Depreciation and
amortization
	
 
	
 
	
238.8
	
 
	
 
	
 
	
51.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
290.3
	
 

	
Total interest charges
	
 
	
 
	
91.8
	
 
	
 
	
 
	
13.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
105.3
	
 

	
Provision for income taxes
	
 
	
 
	
116.9
	
 
	
 
	
 
	
21.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
138.8
	
 

	
Net income
	
 
	
 
	
190.9
	
 
	
 
	
 
	
34.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
225.6
	
 

	
Total assets
	
 
	
 
	
5,895.4
	
 
	
 
	
 
	
989.3
	
 
	
 
	
 
	
(8.9
	
)
	
 
	
 
	
6,875.8
	
 

	
Capital expenditures
	
 
	
 
	
422.3
	
 
	
 
	
 
	
79.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
501.3
	
 




 
  

12. Asset Retirement Obligations 

TEC accounts for AROs under the applicable accounting standards.
An ARO for a long-lived asset is recognized at fair value at inception of the obligation if there is a legal obligation under an existing or enacted law or statute, a written or oral contract or by legal construction under the doctrine of promissory
estoppel. Retirement obligations are recognized only if the legal obligation exists in connection with or as a result of the permanent retirement, abandonment or sale of a long-lived asset. 

When the liability is initially recorded, the carrying amount of
the related long-lived asset is correspondingly increased. Over time, the liability is accreted to its estimated future value. The corresponding amount capitalized at inception is depreciated over the remaining useful life of the asset. The
liability must be revalued each period based on current market prices. 

As regulated utilities, Tampa Electric and PGS must file
depreciation and dismantlement studies periodically and receive approval from the FPSC before implementing new depreciation rates. Included in approved depreciation rates is either an implicit net salvage factor or a cost of removal factor,
expressed as a percentage. The net salvage factor is principally comprised of two components—a salvage factor and a cost of removal or dismantlement factor. TEC uses current cost of removal or dismantlement factors as part of the estimation
method to approximate the amount of cost of removal in accumulated depreciation. 

For Tampa Electric and PGS, the original cost of utility plant
retired or otherwise disposed of and the cost of removal or dismantlement, less salvage value, is charged to accumulated depreciation and the accumulated cost of removal reserve reported as a regulatory liability, respectively. 

154


 Reconciliation of beginning and ending carrying amount of asset retirement obligations: 

 
 
	
 
	
 
	
Dec. 31,
	
 

	
(millions)
	
 
	
2015
	
 
	
 
	
2014
	
 

	
Beginning balance
	
 
	
$
	
5.3
	
 
	
 
	
$
	
4.8
	
 

	
Additional liabilities
	
 
	
 
	
0.9
	
 
	
 
	
 
	
0.1
	
 

	
Revisions to estimated cash
flows
	
 
	
 
	
(0.5
	
)
	
 
	
 
	
0.2
	
 

	
Other
(1)
	
 
	
 
	
0.3
	
 
	
 
	
 
	
0.2
	
 

	
Ending balance
	
 
	
$
	
6.0
	
 
	
 
	
$
	
5.3
	
 





	 (1)
	 Accretion recorded as a deferred regulatory asset.




  
  

13. Accounting for Derivative Instruments and Hedging Activities 

From time to time, TEC enters into futures, forwards, swaps and
option contracts for the following purposes: 
 
	  
	 ·
	 To limit the exposure to price fluctuations for
physical purchases and sales of natural gas in the course of normal operations, and 



 
	  
	 ·
	 To limit the exposure to interest rate
fluctuations on debt securities. 




TEC uses derivatives only to reduce normal operating and market
risks, not for speculative purposes. TEC’s primary objective in using derivative instruments for regulated operations is to reduce the impact of market price volatility on ratepayers. 

The risk management policies adopted by TEC provide a framework
through which management monitors various risk exposures. Daily and periodic reporting of positions and other relevant metrics are performed by a centralized risk management group, which is independent of all operating companies. 

