EX-4.9


  Exhibit 4.9

 

PART I. FINANCIAL INFORMATION 
  

Item 1. CONSOLIDATED
CONDENSED FINANCIAL STATEMENTS
  

4


 
TECO ENERGY, INC. 


Consolidated Condensed Balance Sheets 

Unaudited 

 
 
	
Assets
	
Mar. 31,
	
 
	
 
	
Dec. 31,
	
 

	
(millions)
	
2016
	
 
	
 
	
2015
	
 

	
Current assets
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Cash and cash
equivalents
	
$
	
46.1
	
 
	
 
	
$
	
23.8
	
 

	
Receivables, less allowance for
uncollectibles of $2.1 and $2.1

   at Mar. 31, 2016
and Dec. 31, 2015, respectively
	
 
	
240.1
	
 
	
 
	
 
	
280.7
	
 

	
Inventories, at average
cost
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Fuel
	
118.3
	
 
	
 
	
113.4
	
 

	
Materials and supplies
	
 
	
77.1
	
 
	
 
	
 
	
76.8
	
 

	
Regulatory assets
	
 
	
40.2
	
 
	
 
	
 
	
44.8
	
 

	
Prepayments and other current
assets
	
 
	
25.4
	
 
	
 
	
 
	
30.8
	
 

	
Total current assets
	
 
	
547.2
	
 
	
 
	
 
	
570.3
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Property, plant and
equipment
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Utility plant in
service
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Electric
	
 
	
7,328.3
	
 
	
 
	
 
	
7,270.3
	
 

	
Gas
	
 
	
2,154.1
	
 
	
 
	
 
	
2,113.8
	
 

	
Construction work in
progress
	
 
	
816.9
	
 
	
 
	
 
	
794.7
	
 

	
Other property
	
 
	
16.1
	
 
	
 
	
 
	
15.9
	
 

	
Property, plant and equipment,
at original costs
	
 
	
10,315.4
	
 
	
 
	
 
	
10,194.7
	
 

	
Accumulated
depreciation
	
 
	
(2,762.4
	
)
	
 
	
 
	
(2,712.9
	
)

	
Total property, plant and
equipment, net
	
 
	
7,553.0
	
 
	
 
	
 
	
7,481.8
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Other assets
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulatory assets
	
 
	
393.4
	
 
	
 
	
 
	
395.2
	
 

	
Goodwill
	
 
	
408.4
	
 
	
 
	
 
	
408.4
	
 

	
Deferred charges and other
assets
	
 
	
79.1
	
 
	
 
	
 
	
77.8
	
 

	
Total other assets
	
 
	
880.9
	
 
	
 
	
 
	
881.4
	
 

	
Total assets
	
$
	
8,981.1
	
 
	
 
	
$
	
8,933.5
	
 




 

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

5


 
 TECO ENERGY, INC. 

Consolidated Condensed Balance Sheets -
continued
 Unaudited 

 
 
	
Liabilities and Capital
	
Mar. 31,
	
 
	
 
	
Dec. 31,
	
 

	
(millions)
	
2016
	
 
	
 
	
2015
	
 

	
Current liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Long-term debt due within one
year
	
$
	
83.3
	
 
	
 
	
$
	
333.3
	
 

	
Notes payable
	
 
	
513.0
	
 
	
 
	
 
	
247.0
	
 

	
Accounts payable
	
 
	
189.5
	
 
	
 
	
 
	
255.4
	
 

	
Customer deposits
	
 
	
176.7
	
 
	
 
	
 
	
182.1
	
 

	
Regulatory liabilities
	
 
	
108.4
	
 
	
 
	
 
	
84.8
	
 

	
Derivative liabilities
	
 
	
22.3
	
 
	
 
	
 
	
24.1
	
 

	
Interest accrued
	
 
	
54.0
	
 
	
 
	
 
	
36.2
	
 

	
Taxes accrued
	
 
	
28.2
	
 
	
 
	
 
	
13.2
	
 

	
Other
	
 
	
25.2
	
 
	
 
	
 
	
22.6
	
 

	
Total current
liabilities
	
 
	
1,200.6
	
 
	
 
	
 
	
1,198.7
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Other liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Deferred income taxes
	
 
	
607.0
	
 
	
 
	
 
	
570.7
	
 

	
Investment tax credits
	
 
	
10.4
	
 
	
 
	
 
	
10.5
	
 

	
Regulatory liabilities
	
 
	
709.4
	
 
	
 
	
 
	
715.8
	
 

	
Derivative liabilities
	
 
	
0.8
	
 
	
 
	
 
	
2.1
	
 

	
Deferred credits and other
liabilities
	
 
	
380.9
	
 
	
 
	
 
	
387.5
	
 

	
Long-term debt, less amount due
within one year
	
 
	
3,489.7
	
 
	
 
	
 
	
3,489.2
	
 

	
Total other
liabilities
	
 
	
5,198.2
	
 
	
 
	
 
	
5,175.8
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Commitments and contingencies (see
Note 10)
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Capital
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Common equity (400.0 million
shares authorized; par value $1; 235.5 million

   and 235.3 million
shares outstanding at Mar. 31, 2016 and Dec. 31, 2015,

  
respectively)
	
 
	
235.5
	
 
	
 
	
 
	
235.3
	
 

	
Additional paid in
capital
	
 
	
1,894.8
	
 
	
 
	
 
	
1,894.5
	
 

	
Retained earnings
	
 
	
463.5
	
 
	
 
	
 
	
441.4
	
 

	
Accumulated other comprehensive
loss
	
 
	
(11.5
	
)
	
 
	
 
	
(12.2
	
)

	
Total capital
	
 
	
2,582.3
	
 
	
 
	
 
	
2,559.0
	
 

	
Total liabilities and
capital
	
$
	
8,981.1
	
 
	
 
	
$
	
8,933.5
	
 




 

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

6


 
TECO ENERGY, INC. 

Consolidated Condensed Statements of Income 

Unaudited 

 
 
	
 
	
 
	
 
	
Three months ended
Mar. 31,
	
 

	
(millions, except per share amounts)
	
 
	
 
	
2016
	
 
	
 
	
2015
	
 

	
Revenues
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulated electric
	
 
	
 
	
$
	
423.4
	
 
	
 
	
$
	
449.7
	
 

	
Regulated gas
	
 
	
 
	
 
	
232.9
	
 
	
 
	
 
	
240.2
	
 

	
Unregulated
	
 
	
 
	
 
	
3.2
	
 
	
 
	
 
	
3.1
	
 

	
Total revenues
	
 
	
 
	
 
	
659.5
	
 
	
 
	
 
	
693.0
	
 

	
Expenses
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulated operations and
maintenance
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Fuel
	
 
	
 
	
 
	
115.2
	
 
	
 
	
 
	
144.1
	
 

	
Purchased power
	
 
	
 
	
 
	
14.4
	
 
	
 
	
 
	
17.1
	
 

	
Cost of natural gas
sold
	
 
	
 
	
 
	
96.8
	
 
	
 
	
 
	
103.0
	
 

	
Other
	
 
	
 
	
 
	
142.3
	
 
	
 
	
 
	
143.7
	
 

	
Operation and maintenance other
expense
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.6
	
 

	
Depreciation and
amortization
	
 
	
 
	
 
	
89.8
	
 
	
 
	
 
	
85.5
	
 

	
Taxes, other than
income
	
 
	
 
	
 
	
52.9
	
 
	
 
	
 
	
51.8
	
 

	
Total expenses
	
 
	
 
	
 
	
511.4
	
 
	
 
	
 
	
546.8
	
 

	
Income from operations
	
 
	
 
	
 
	
148.1
	
 
	
 
	
 
	
146.2
	
 

	
Other income
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Allowance for other funds used
during construction
	
 
	
 
	
 
	
5.7
	
 
	
 
	
 
	
3.8
	
 

	
Other income, net
	
 
	
 
	
 
	
1.5
	
 
	
 
	
 
	
1.6
	
 

	
Total other income
	
 
	
 
	
 
	
7.2
	
 
	
 
	
 
	
5.4
	
 

	
Interest charges
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Interest expense
	
 
	
 
	
 
	
48.9
	
 
	
 
	
 
	
49.8
	
 

	
Allowance for borrowed funds
used during construction
	
 
	
 
	
 
	
(3.0
	
)
	
 
	
 
	
(1.9
	
)

	
Total interest charges
	
 
	
 
	
 
	
45.9
	
 
	
 
	
 
	
47.9
	
 

	
Income from continuing operations
before provision for
   
income taxes
	
 
	
 
	
 
	
109.4
	
 
	
 
	
 
	
103.7
	
 

	
Provision for income
taxes
	
 
	
 
	
 
	
35.7
	
 
	
 
	
 
	
39.9
	
 

	
Net income from continuing
operations
	
 
	
 
	
 
	
73.7
	
 
	
 
	