TEC applies the accounting standards for derivative instruments
and hedging activities. These standards require companies to recognize derivatives as either assets or liabilities in the financial statements, to measure those instruments at fair value and to reflect the changes in the fair value of those
instruments as either components of OCI or in net income, depending on the designation of those instruments (see Note 14). The changes in fair value that are recorded in OCI are not immediately recognized in
current net income. As the underlying hedged transaction matures or the physical commodity is delivered, the deferred gain or loss on the related hedging instrument must be reclassified from OCI to earnings based on its value at the time of the
instrument’s settlement. For effective hedge transactions, the amount reclassified from OCI to earnings is offset in net income by the market change of the amount paid or received on the underlying physical transaction. 

TEC applies the accounting standards for regulated operations to
financial instruments used to hedge the purchase of natural gas for its regulated companies. These standards, in accordance with the FPSC, permit the changes in fair value of natural gas derivatives to be recorded as regulatory assets or liabilities
reflecting the impact of hedging activities on the fuel recovery clause. As a result, these changes are not recorded in OCI (see Note 3). 

TEC’s physical contracts qualify for the NPNS exception to
derivative accounting rules, provided they meet certain criteria. Generally, NPNS applies if TEC deems the counterparty creditworthy, if the counterparty owns or controls resources within the proximity to allow for physical delivery of the
commodity, if TEC intends to receive physical delivery and if the transaction is reasonable in relation to TEC’s business needs. As of Dec. 31, 2015, all of TEC’s physical contracts qualify for the NPNS exception. 

The derivatives that are designated as cash flow hedges at Dec.
31, 2015 and 2014 are reflected on TEC’s Consolidated Balance Sheets and classified accordingly as current and long term assets and liabilities on a net basis as permitted by their respective master netting agreements. There were no derivative
assets as of Dec. 31, 2015 and 2014. Derivative liabilities totaled $26.2 million and $42.7 million as of Dec. 31, 2015 and 2014, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net
amounts presented on the Consolidated Balance Sheets. There was no collateral posted with or received from any counterparties. 

All of the derivative asset and liabilities at Dec. 31, 2015 and
2014 are designated as hedging instruments, which primarily are derivative hedges of natural gas contracts to limit the exposure to changes in market price for natural gas used to produce energy and natural gas purchased for resale to customers. The
corresponding effect of these natural gas related derivatives on the regulated utilities’ fuel recovery clause mechanism is reflected on the Consolidated Balance Sheets as current and long term regulatory assets and liabilities. Based on the
fair value of the instruments at Dec. 31, 2015, net pretax losses of $24.1 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Statements of Income within the next twelve months. 

The Dec. 31, 2015 and 2014 balance in AOCI related to the cash
flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 8. 

155


 For derivative instruments that meet cash flow hedge criteria, the effective portion of the gain or loss on the
derivative is reported as a component of OCI and reclassified into earnings in the same period or period
during which the hedged transaction affects earnings. Gains and losses on the derivatives representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings. For the years ended Dec. 31, 2015, 2014 and 2013, all hedges were effective. The derivative after-tax effect on OCI and the amount of after-tax gain or loss
reclassified from AOCI into earnings for the years ended Dec. 31, 2015, 2014 and 2013 is presented in Note 8. Gains and losses were the result of interest rate contracts and the reclassifications to income were reflected in
Interest expense. 

The maximum length of time over which TEC is hedging its
exposure to the variability in future cash flows extends to Nov. 30, 2017 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Dec. 31, 2015, are expected to settle during the 2016 and 2017
fiscal years: 
  
 
	
 
	
 
	
Natural Gas
Contracts
	
 

	
(millions)
	
 
	
(MMBTUs)
	
 

	
Year
	
 
	
Physical
	
 
	
 
	
Financial
	
 

	
2016
	
 
	
 
	
0.0
	
 
	
 
	
 
	
27.6
	
 

	
2017
	
 
	
 
	
0.0
	
 
	
 
	
 
	
5.0
	
 

	
Total
	
 
	
 
	
0.0
	
 
	
 
	
 
	
32.6
	
 




TEC is exposed to credit risk by entering into derivative
instruments with counterparties to limit its exposure to the commodity price fluctuations associated with natural gas. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. TEC manages credit risk
with policies and procedures for, among other things, counterparty analysis, exposure measurement and exposure monitoring and mitigation. 

It is possible that volatility in commodity prices could cause
TEC to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, TEC could suffer a material financial loss. However, as of Dec. 31, 2015,
substantially all of the counterparties with transaction amounts outstanding in TEC’s energy portfolio were rated investment grade by the major rating agencies. TEC assesses credit risk internally for counterparties that are not rated. 