 
	
63.8
	
 

	
Discontinued operations
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Income (loss) from discontinued
operations
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
(9.6
	
)

	
Provision (benefit) from income
taxes
	
 
	
 
	
 
	
0.1
	
 
	
 
	
 
	
(3.8
	
)

	
Income (loss) from discontinued
operations, net
	
 
	
 
	
 
	
0.1
	
 
	
 
	
 
	
(5.8
	
)

	
Net income
	
 
	
 
	
$
	
73.8
	
 
	
 
	
$
	
58.0
	
 

	
Average common shares
outstanding
	
– Basic
	
 
	
 
	
234.0
	
 
	
 
	
 
	
232.8
	
 

	
 
	
– Diluted
	
 
	
 
	
235.2
	
 
	
 
	
 
	
233.5
	
 

	
Earnings per share from continuing
operations
	
– Basic
	
 
	
$
	
0.31
	
 
	
 
	
$
	
0.27
	
 

	
 
	
– Diluted
	
 
	
$
	
0.31
	
 
	
 
	
$
	
0.27
	
 

	
Earnings per share from discontinued
operations
	
– Basic
	
 
	
$
	
0.00
	
 
	
 
	
$
	
(0.02
	
)

	
 
	
– Diluted
	
 
	
$
	
0.00
	
 
	
 
	
$
	
(0.02
	
)

	
Earnings per share
	
– Basic
	
 
	
$
	
0.31
	
 
	
 
	
$
	
0.25
	
 

	
 
	
– Diluted
	
 
	
$
	
0.31
	
 
	
 
	
$
	
0.25
	
 

	
Dividends paid per common share
outstanding
	
 
	
 
	
$
	
0.230
	
 
	
 
	
$
	
0.225
	
 




 

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


7


  

TECO ENERGY, INC. 


Consolidated Condensed Statements of Comprehensive Income 

Unaudited 

 

 
 
	
 
	
Three months ended
Mar. 31,
	
 

	
(millions)
	
2016
	
 
	
 
	
2015
	
 

	
Net income
	
$
	
73.8
	
 
	
 
	
$
	
58.0
	
 

	
Other comprehensive income, net of
tax
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Gain on cash flow
hedges
	
 
	
0.2
	
 
	
 
	
 
	
0.3
	
 

	
Amortization of unrecognized
benefit costs
	
 
	
0.5
	
 
	
 
	
 
	
0.6
	
 

	
Other comprehensive income, net
of tax
	
 
	
0.7
	
 
	
 
	
 
	
0.9
	
 

	
Comprehensive income
	
$
	
74.5
	
 
	
 
	
$
	
58.9
	
 




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

 
  

8


 
TECO ENERGY, INC. 

Consolidated
 Condensed Statements of Cash Flows 
 Unaudited

  
 
	
 
	
Three months ended
Mar. 31,
	
 

	
(millions)
	
2016
	
 
	
 
	
2015
	
 

	
Cash flows from operating
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net income
	
$
	
73.8
	
 
	
 
	
$
	
58.0
	
 

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

	
Depreciation and
amortization
	
 
	
89.8
	
 
	
 
	
 
	
85.9
	
 

	
Deferred income taxes and
investment tax credits
	
 
	
36.1
	
 
	
 
	
 
	
36.0
	
 

	
Allowance for other funds used
during construction
	
 
	
(5.7
	
)
	
 
	
 
	
(3.8
	
)

	
Non-cash stock
compensation
	
 
	
3.0
	
 
	
 
	
 
	
3.9
	
 

	
Deferred recovery
clauses
	
 
	
26.4
	
 
	
 
	
 
	
(5.7
	
)

	
Receivables, less allowance for
uncollectibles
	
 
	
40.6
	
 
	
 
	
 
	
51.0
	
 

	
Inventories
	
 
	
(5.2
	
)
	
 
	
 
	
(15.7
	
)

	
Prepayments and other current
assets
	
 
	
2.8
	
 
	
 
	
 
	
(10.9
	
)

	
Taxes accrued
	
 
	
18.1
	
 
	
 
	
 
	
1.7
	
 

	
Interest accrued
	
 
	
17.8
	
 
	
 
	
 
	
17.8
	
 

	
Accounts payable
	
 
	
(59.1
	
)
	
 
	
 
	
(63.5
	
)

	
Other
	
 
	
(6.8
	
)
	
 
	
 
	
(7.7
	
)

	
Cash flows from operating
activities
	
 
	
231.6
	
 
	
 
	
 
	
147.0
	
 

	
Cash flows from investing
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Capital expenditures
	
 
	
(168.0
	
)
	
 
	
 
	
(156.2
	
)

	
Other investing
activities
	
 
	
(0.2
	
)
	
 
	
 
	
(0.2
	
)

	
Cash flows used in investing
activities
	
 
	
(168.2
	
)
	
 
	
 
	
(156.4
	
)

	
Cash flows from financing
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Dividends and dividend
equivalents
	
 
	
(54.3
	
)
	
 
	
 
	
(53.0
	
)

	
Proceeds from the sale of
common stock
	
 
	
3.9
	
 
	
 
	
 
	
2.8
	
 

	
Repayment of long-term
debt/purchase in lieu of redemption
	
 
	
(250.0
	
)
	
 
	
 
	
0.0
	
 

	
Net increase (decrease) in
short-term debt (maturities of 90 days or less)
	
 
	
(134.0
	
)
	
 
	
 
	
67.0
	
 

	
Proceeds from other short-term
debt (maturities over 90 days)
	
 
	
400.0
	
 
	
 
	
 
	
0.0
	
 

	
Other financing
activities
	
 
	
(6.7
	
)
	
 
	
 
	
0.0
	
 

	
Cash flows from (used in)
financing activities
	
 
	
(41.1
	
)
	
 
	
 
	
16.8
	
 

	
Net increase in cash and cash
equivalents
	
 
	
22.3
	
 
	
 
	
 
	
7.4
	
 

	
Cash and cash equivalents at
beginning of the period
	
 
	
23.8
	
 
	
 
	
 
	
25.4
	
 

	
Cash and cash equivalents at end of
the period
	
$
	
46.1
	
 
	
 
	
$
	
32.8
	
 

	
Supplemental disclosure of non-cash
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Change in accrued capital
expenditures
	
$
	
(6.0
	
)
	
 
	
$
	
11.5
	
 




 

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

 
  




9


  

TECO ENERGY, INC. 


NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS 

UNAUDITED 

 

1. Summary of Significant Accounting Policies 

See TECO Energy, Inc.’s 2015 Annual Report on
Form 10-K for a complete discussion of the company’s accounting policies. The significant accounting policies for all utility and diversified operations include: 

Principles of Consolidation and Basis of Presentation 

Intercompany balances and intercompany transactions have been
eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TECO Energy, Inc. and
its subsidiaries as of Mar. 31, 2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Mar. 31, 2016 and 2015. The results of operations for the three months ended Mar. 31, 2016 are not necessarily indicative of
the results that can be expected for the entire fiscal year ending Dec. 31, 2016. 

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. The year-end consolidated condensed balance sheet data was derived from audited financial statements; however, this quarterly report on Form 10-Q does not
include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP. 

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 16 for further information.

Revenues 

As of Mar. 31, 2016 and Dec. 31, 2015, unbilled revenues of $67.3
million and $81.1 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets. 

Accounting for Franchise Fees and Gross Receipt Taxes 

Tampa Electric and PGS are allowed to recover certain costs from
customers on a dollar-per-dollar basis 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 Condensed Statements of Income.
Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.9 million and $27.4 million
for the three months ended Mar. 31, 2016 and 2015, 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 Condensed Statements of
Income.
  

2. New Accounting Pronouncements 

Change in Accounting Policy

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 became effective for the company beginning in 2016 and is required to be applied on a retrospective basis for all periods presented. As of Mar. 31, 2016 and Dec. 31, 2015, the company
classified $26.4 million and $27.7 million, respectively, of debt issuance costs, which do not include costs for line-of-credit arrangements, as a deduction in the “Long-term debt, less amount due within one year” line item on the
company’s Consolidated Condensed Balance Sheet (previously classified in the “Deferred charges and other assets” line item). The guidance did not affect the company’s results of operations or cash flows.

 

Stock Compensation

In March 2016, the FASB issued guidance regarding employee
share-based payment accounting. The guidance simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, accounting for forfeitures, classification of awards as either equity or
liability, and presentation on the statement of cash flows. This guidance will be required for the company beginning in 2017. As early adoption is permitted, the company adopted the standard as of Jan. 1, 2016. Each aspect has an accounting impact
and was implemented as follows: 
 10


 
	  
	 ·
	 Income tax consequences – Under the new guidance, the company will no longer recognize excess tax benefits and certain tax deficiencies in
additional paid in capital. Instead, the company will recognize all excess tax benefits and tax
deficiencies as income tax expense or benefit on the income statement. In addition, the guidance eliminates the requirement that excess tax benefits be realized before the company can recognize
them. Accordingly, the company recorded a $2.6
million cumulative adjustment to retained earnings as of Jan. 1, 2016 for excess tax benefits related to prior periods. In accordance with the new guidance, the company will no longer include excess tax benefits and tax deficiencies in the dilutive EPS calculation on a prospective basis. 



 
	  
	 ·
	 Accounting for forfeitures – The
company’s policy is to estimate the number of awards expected to be forfeited, which is consistent with prior periods.



 
	  
	 ·
	 Classification of awards - The company had no
share-based payments classified as liability awards as of Mar. 31, 2016 or Dec. 31, 2015.  



 
	  
	 ·
	 Presentation on the statement of cash flows
– Excess tax benefits are required to be presented as an operating activity on the statement of cash flows rather than as a financing activity. The change may be applied retrospectively or prospectively. The company elected to apply it
prospectively, and prior periods were not retrospectively adjusted. Additionally, employee taxes paid by an employer to a tax authority when shares are withheld for tax-withholding purposes are required to be presented as a financing activity on a
retrospective basis for all periods presented. Previously, the company presented it as an operating activity. There was an immaterial amount of activity that did not result in an adjustment to the statement of cash flows for the three months ended
Mar. 31, 2015.



  

Future 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. 
  

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. Under the existing guidance,
operating leases are not recorded as lease assets and lease liabilities on the balance sheet. Recognition of expenses for both operating and finance leases will be similar to existing guidance and as a result is expected to limit the impact of the
changes on the income statement and statement of cash flows. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. 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.

Derivative Contract Novations

In March 2016, the FASB issued guidance clarifying that a change
in the counterparty to a derivative contract, in and of itself, does not require the dedesignation of a hedging relationship provided that all other hedge accounting criteria continue to be met. The guidance is effective for the company beginning in
2017, with early adoption permitted, and may be applied on a prospective or modified retrospective basis. The guidance will not affect the company’s current financial statements. However, the company will assess the impact of this guidance on
future derivative contract novations, if any.
  

11


 
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 requirement) 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. 
  

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. 

Details of the regulatory assets and liabilities as of Mar. 31,
2016 and Dec. 31, 2015 are presented in the following table: 

 
 
	
Regulatory Assets and Liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
Mar. 31,
2016
	
 
	
 
	
Dec. 31,
2015
	
 

	
Regulatory assets:
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulatory tax asset (1)
	
$
	
77.1
	
 
	
 
	
$
	
74.7
	
 

	
Cost-recovery clauses - deferred
balances (2)
	
 
	
0.1
	
 
	
 
	
 
	
5.5
	
 

	
Cost-recovery clauses - offsets
to derivative liabilities (2)
	
 
	
26.0
	
 
	
 
	
 
	
26.5
	
 

	
Environmental remediation (3)
	
 
	
54.4
	
 
	
 
	
 
	
54.0
	
 

	
Postretirement benefits (4)
	
 
	
238.5
	
 
	
 
	
 
	
240.6
	
 

	
Deferred bond refinancing costs (5)
	
 
	
6.2
	
 
	
 
	
 
	
6.5
	
 

	
Debt basis adjustment (6)
	
 
	
16.7
	
 
	
 
	
 
	
17.5
	
 

	
Competitive rate adjustment (2)
	
 
	
2.5
	
 
	
 
	
 
	
2.6
	
 

	
Other
	
 
	
12.1
	
 
	
 
	
 
	
12.1
	
 

	
Total regulatory assets
	
 
	
433.6
	
 
	
 
	
 
	
440.0
	
 

	
Less: Current portion
	
 
	
40.2
	
 
	
 
	
 
	
44.8
	
 

	
Long-term regulatory
assets
	
$
	
393.4
	
 
	
 
	
$
	
395.2
	
 

	
Regulatory liabilities:
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulatory tax
liability
	
$
	
7.6
	
 
	
 
	
$
	
7.9
	
 

	
Cost-recovery clauses (2)
	
 
	
80.0
	
 
	
 
	
 
	
55.9
	
 

	
Transmission and delivery storm
reserve
	
 
	
56.1
	
 
	
 
	
 
	
56.1
	
 

	
Accumulated reserve - cost of
removal (7)
	
 
	
673.6
	
 
	
 
	
 
	
679.9
	
 

	
Other
	
 
	
0.5
	
 
	
 
	
 
	
0.8
	
 

	
Total regulatory
liabilities
	
 
	
817.8
	
 
	
 
	
 
	
800.6
	
 

	
Less: Current portion
	
 
	
108.4
	
 
	
 
	
 
	
84.8
	
 

	
Long-term regulatory
liabilities
	
$
	
709.4
	
 
	
 
	
$
	
715.8
	
 




 
 
	 (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.




12


 
	 (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 

The effective tax rate decreased to 32.63% for the three months
ended Mar. 31, 2016 from 38.48% for the same period in 2015 primarily due to the tax benefit related to long-term incentive compensation share vestings (see Note 2 for further description).

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 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. TECO Energy does not expect the settlement of audit
examinations to significantly change the total amount of unrecognized tax benefits by the end of 2016. 

 
  

5. Employee Postretirement Benefits 

Included in the table below is the periodic expense for pension
and other postretirement benefits offered by the company. Amounts disclosed for pension benefits include the amounts related to the qualified pension plan and the non-qualified, non-contributory SERP.

 
 
	
Pension Expense
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
Pension
Benefits
	
 
	
 
	
Other
Postretirement Benefits
	
 

	
Three months ended Mar. 31,
	
2016
	
 
	
 
	
2015
	
 
	
 
	
2016
	
 
	
 
	
2015
	
 

	
Components of net periodic benefit
expense
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Service cost
	
$
	
4.4
	
 
	
 
	
$
	
4.5
	
 
	
 
	
$
	
0.5
	
 
	
 
	
$
	
0.6
	
 

	
Interest cost
	
 
	
8.1
	
 
	
 
	
 
	
7.4
	
 
	
 
	
 
	
2.2
	
 
	
 
	
 
	
2.0
	
 

	
Expected return on assets
	
 
	
(11.3
	
)
	
 
	
 
	
(10.8
	
)
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
(0.3
	
)

	
Amortization of:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Prior service (benefit)
cost
	
 
	
0.0
	
 
	
 
	
 
	
(0.1
	
)
	
 
	
 
	
(0.6
	
)
	
 
	
 
	
(0.6
	
)

	
Actuarial loss
	
 
	
3.4
	
 
	
 
	
 
	
3.4
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Regulatory asset
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
0.3
	
 

	
Net pension expense recognized in
the
    TECO Energy
Consolidated Condensed Statements of Income
	
$
	
4.6
	
 
	
 
	
$
	
4.4
	
 
	
 
	
$
	
2.0
	
 
	
 
	
$
	
2.0
	
 




For the fiscal 2016 plan year, TECO Energy is using an assumed
long-term EROA of 7.00% and a discount rate of 4.685% for pension benefits under its qualified pension plan. For the Jan. 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy assumed a discount rate of 4.667% for the
Florida-based plan and 4.687% for the NMGC plan. Additionally, TECO Energy made contributions of $4.7 million and $14.9 million to its pension plan for the three months ended Mar. 31, 2016 and 2015, respectively.

For the three months ended Mar. 31, 2016 and 2015, TECO Energy
and its subsidiaries reclassified $0.8 million of pretax unamortized prior service benefit and actuarial losses from AOCI to net income as part of periodic benefit expense. In addition, during the three months ended Mar. 31, 2016 and 2015, the
regulated companies reclassified $2.2 million of unamortized prior service benefit and actuarial losses from regulatory assets to net income as part of periodic benefit expense. 

13


  

6. Short-Term Debt 

At Mar. 31, 2016 and Dec. 31, 2015, the following credit
facilities and related borrowings existed: 
  
 
	
Credit Facilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
Mar. 31,
2016
	
 
	
 
	
Dec. 31,
2015
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
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
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.5
	
 

	
3-year accounts

   receivable facility
(3)
	
 
	
150.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
150.0
	
 
	
 
	
 
	
61.0
	
 
	
 
	
 
	
0.0
	
 

	
TECO Energy/TECO Finance:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
5-year facility (2)(4)
	
 
	
300.0
	
 
	
 
	
 
	
113.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
300.0
	
 
	
 
	
 
	
163.0
	
 
	
 
	
 
	
0.0
	
 

	
1-year term facility (4)(5)
	
 
	
400.0
	
 
	
 
	
 
	
400.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
New Mexico Gas Company:
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
5-year facility (2)
	
 
	
125.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.7
	
 
	
 
	
 
	
125.0
	
 
	
 
	
 
	
23.0
	
 
	
 
	
 
	
1.7
	
 

	
Total
	
$
	
1,300.0
	
 
	
 
	
$
	
513.0
	
 
	
 
	
$
	
2.2
	
 
	
 
	
$
	
900.0
	
 
	
 
	
$
	
247.0
	
 
	
 
	
$
	
2.2
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(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.
	