TEC has entered into commodity master arrangements with its
counterparties to mitigate credit exposure to those counterparties. TEC generally enters into the following master arrangements: (1) EEI agreements—standardized power sales contracts in the electric industry; (2) ISDA
agreements—standardized financial gas and electric contracts; and (3) NAESB agreements—standardized physical gas contracts. TEC believes that entering into such agreements reduces the risk from default by creating contractual rights
relating to creditworthiness, collateral and termination. 

TEC has implemented procedures to monitor the creditworthiness of
its counterparties and to consider nonperformance risk in determining the fair value of counterparty positions. Net liability positions generally do not require a nonperformance risk adjustment as TEC uses derivative transactions as hedges and has
the ability and intent to perform under each of these contracts. In the instance of net asset positions, TEC considers general market conditions and the observable financial health and outlook of specific counterparties in evaluating the potential
impact of nonperformance risk to derivative positions. 

Certain TEC derivative instruments contain provisions that
require TEC’s debt to maintain an investment grade credit rating from any or all of the major credit rating agencies. If debt ratings were to fall below investment grade, it could trigger these provisions, and the counterparties to the
derivative instruments could demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. TEC has no other contingent risk features associated with any derivative instruments.  

 
  

14. Fair Value Measurements 

Items Measured at Fair Value on a Recurring Basis 

Accounting guidance governing fair value measurements and
disclosures provides that fair value represents the amount that would be received in selling an asset or the amount that would be paid in transferring a liability in an orderly transaction between market participants. As such, fair value is a
market-based measurement that is determined based upon assumptions that market participants would use in pricing an asset or liability. As a basis for considering such assumptions, accounting guidance also establishes a three-tier fair value
hierarchy, which prioritizes the inputs used in measuring fair value as follows: 
 
	  
	 Level 1:
	 Observable inputs, such as quoted prices in active
markets;



 
	  
	 Level 2:
	 Inputs, other than quoted prices in active markets, that are
observable either directly or indirectly; and



 
	  
	 Level 3:
	 Unobservable inputs for which there is little or no market data,
which require the reporting entity to develop its own assumptions.




156


 Assets and liabilities are measured at fair value based on one or more of the following three valuation techniques
noted under accounting guidance: 
 
	  
	 (A)
	 Market approach: Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities; 



 
	  
	 (B)
	 Cost approach: Amount that would be required to replace the service capacity of an asset (replacement cost); and 



 
	  
	 (C)
	 Income approach: Techniques to convert future amounts to a single present amount based upon market expectations (including present value techniques, option-pricing and excess earnings models). 




The fair value of financial instruments is determined by using
various market data and other valuation techniques. 
 The
following table sets forth by level within the fair value hierarchy TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Dec. 31, 2015 and 2014. As required by accounting standards for fair
value measurements, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. TEC’s assessment of the significance of a particular input to the fair
value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  

Recurring Derivative Fair Value Measures

 
 
	
 
	
 
	
As of Dec. 31,
2015
	
 

	
(millions)
	
 
	
Level 
1
	
 
	
 
	
Level 
2
	
 
	
 
	
Level 
3
	
 
	
 
	
Total
	
 

	
Liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Natural gas swaps
	
 
	
$
	
0.0
	
 
	
 
	
$
	
26.2
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
26.2
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
As of Dec. 31,
2014
	
 

	
(millions)
	
 
	
Level 
1
	
 
	
 
	
Level 
2
	
 
	
 
	
Level 
3
	
 
	
 
	
Total
	
 

	
Liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Natural gas swaps
	
 
	
$
	
0.0
	
 
	
 
	
$
	
42.7
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
42.7
	
 




Natural gas swaps are OTC swap instruments. The fair value of
the swaps is estimated utilizing the market approach. The price of swaps is calculated using observable NYMEX quoted closing prices of exchange-traded futures. These prices are applied to the notional quantities of active positions to determine the
reported fair value (see Note 13). 