 

	
(5)     
      This 1-year facility matures Mar. 14, 2017.
	
 



  

At Mar. 31, 2016, these credit facilities required commitment
fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2016 and Dec. 31, 2015 was 1.44% and 1.29%, respectively.  

TECO Energy/TECO Finance Credit Facility

On Mar. 14, 2016, TECO Finance entered into a one-year, $400
million credit agreement. The credit agreement (i) has a maturity date of Mar. 14, 2017; (ii) contains customary representations and warranties, events of default, and financial and other covenants; and
(iii) provides for interest to accrue at variable rates based on the London interbank deposit rate plus a margin, or, as an alternative to such interest rate, 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 one-month London interbank deposit rate plus 1.00%.  

 

7. Long-Term Debt 

Fair Value of Long-Term Debt

At Mar. 31, 2016, total long-term debt had a carrying amount of
$3,573.0 million and an estimated fair market value of $3,879.1 million. At Dec. 31, 2015, total long-term debt had a carrying amount of $3,822.5 million and an estimated fair market value of $4,061.6 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 (see Note 13 for information regarding the
fair value hierarchy). 
 Purchase in Lieu of Redemption of
Revenue Refunding Bonds
 On Mar. 19, 2008, the HCIDA
remarketed $86.0 million HCIDA Pollution Control Revenue Refunding Bonds, Series 2006 (Non-AMT) (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.  On Mar. 15, 2012, TEC purchased in lieu of redemption the Series 2006 HCIDA Bonds. The Series 2006 HCIDA Bonds bore
interest at a term rate of 1.875% per annum from Mar. 15, 2012 to Mar. 15, 2016.  On Mar. 15, 2016, pursuant to the terms of the Loan and Trust Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender
occurred and a term rate of 2.00% per annum will apply from Mar. 15, 2016 to Mar. 15, 2020. The 2016 mandatory tender did not impact the Consolidated Condensed Balance Sheet. 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.

14


  

As of Mar. 31, 2016, $232.6 million of bonds purchased in lieu of
redemption, including the Series 2006 HCIDA Bonds described above, were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

 
  

8. Other Comprehensive Income

TECO Energy reported the following OCI for the three months ended
Mar. 31, 2016 and 2015 related to changes in the fair value of cash flow hedges and amortization of unrecognized benefit costs associated with the company’s postretirement plans: 

 
 
	
Other Comprehensive Income
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
Three months ended
Mar. 31,
	
 

	
(millions)
	
 
	
Gross
	
 
	
 
	
Tax
	
 
	
 
	
Net
	
 

	
2016
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Unrealized gain on cash flow
hedges
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 

	
Reclassification from AOCI to net
income (1)
	
 
	
 
	
0.3
	
 
	
 
	
 
	
(0.1
	
)
	
 
	
 
	
0.2
	
 

	
Gain on cash flow
hedges
	
 
	
 
	
0.3
	
 
	
 
	
 
	
(0.1
	
)
	
 
	
 
	
0.2
	
 

	
Amortization of unrecognized
benefit costs (2)
	
 
	
 
	
0.8
	
 
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
0.5
	
 

	
Total other comprehensive
income
	
 
	
$
	
1.1
	
 
	
 
	
$
	
(0.4
	
)
	
 
	
$
	
0.7
	
 

	
2015
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Unrealized gain on cash flow
hedges
	
 
	
$
	
0.3
	
 
	
 
	
$
	
(0.2
	
)
	
 
	
$
	
0.1
	
 

	
Reclassification from AOCI to net
income (1)
	
 
	
 
	
0.4
	
 
	
 
	
 
	
(0.2
	
)
	
 
	
 
	
0.2
	
 

	
Gain on cash flow
hedges
	
 
	
 
	
0.7
	
 
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
0.3
	
 

	
Amortization of unrecognized
benefit costs (2)
	
 
	
 
	
0.9
	
 
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
0.6
	
 

	
Total other comprehensive
income
	
 
	
$
	
1.6
	
 
	
 
	
$
	
(0.7
	
)
	
 
	
$
	
0.9
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(1)  Related to
interest rate contracts recognized in Interest expense.
	
 

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




 
 
	
Accumulated Other Comprehensive Loss
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
Mar. 31,
2016
	
 
	
 
	
Dec. 31,
2015
	
 

	
Unamortized pension loss and prior
service credit (1)
	
 
	
$
	
(33.6
	
)
	
 
	
$
	
(34.2
	
)

	
Unamortized other benefit gains,
prior service costs and

   transition obligations
(2)
	
 
	
 
	
25.5
	
 
	
 
	
 
	
25.6
	
 

	
Net unrealized losses from cash
flow hedges (3)
	
 
	
 
	
(3.4
	
)
	
 
	
 
	
(3.6
	
)

	
Total accumulated other
comprehensive loss
	
 
	
$
	
(11.5
	
)
	
 
	
$
	
(12.2
	
)

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(1)  Net of tax benefit
of $21.1 million and $21.5 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.
	
 

	
(2)  Net of tax expense
of $16.0 million and $16.1 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.
	
 

	
(3)  Net of tax benefit
of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.
	
 



 15


  

9. Earnings Per Share 

 
 
	
 
	
For the three
months ended Mar. 31,
	
 

	
(millions, except per share amounts)
	
2016
	
 
	
 
	
2015
	
 

	
Basic earnings per share
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net income from continuing
operations
	
$
	
73.7
	
 
	
 
	
$
	
63.8
	
 

	
Amount allocated to nonvested
participating shareholders
	
 
	
(0.1
	
)
	
 
	
 
	
(0.2
	
)

	
Income before discontinued
operations available to

   common shareholders -
Basic
	
$
	
73.6
	
 
	
 
	
$
	
63.6
	
 

	
Income (loss) from discontinued
operations, net
	
$
	
0.1
	
 
	
 
	
$
	
(5.8
	
)

	
Amount allocated to nonvested
participating shareholders
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Income (loss) from discontinued
operations available to

   common shareholders -
Basic
	
$
	
0.1
	
 
	
 
	
$
	
(5.8
	
)

	
Net income
	
$
	
73.8
	
 
	
 
	
$
	
58.0
	
 

	
Amount allocated to nonvested
participating shareholders
	
 
	
(0.1
	
)
	
 
	
 
	
(0.2
	
)

	
Net income available to common
shareholders - Basic
	
$
	
73.7
	
 
	
 
	
$
	
57.8
	
 

	
Average common shares outstanding -
Basic
	
 
	
234.0
	
 
	
 
	
 
	
232.8
	
 

	
Earnings per share from continuing
operations available to

   common shareholders -
Basic
	
$
	
0.31
	
 
	
 
	
$
	
0.27
	
 

	
Earnings per share from
discontinued operations available to

   common shareholders -
Basic
	
 
	
0.0
	
 
	
 
	
$
	
(0.02
	
)

	
Earnings per share available to
common shareholders - Basic
	
$
	
0.31
	
 
	
 
	
$
	
0.25
	
 

	
Diluted earnings per share
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net income from continuing
operations
	
$
	
73.7
	
 
	
 
	
$
	
63.8
	
 

	
Amount allocated to nonvested
participating shareholders
	
 
	
(0.1
	
)
	
 
	
 
	
(0.2
	
)

	
Income before discontinued
operations available to

   common shareholders -
Diluted
	
$
	
73.6
	
 
	
 
	
$
	
63.6
	
 

	
Income (loss) from discontinued
operations, net
	
$
	
0.1
	
 
	
 
	
$
	
(5.8
	
)

	
Amount allocated to nonvested
participating shareholders
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 

	
Income (loss) from discontinued
operations available to

   common shareholders -
Diluted
	
$
	
0.1
	
 
	
 
	
$
	
(5.8
	
)

	
Net income
	
$
	
73.8
	
 
	
 
	
$
	
58.0
	
 

	
Amount allocated to nonvested
participating shareholders
	
 
	
(0.1
	
)
	
 
	
 
	
(0.2
	
)

	
Net income available to common
shareholders - Diluted
	
$
	
73.7
	
 
	
 
	
$
	
57.8
	
 

	
Unadjusted average common shares
outstanding - Diluted
	
 
	
234.0
	
 
	
 
	
 
	
232.8
	
 

	
Assumed conversion of stock
options, unvested restricted stock,

   unvested RSUs and
contingent performance shares, net
	
 
	
1.2
	
 
	
 
	
 
	
0.7
	
 

	
Average common shares outstanding -
Diluted
	
 
	
235.2
	
 
	
 
	
 
	
233.5
	
 

	
Earnings per share from continuing
operations available to

   common shareholders -
Diluted
	
$
	
0.31
	
 
	
 
	
$
	
0.27
	
 

	
Earnings per share from
discontinued operations available to

   common shareholders -
Diluted
	
 
	
0.0
	
 
	
 
	
$
	
(0.02
	
)

	
Earnings per share available to
common shareholders - Diluted
	
$
	
0.31
	
 
	
 
	
$
	
0.25
	
 

	
Anti-dilutive shares
	
 
	
0.2
	
 
	
 
	
 
	
0.1
	
 




 




16


 
10. 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 not believe that their
ultimate resolution will have a material adverse effect on the company’s results of operations, financial condition or cash flows. 

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 October 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 Mar. 31, 2016.
 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 judgment in favor
of NMGC and all of the subrogation lawsuits were dismissed. The insurance carriers subsequently filed a timely appeal of the summary judgment, which is pending.  

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.  

17


 
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.
  

Claim in connection with the Sale of TECO Coal

As discussed in Note 15,
TECO Coal was sold on Sept. 21, 2015 to Cambrian. On Mar. 18, 2016, Cambrian delivered a notice of a purported claim to TECO Diversified asserting breach of certain representations, and fraud and willful misconduct in connection therewith, of the
SPA.  
  

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. 

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. 

On Apr. 5, 2016, an ICSID ad hoc Committee issued a decision in
favor of TGH in the annulment proceedings. In its decision, the ad hoc Committee unanimously dismissed Guatemala’s application for annulment of the award and upheld the original $21.1 million award, plus interest. In addition, the ad hoc
Committee granted TGH’s application for partial annulment of the award, and ordered Guatemala to pay certain costs relating to the annulment proceedings. Because the Tribunal’s award of costs to TGH in its original arbitration was based
on the Tribunal’s assessment that TGH had prevailed on liability and Guatemala had partially prevailed on damages, and the latter finding was annulled by the ad hoc Committee, the Committee also annulled the Tribunal’s award of costs to
TGH.  As a result, TGH has the right to resubmit its arbitration claim against Guatemala to seek additional damages (in addition to the previously awarded $21.1 million), as well as additional interest on the $21.1 million, and its full
costs relating to the original arbitration and the new arbitration proceeding. Results to date do not reflect any benefit of this decision.

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. On Apr. 18, 2016, PGS reached a settlement regarding this matter with the OPC and FPSC staff and
agreed to pay a $1 million civil penalty and customer refunds of $2 million. The FPSC approved the settlement agreement on May 5, 2016.

 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
Mar. 31, 2016, 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. 

18


 
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. 

Guarantees and Letters of Credit 

A summary of the face amount or maximum theoretical obligation
and the year of expiration under letters of credit and guarantees as of Mar. 31, 2016 is as follows: 

 
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
 
	
 
	
Maximum
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
After (1)
	
 
	
 
	
Theoretical
	
 
	
 
	
Liabilities
Recognized
	
 

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

	
TECO Energy
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

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

	
Letters of indemnity - coal
mining permits (3)
	
 
	
89.4
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
89.4
	
 
	
 
	
 
	
0.0
	
 

	
 
	
$
	
89.4
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
92.9
	
 
	
 
	
$
	
182.3
	
 
	
 
	
$
	
0.0
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Maximum
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
After (1)
	
 
	
 
	
Theoretical
	
 
	
 
	
Liabilities
Recognized
	
 

	
Letters of Credit for the Benefit of:
	
2016
	
 
	
 
	
2017-2020
	
 
	
 
	
2020
	
 
	
 
	
Obligation
	
 
	
 
	
at Mar. 31, 2016 (4)
	
 

	
TEC
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.5
	
 
	
 
	
$
	
0.5
	
 
	
 
	
$
	
0.1
	
 

	
NMGC
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
1.7
	
 
	
 
	
 
	
1.7
	
 
	
 
	
 
	
0.0
	
 

	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
2.2
	
 
	
 
	
$
	
2.2
	
 
	
 
	
$
	
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 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 Mar. 31, 2016. See Note 12 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 15, 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 Mar. 31, 2016. 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 facilities, TECO Energy and its subsidiaries must meet certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TECO Energy and its subsidiaries have certain
restrictive 
 19


 covenants in specific agreements and debt instruments. At Mar. 31, 2016, TECO Energy and its subsidiaries were in compliance with all applicable financial covenants. 

 

11. Segment Information 

TECO Energy is an electric and gas utility holding company with
diversified activities. 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 subsidiary’s
contribution of revenues, net income and total assets as required by the accounting guidance for disclosures about segments of an enterprise and related information. Intercompany transactions are eliminated in the Consolidated Condensed Financial
Statements of TECO Energy, but are included in determining reportable segments.  
  
 
	
Three months ended Mar. 31,
	
Tampa
Electric
	
 
	
 
	
PGS
	
 
	
 
	
NMGC (2)
	
 
	
 
	
TECO

Coal (1)
	
 
	
 
	
Other (2) (3)
	
 
	
 
	
Eliminations (3)
	
 
	
 
	
TECO

Energy
	
 

	
2016
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Revenues - external
	
$
	
423.4
	
 
	
 
	
$
	
126.8
	
 
	
 
	
$
	
106.6
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
2.7
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
659.5
	
 

	
Sales to affiliates
	
 
	
1.1
	
 
	
 
	
 
	
4.4
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(5.5
	
)
	
 
	
 
	
0.0
	
 

	
Total revenues
	
 
	
424.5
	
 
	
 
	
 
	
131.2
	
 
	
 
	
 
	
106.6
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
2.7
	
 
	
 
	
 
	
(5.5
	
)
	
 
	
 
	
659.5
	
 

	
Depreciation and
amortization
	
 
	
66.1
	
 
	
 
	
 
	
14.8
	
 
	
 
	
 
	
8.4
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
89.8
	
 

	
Total interest charges
	
 
	
23.8
	
 
	
 
	
 
	
3.7
	
 
	
 
	
 
	
3.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
15.6
	
 
	
 
	
 
	
(0.2
	
)
	
 
	
 
	
45.9
	
 

	
Internally allocated
interest
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.2
	
 
	
 
	
 
	
(0.2
	
)
	
 
	
 
	
0.0
	
 

	
Provision (benefit) for income
taxes
	
 
	
27.8
	
 
	
 
	
 
	
8.9
	
 
	
 
	
 
	
9.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(10.7
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
35.7
	
 

	
Net income (loss) from
continuing operations
	
 
	
50.2
	
 
	
 
	
 
	
13.1
	
 
	
 
	
 
	
15.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(4.8
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
73.7
	
 

	
Income (loss) from discontinued
operations, net (1)
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.1
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.1
	
 

	
Net income (loss)
	
$
	
50.2
	
 
	
 
	
$
	
13.1
	
 
	
 
	
$
	
15.2
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
(4.7
	
)
	
 
	
$
	
0.0
	
 
	
 
	
$
	
73.8
	
 

	
2015
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Revenues - external
	
$
	
449.8
	
 
	
 
	
$
	
121.7
	
 
	
 
	
$
	
119.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
2.5
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
693.0
	
 

	
Sales to affiliates
	
 
	
0.8
	
 
	
 
	
 
	
1.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(2.0
	
)
	
 
	
 
	
0.0
	
 

	
Total revenues
	
 
	
450.6
	
 
	
 
	
 
	
122.9
	
 
	
 
	
 
	
119.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
2.5
	
 
	
 
	
 
	
(2.0
	
)
	
 
	
 
	
693.0
	
 

	
Depreciation and
amortization
	
 
	
62.9
	
 
	
 
	
 
	
13.9
	
 
	
 
	
 
	
8.4
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
85.5
	
 

	
Total interest charges
	
 
	
23.5
	
 
	
 
	
 
	
3.5
	
 
	
 
	
 
	
3.3
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
17.9
	
 
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
47.9
	
 

	
Internally allocated
interest
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.3
	
 
	
 
	
 
	
(0.3
	
)
	
 
	
 
	
0.0
	
 

	
Provision (benefit) for income
taxes
	
 
	
27.4
	
 
	
 
	
 
	
9.2
	
 
	
 
	
 
	
9.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(5.7
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
39.9
	
 

	
Net income (loss) from
continuing operations
	
 
	
48.2
	
 
	
 
	
 
	
14.6
	
 
	
 
	
 
	
13.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(12.9
	
)
	
 
	
 
	
0.0
	
 
	
 
	
 
	
63.8
	
 

	
Income (loss) from discontinued
operations, net (1)
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(6.0
	
)
	
 
	
 
	
0.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
(5.8
	
)

	
Net income (loss)
	
$
	
48.2
	
 
	
 
	
$
	
14.6
	
 
	
 
	
$
	
13.9
	
 
	
 
	
$
	
(6.0
	
)
	
 
	
$
	
(12.7
	
)
	
 
	
$
	
0.0
	
 
	
 
	
$
	
58.0
	
 

	
At Mar. 31, 2016
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Total assets
	
$
	
6,988.2
	
 
	
 
	
$
	
1,147.0
	
 
	
 
	
$
	
1,210.9
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
1,982.1
	
 
	
 
	
$
	
(2,347.1
	
)
	
(4)
	
$
	
8,981.1
	
 

	
At Dec. 31, 2015
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Total assets (3)
	
$
	
7,003.8
	
 
	
 
	
$
	
1,136.1
	
 
	
 
	
$
	
1,229.7
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
1,945.1
	
 
	
 
	
$
	
(2,381.2
	
)
	
(4)
	
 
	
8,933.5
	
 

	
(1)    
All periods have been adjusted to reflect the results from operations to discontinued operations for TECO Coal and certain charges and gains at Other, including Parent and TECO Diversified, that directly relate to TECO Coal and TECO Guatemala. See Note 15.
	