TEC considered the impact of nonperformance risk in determining
the fair value of derivatives. TEC considered the net position with each counterparty, past performance of both parties, the intent of the parties, indications of credit deterioration and whether the markets in which TEC transacts have
experienced dislocation. At Dec. 31, 2015, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

 
  

15. Variable Interest Entities 

The determination of a VIE’s primary beneficiary is the
enterprise that has both 1) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses of the entity that could potentially be significant to the VIE or
the right to receive benefits from the entity that could potentially be significant to the VIE. 

Tampa Electric has entered into multiple PPAs with wholesale
energy providers in Florida to ensure the ability to meet customer energy demand and to provide lower cost options in the meeting of this demand. These agreements range in size from 117 MW to 157 MW of available capacity, are with similar entities
and contain similar provisions. Because some of these provisions provide for the transfer or sharing of a number of risks inherent in the generation of energy, these agreements meet the definition of being variable interests. These risks include:
operating and maintenance, regulatory, credit, commodity/fuel and energy market risk. Tampa Electric has reviewed these risks and has determined that the owners of these entities have retained the majority of these risks over the expected life of
the underlying generating assets, have the power to direct the most significant activities, and have the obligation or right to absorb losses or benefits and hence remain the primary beneficiaries. As a result, Tampa Electric is not required to
consolidate any of these entities. Tampa Electric purchased $33.6 million, $25.7 million and $22.1 million, under these PPAs for the three years ended Dec. 31, 2015, 2014 and 2013, respectively. 

TEC does not provide any material financial or other support to
any of the VIEs it is involved with, nor is TEC under any obligation to absorb losses associated with these VIEs. In the normal course of business, TEC’s involvement with these VIEs does not affect its Consolidated Balance Sheets, Statements
of Income or Cash Flows. 
  

157


 16. Mergers and Acquisitions

Pending Merger with Emera Inc.

On Sept. 4, 2015, TECO Energy and Emera entered into the
Merger Agreement. Upon closing of the Merger, TECO Energy will become a wholly owned indirect subsidiary of Emera. 

Upon the terms and subject to the conditions set forth in the
Merger Agreement, which was unanimously approved and adopted by the board of directors of TECO Energy, at the effective time, Merger Sub will merge with and into TECO Energy with TECO Energy continuing as the surviving corporation. 

Pursuant to the Merger Agreement, upon the closing of the Merger,
which is expected to occur in the summer of 2016, each issued and outstanding share of TECO Energy common stock will be cancelled and converted automatically into the right to receive $27.55 in cash, without interest (Merger Consideration). This
represents an aggregate purchase price of approximately $10.4 billion including assumption of approximately $3.9 billion of debt (of which TEC’s portion of debt was $2.3 billion). 

The closing of the Merger is subject to certain conditions,
including, among others, (i) approval of TECO Energy shareholders representing a majority of the outstanding shares of TECO Energy common stock (which approval was obtained at the special meeting of shareholders held on Dec. 3, 2015),
(ii) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period (which expired on Feb. 5, 2016), (iii) receipt of all required regulatory approvals, including from the FERC, the NMPRC and the Committee on Foreign
Investment in the United States (which, with respect to the FERC, was obtained on Jan. 20, 2016), (iv) the absence of any law or judgment that prevents, makes illegal or prohibits the closing of the Merger, (v) the absence of any material
adverse effect with respect to TECO Energy and (vi) subject to certain exceptions, the accuracy of the representations and warranties of, and compliance with covenants by, each of the parties to the Merger Agreement. 

TECO Energy is also subject to a “no shop”
restriction that limits its ability to solicit alternative acquisition proposals or provide nonpublic information to, and engage in discussion with, third parties. 

The Merger Agreement contains certain termination rights for both
TECO Energy and Emera. Either party may terminate the Merger Agreement if (i) the closing of the Merger has not occurred by Sept. 30, 2016 (subject to a 6-month extension if required to obtain necessary regulatory approvals), (ii) a
law or judgment preventing or prohibiting the closing of the Merger has become final, (iii) TECO Energy’s shareholders do not approve the Merger or (iv) TECO Energy’s board of directors changes its recommendation so that it is
no longer in favor of the Merger. If either party terminates the Merger Agreement because TECO Energy’s board of directors changes its recommendation, TECO Energy must pay Emera a termination fee of $212.5 million. If the Merger Agreement is
terminated under certain other circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million.

 
  

 

158