 

	
(2)    NMGI is
included in the Other segment.
	
 

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

	
(4)    Amounts
primarily relate to intercompany advances and consolidated tax eliminations.
	
 



  
  

 


20


  

12. 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; 



 
	  
	 ·
	 To optimize the utilization of NMGC’s
physical natural gas storage capacity, 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. 

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 13). 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 and sale of natural gas for the benefit of its regulated companies’ ratepayers. 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 Mar. 31, 2016, all of the company’s physical contracts qualify for the
NPNS exception with the exception of a minor amount of forward purchases and sales entered into by NMGC to optimize its gas storage capacity.

The derivatives that are designated as cash flow hedges at Mar.
31, 2016 and Dec. 31, 2015 are reflected on the company’s Consolidated Condensed 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 $0.0 million and $0.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively, and are included in “Prepayments and other current assets” on the Condensed Consolidated Balance Sheets. Derivative
liabilities totaled $23.1 million and $26.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross derivative assets and liabilities and the net amounts presented on the Consolidated
Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties. 

All of the derivative assets and liabilities at Mar. 31, 2016 and
Dec. 31, 2015 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 Condensed Balance Sheets as current and long-term regulatory assets and
liabilities. Based on the fair value of the instruments at Mar. 31, 2016, net pretax losses of $22.3 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next
twelve months. 
 The Mar. 31, 2016 and Dec. 31, 2015 balance
in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 8. 

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 three months ended Mar. 31, 2016 and 2015, 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 

21


 three months ended Mar. 31, 2016 and 2015 is presented in Note 8. These gains and losses were the result of interest rate contracts for TEC. The location of the reclassification to income was reflected in “Interest expense” for TEC.

The maximum length of time over which the company is hedging its
exposure to the variability in future cash flows extends to Feb. 28, 2018 for financial natural gas contracts. The following table presents the company’s derivative volumes that, as of Mar. 31, 2016, are expected to settle during the 2016,
2017 and 2018 fiscal years: 
  
 
	
Derivative Volumes
	
Natural Gas
Contracts
	
 

	
(millions)
	
(MMBTUs)
	
 

	
Year
	
Physical
	
 
	
 
	
Financial
	
 

	
2016
	
 
	
0.0
	
 
	
 
	
 
	
25.1
	
 

	
2017
	
 
	
0.0
	
 
	
 
	
 
	
9.9
	
 

	
2018
	
 
	
0.0
	
 
	
 
	
 
	
0.7
	
 

	
Total
	
 
	
0.0
	
 
	
 
	
 
	
35.7
	
 




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 Mar. 31,
2016, 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. 
  

13. 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: 

22


  

(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 Mar. 31, 2016 and Dec. 31, 2015. 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.      

 
 
	
Recurring Fair Value Measures
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
As of Mar. 31,
2016
	
 

	
(millions)
	
Level 1
	
 
	
 
	
Level 2
	
 
	
 
	
Level 3
	
 
	
 
	
Total
	
 

	
Liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Natural gas derivatives
	
$
	
0.0
	
 
	
 
	
$
	
23.1
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
23.1
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
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
	
 




 

The natural gas derivatives are OTC swap, forward and option
instruments. Fair values of swaps and forwards are estimated utilizing the market approach. The price of swaps and forwards are calculated using observable NYMEX quoted closing prices of exchange-traded futures. Fair values of options are
estimated utilizing the income approach. 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, forward and option positions to determine the fair value (see Note
12).  
 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 Mar. 31, 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented.

  

14. 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 250 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. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate
any of these entities. Tampa Electric purchased $12.6 million and $5.4 million under these PPAs for the three months ended Mar. 31, 2016 and 2015, respectively. 

23


 
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 Condensed Balance Sheets, Statements of
Income or Cash Flows. 
  

15. Discontinued Operations and Asset Impairments

TECO Coal 

On Sept. 21, 2015, TECO Energy’s
subsidiary, TECO Diversified, entered into an 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.  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 10). The SPA contained
customary representations, warranties and covenants (see Note 10 for description of a claim related to the SPA). The income shown for the first quarter of 2016 in the table below reflects a refund of prepaid
costs. 
 Since the closing of the sale, TECO Energy does 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.

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 10). The charges shown in the table below are legal costs associated with that claim.  

Combined Components of Discontinued Operations

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

 
 
	
Components of income from discontinued operations
	
Three months
ended
	
 

	
 
	
Mar. 31,
	
 

	
(millions)
	
2016
	
 
	
 
	
2015
	
 

	
Revenues—TECO Coal
	
$
	
0.0
	
 
	
 
	
$
	
72.7
	
 

	
Loss from operations—TECO
Coal
	
 
	
0.0
	
 
	
 
	
 
	
(9.5
	
)

	
Loss from operations—TECO
Guatemala
	
 
	
0.0
	
 
	
 
	
 
	
(0.1
	
)

	
Income (loss) from discontinued
operations—TECO Coal
	
 
	
0.2
	
 
	
 
	
 
	
(9.5
	
)

	
Loss from discontinued
operations—TECO Guatemala
	
 
	
0.0
	
 
	
 
	
 
	
(0.1
	
)

	
Income (loss) from discontinued
operations
	
 
	
0.2
	
 
	
 
	
 
	
(9.6
	
)

	
Provision (benefit) for income
taxes
	
 
	
0.1
	
 
	
 
	
 
	
(3.8
	
)

	
Income (loss) from discontinued
operations, net
	
$
	
0.1
	
 
	
 
	
$
	
(5.8
	
)




 
  

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. 

24


 
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 and the Committee on Foreign Investment in the United States, was obtained on Jan. 20, 2016 and Mar. 23, 2016, respectively), (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. 

On Apr. 11, 2016, Emera and TECO Energy filed with the NMPRC an
unopposed stipulation agreement reflecting a settlement reached with certain intervening parties in the acquisition case currently pending before the NMPRC for approval of the transaction.  In the stipulation, the parties state that they
believe the settlement is in the public interest and have recommended approval to the NMPRC. Amongst other elements, the stipulation includes Emera’s agreement to maintain the commitments made by TECO Energy in its 2014 case relating to its
acquisition of NMGC, invest in the expansion of the natural gas system to underserved communities and the Mexican border, and provide resources to support certain economic growth projects and programs.  The stipulation is subject to review
and approval by the NMPRC. The NMPRC hearing to consider the acquisition is scheduled to begin in May 2016.

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. 

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) or (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final.
If the Merger Agreement is terminated under certain circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million. 

During the three months ended Mar. 31, 2016, TECO Energy incurred
approximately $0.1 million pretax of incremental transaction-related costs, which are included in “Operations and maintenance other expense” on the Consolidated Condensed Statements of Income.

 
  

 




25


  

TAMPA ELECTRIC COMPANY 


Consolidated Condensed Balance Sheets 

Unaudited 

 
 
	
Assets
	
Mar. 31,
	
 
	
 
	
Dec. 31,
	
 

	
(millions)
	
2016
	
 
	
 
	
2015
	
 

	
Property, plant and
equipment
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Utility plant in
service
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Electric
	
$
	
7,328.3
	
 
	
 
	
$
	
7,270.3
	
 

	
Gas
	
 
	
1,419.3
	
 
	
 
	
 
	
1,398.6
	
 

	
Construction work in
progress
	
 
	
797.0
	
 
	
 
	
 
	
771.1
	
 

	
Utility plant in service, at
original costs
	
 
	
9,544.6
	
 
	
 
	
 
	
9,440.0
	
 

	
Accumulated
depreciation
	
 
	
(2,720.3
	
)
	
 
	
 
	
(2,676.8
	
)

	
Utility plant in service,
net
	
 
	
6,824.3
	
 
	
 
	
 
	
6,763.2
	
 

	
Other property
	
 
	
9.9
	
 
	
 
	
 
	
9.7
	
 

	
Total property, plant and
equipment, net
	
 
	
6,834.2
	
 
	
 
	
 
	
6,772.9
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Current assets
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Cash and cash
equivalents
	
 
	
28.2
	
 
	
 
	
 
	
9.1
	
 

	
Receivables, less allowance for
uncollectibles of $1.6 and $1.5 at Mar. 31, 2016

   and Dec. 31, 2015,
respectively
	
 
	
205.5
	
 
	
 
	
 
	
230.2
	
 

	
Inventories, at average
cost
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Fuel
	
 
	
115.4
	
 
	
 
	
 
	
105.6
	
 

	
Materials and supplies
	
 
	
73.6
	
 
	
 
	
 
	
73.1
	
 

	
Regulatory assets
	
 
	
39.9
	
 
	
 
	
 
	
44.3
	
 

	
Taxes receivable from
affiliate
	
 
	
0.0
	
 
	
 
	
 
	
61.3
	
 

	
Prepayments and other current
assets
	
 
	
17.0
	
 
	
 
	
 
	
21.5
	
 

	
Total current assets
	
 
	
479.6
	
 
	
 
	
 
	
545.1
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Deferred debits
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulatory assets
	
 
	
373.1
	
 
	
 
	
 
	
373.8
	
 

	
Other
	
 
	
17.9
	
 
	
 
	
 
	
16.8
	
 

	
Total deferred debits
	
 
	
391.0
	
 
	
 
	
 
	
390.6
	
 

	
Total assets
	
$
	
7,704.8
	
 
	
 
	
$
	
7,708.6
	
 




 

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

 

26


  


 TAMPA ELECTRIC
COMPANY 
 Consolidated Condensed Balance
Sheets - continued
 Unaudited 

 
 
	
Liabilities and
Capitalization
	
Mar. 31,
	
 
	
 
	
Dec. 31,
	
 

	
(millions)
	
2016
	
 
	
 
	
2015
	
 

	
Capitalization
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Common stock
	
$
	
2,330.4
	
 
	
 
	
$
	
2,305.4
	
 

	
Accumulated other comprehensive
loss
	
 
	
(3.4
	
)
	
 
	
 
	
(3.6
	
)

	
Retained earnings
	
 
	
314.4
	
 
	
 
	
 
	
313.7
	
 

	
Total capital
	
 
	
2,641.4
	
 
	
 
	
 
	
2,615.5
	
 

	
Long-term debt
	
 
	
2,162.0
	
 
	
 
	
 
	
2,161.7
	
 

	
Total capitalization
	
 
	
4,803.4
	
 
	
 
	
 
	
4,777.2
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Current liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Long-term debt due within one
year
	
 
	
83.3
	
 
	
 
	
 
	
83.3
	
 

	
Notes payable
	
 
	
0.0
	
 
	
 
	
 
	
61.0
	
 

	
Accounts payable
	
 
	
174.6
	
 
	
 
	
 
	
221.6
	
 

	
Customer deposits
	
 
	
170.9
	
 
	
 
	
 
	
176.3
	
 

	
Regulatory liabilities
	
 
	
104.5
	
 
	
 
	
 
	
83.2
	
 

	
Derivative liabilities
	
 
	
22.2
	
 
	
 
	
 
	
24.1
	
 

	
Interest accrued
	
 
	
41.2
	
 
	
 
	
 
	
16.9
	
 

	
Taxes accrued
	
 
	
33.6
	
 
	
 
	
 
	
13.2
	
 

	
Other
	
 
	
10.1
	
 
	
 
	
 
	
10.2
	
 

	
Total current
liabilities
	
 
	
640.4
	
 
	
 
	
 
	
689.8
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Deferred credits
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Deferred income taxes
	
 
	
1,342.0
	
 
	
 
	
 
	
1,308.8
	
 

	
Investment tax credits
	
 
	
10.4
	
 
	
 
	
 
	
10.5
	
 

	
Derivative liabilities
	
 
	
0.8
	
 
	
 
	
 
	
2.1
	
 

	
Regulatory liabilities
	
 
	
595.5
	
 
	
 
	
 
	
603.5
	
 

	
Deferred credits and other
liabilities
	
 
	
312.3
	
 
	
 
	
 
	
316.7
	
 

	
Total deferred credits
	
 
	
2,261.0
	
 
	
 
	
 
	
2,241.6
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Commitments and Contingencies (see Note 8)
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Total liabilities and
capitalization
	
$
	
7,704.8
	
 
	
 
	
$
	
7,708.6
	
 




 

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

27


  

TAMPA ELECTRIC COMPANY 

Consolidated Condensed Statements of Income and
Comprehensive Income 
 Unaudited 

 
 
	
 
	
Three months ended
Mar. 31,
	
 

	
(millions)
	
2016
	
 
	
 
	
2015
	
 

	
Revenues
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Electric
	
$
	
424.2
	
 
	
 
	
$
	
450.4
	
 

	
Gas
	
 
	
126.8
	
 
	
 
	
 
	
121.7
	
 

	
Total revenues
	
 
	
551.0
	
 
	
 
	
 
	
572.1
	
 

	
Expenses
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulated operations and
maintenance
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Fuel
	
 
	
115.1
	
 
	
 
	
 
	
144.1
	
 

	
Purchased power
	
 
	
14.4
	
 
	
 
	
 
	
17.1
	
 

	
Cost of natural gas
sold
	
 
	
50.3
	
 
	
 
	
 
	
43.3
	
 

	
Other
	
 
	
121.2
	
 
	
 
	
 
	
121.8
	
 

	
Depreciation and
amortization
	
 
	
80.9
	
 
	
 
	
 
	
76.8
	
 

	
Taxes, other than
income
	
 
	
48.5
	
 
	
 
	
 
	
47.6
	
 

	
Total expenses
	
 
	
430.4
	
 
	
 
	
 
	
450.7
	
 

	
Income from operations
	
 
	
120.6
	
 
	
 
	
 
	
121.4
	
 

	
Other income
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Allowance for other funds used
during construction
	
 
	
5.6
	
 
	
 
	
 
	
3.8
	
 

	
Other income, net
	
 
	
1.3
	
 
	
 
	
 
	
1.2
	
 

	
Total other income
	
 
	
6.9
	
 
	
 
	
 
	
5.0
	
 

	
Interest charges
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Interest on long-term
debt
	
 
	
29.0
	
 
	
 
	
 
	
27.7
	
 

	
Interest expense
	
 
	
1.2
	
 
	
 
	
 
	
1.1
	
 

	
Allowance for borrowed funds
used during construction
	
 
	
(2.7
	
)
	
 
	
 
	
(1.8
	
)

	
Total interest charges
	
 
	
27.5
	
 
	
 
	
 
	
27.0
	
 

	
Income before provision for income
taxes
	
 
	
100.0
	
 
	
 
	
 
	
99.4
	
 

	
Provision for income
taxes
	
 
	
36.7
	
 
	
 
	
 
	
36.6
	
 

	
Net income
	
 
	
63.3
	
 
	
 
	
 
	
62.8
	
 

	
Other comprehensive income, net of
tax
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Gain on cash flow
hedges
	
 
	
0.2
	
 
	
 
	
 
	
0.3
	
 

	
Total other comprehensive
income, net of tax
	
 
	
0.2
	
 
	
 
	
 
	
0.3
	
 

	
Comprehensive income
	
$
	
63.5
	
 
	
 
	
$
	
63.1
	
 




 

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

 

28


  

TAMPA ELECTRIC COMPANY 

Consolidated
 Condensed Statements of Cash Flows 
 Unaudited

  
 
	
 
	
Three months ended
Mar. 31,
	
 

	
(millions)
	
2016
	
 
	
 
	
2015
	
 

	
Cash flows from operating
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Net income
	
$
	
63.3
	
 
	
 
	
$
	
62.8
	
 

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

	
Depreciation and
amortization
	
 
	
80.9
	
 
	
 
	
 
	
76.8
	
 

	
Deferred income taxes and
investment tax credits
	
 
	
30.4
	
 
	
 
	
 
	
21.2
	
 

	
Allowance for funds used during
construction
	
 
	
(5.6
	
)
	
 
	
 
	
(3.8
	
)

	
Deferred recovery
clauses
	
 
	
27.0
	
 
	
 
	
 
	
(4.7
	
)

	
Receivables, less allowance for
uncollectibles
	
 
	
24.7
	
 
	
 
	
 
	
13.5
	
 

	
Inventories
	
 
	
(10.3
	
)
	
 
	
 
	
(21.1
	
)

	
Prepayments
	
 
	
4.6
	
 
	
 
	
 
	
(5.0
	
)

	
Taxes accrued
	
 
	
81.7
	
 
	
 
	
 
	
72.7
	
 

	
Interest accrued
	
 
	
24.3
	
 
	
 
	
 
	
22.9
	
 

	
Accounts payable
	
 
	
(41.2
	
)
	
 
	
 
	
(28.3
	
)

	
Other
	
 
	
(11.6
	
)
	
 
	
 
	
(6.9
	
)

	
Cash flows from operating
activities
	
 
	
268.2
	
 
	
 
	
 
	
200.1
	
 

	
Cash flows from investing
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Capital expenditures
	
 
	
(150.5
	
)
	
 
	
 
	
(148.8
	
)

	
Cash flows used in investing
activities
	
 
	
(150.5
	
)
	
 
	
 
	
(148.8
	
)

	
Cash flows from financing
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Common stock
	
 
	
25.0
	
 
	
 
	
 
	
20.0
	
 

	
Net decrease in short-term
debt
	
 
	
(61.0
	
)
	
 
	
 
	
(11.0
	
)

	
Dividends
	
 
	
(62.6
	
)
	
 
	
 
	
(55.7
	
)

	
Cash flows used in financing
activities
	
 
	
(98.6
	
)
	
 
	
 
	
(46.7
	
)

	
Net increase in cash and cash
equivalents
	
 
	
19.1
	
 
	
 
	
 
	
4.6
	
 

	
Cash and cash equivalents at
beginning of period
	
 
	
9.1
	
 
	
 
	
 
	
10.4
	
 

	
Cash and cash equivalents at end of
period
	
$
	
28.2
	
 
	
 
	
$
	
15.0
	
 

	
Supplemental disclosure of non-cash
activities
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Change in accrued capital
expenditures
	
$
	
(4.8
	
)
	
 
	
$
	
11.4
	
 




 

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




29


  

 

TAMPA ELECTRIC COMPANY 


NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS 

UNAUDITED 

 

1. Summary of Significant Accounting Policies 

See TEC’s 2015 Annual Report on Form 10-K for a
complete discussion of accounting policies. The significant accounting policies for TEC include: 

Principles of Consolidation and Basis of Presentation 

TEC is a wholly owned subsidiary of TECO Energy. For the purposes
of its consolidated financial reporting, TEC is comprised of the electric division, generally referred to as Tampa Electric, the natural gas division, generally referred to as PGS, and potentially the accounts of VIEs for which it is the primary
beneficiary. For the periods presented, no VIEs have been consolidated (see Note 13). 

Intercompany balances and intercompany transactions have been
eliminated in consolidation. In the opinion of management, the unaudited consolidated condensed financial statements include all adjustments that are of a recurring nature and necessary to state fairly the financial position of TEC as of Mar. 31,
2016 and Dec. 31, 2015, and the results of operations and cash flows for the periods ended Mar. 31, 2016 and 2015. The results of operations for the three months ended Mar. 31, 2016 are not necessarily indicative of the results that can be expected
for the entire fiscal year ending Dec. 31, 2016. 
 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. The year-end consolidated condensed balance sheet data was derived from audited financial statements;
however, this quarterly report on Form 10-Q does not include all year-end disclosures required for an annual report on Form 10-K by U.S. GAAP. 

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 14 for further information.

Revenues 

As of Mar. 31, 2016 and Dec. 31, 2015, unbilled revenues of $56.8
million and $53.7 million, respectively, are included in the “Receivables” line item on the Consolidated Condensed Balance Sheets. 

Accounting for Franchise Fees and Gross Receipts 

Tampa Electric and PGS are allowed to recover certain costs from
customers on a dollar-per-dollar basis 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 Condensed Statements of Income.
Franchise fees and gross receipt taxes payable by Tampa Electric and PGS are included as an expense on the Consolidated Condensed Statements of Income in “Taxes, other than income”. These amounts totaled $27.9 million and $27.4 million
for the three months ended Mar. 31, 2016 and 2015, respectively.
  

2. New Accounting Pronouncements 

Change in Accounting Policy

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 became effective for TEC beginning in 2016 and is required to be applied on a retrospective basis for all periods presented. As of Mar. 31, 2016 and Dec. 31, 2015, TEC classified $17.9
million and $18.1 million, respectively, of debt issuance costs, which do not include costs for line-of-credit arrangements, as a deduction in the “Long-term debt, less amount due within one year” line item on the company’s
Consolidated Condensed Balance Sheet (previously classified as an asset in the “Unamortized debt expense” line item). The guidance did not affect TEC’s results of operations or cash flows.

30


  

Future 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 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. 
  

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. Under the existing guidance,
operating leases are not recorded as lease assets and lease liabilities on the balance sheet. Recognition of expenses for both operating and finance leases will be similar to existing guidance and as a result is expected to limit the impact of the
changes on the income statement and statement of cash flows. In addition, the guidance will require additional disclosures regarding key information about leasing arrangements. This guidance will be effective for TEC beginning in 2019, with early
adoption 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.

Derivative Contract Novations

In March 2016, the FASB issued guidance clarifying that a change
in the counterparty to a derivative contract, in and of itself, does not require the dedesignation of a hedging relationship provided that all other hedge accounting criteria continue to be met. The guidance is effective for TEC beginning in 2017,
with early adoption permitted, and may be applied on a prospective or modified retrospective basis. The guidance will not affect TEC’s current financial statements. However, TEC will assess the impact of this guidance on future derivative
contract novations, if any.
  

3. Regulatory 

Tampa Electric’s and PGS’s retail businesses 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 requirement) equal to their cost of providing
service, plus a reasonable return on invested capital. 
 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 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 Mar. 31,
2016 and Dec. 31, 2015 are presented in the following table: 

31


  

 
 
	
Regulatory
 Assets and Liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
Mar. 31,
2016
	
 
	
 
	
Dec. 31,
2015
	
 

	
Regulatory assets:
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulatory tax asset (1)
	
$
	
77.0
	
 
	
 
	
$
	
74.6
	
 

	
Cost-recovery clauses - deferred
balances (2)
	
 
	
0.0
	
 
	
 
	
 
	
5.2
	
 

	
Cost-recovery clauses - offsets
to derivative liabilities (2)
	
 
	
25.9
	
 
	
 
	
 
	
26.2
	
 

	
Environmental remediation (3)
	
 
	
54.4
	
 
	
 
	
 
	
54.0
	
 

	
Postretirement benefits (4)
	
 
	
236.4
	
 
	
 
	
 
	
238.3
	
 

	
Deferred bond refinancing costs (5)
	
 
	
6.2
	
 
	
 
	
 
	
6.5
	
 

	
Competitive rate adjustment (2)
	
 
	
2.5
	
 
	
 
	
 
	
2.6
	
 

	
Other
	
 
	
10.6
	
 
	
 
	
 
	
10.7
	
 

	
Total regulatory assets
	
 
	
413.0
	
 
	
 
	
 
	
418.1
	
 

	
Less: Current portion
	
 
	
39.9
	
 
	
 
	
 
	
44.3
	
 

	
Long-term regulatory
assets
	
$
	
373.1
	
 
	
 
	
$
	
373.8
	
 

	
Regulatory liabilities:
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Regulatory tax
liability
	
$
	
5.6
	
 
	
 
	
$
	
5.7
	
 

	
Cost-recovery clauses (2)
	
 
	
76.1
	
 
	
 
	
 
	
54.2
	
 

	
Transmission and delivery storm
reserve
	
 
	
56.1
	
 
	
 
	
 
	
56.1
	
 

	
Accumulated reserve - cost of
removal (6)
	
 
	
561.7
	
 
	
 
	
 
	
570.0
	
 

	
Other
	
 
	
0.5
	
 
	
 
	
 
	
0.7
	
 

	
Total regulatory
liabilities
	
 
	
700.0
	
 
	
 
	
 
	
686.7
	
 

	
Less: Current portion
	
 
	
104.5
	
 
	
 
	
 
	
83.2
	
 

	
Long-term regulatory
liabilities
	
$
	
595.5
	
 
	
 
	
$
	
603.5
	
 





	 (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 

 

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. TEC’s effective tax rates for the three months ended Mar. 31, 2016 and 2015 differ from the statutory rate principally
due to state income taxes, the domestic activity production deduction and the AFUDC-equity.

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 forward. 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 by the end of 2016.
  

32


  

5. Employee Postretirement Benefits 

TEC is a participant in the comprehensive retirement plans of
TECO Energy. Amounts allocable to all participants of the TECO Energy retirement plans are found in Note 5, Employee Postretirement Benefits, in the TECO Energy Notes to Consolidated Condensed Financial Statements. TEC’s portion of the net pension expense for the three months ended Mar. 31, 2016 and 2015, respectively, was $2.9 million and $2.6 million for
pension benefits, and $1.5 million and $1.4 million for other postretirement benefits. 

For the fiscal 2016 plan year, TECO Energy assumed a long-term
EROA of 7.00% and a discount rate of 4.685%.  For the Jan. 1, 2016 measurement of TECO Energy’s other postretirement benefits, TECO Energy used a discount rate of 4.667%. Additionally, TECO Energy made contributions of $4.7 million
and $14.9 million to its pension plan in the three months ended Mar. 31, 2016 and 2015, respectively. TEC’s portion of the contributions was $3.9 million and $11.0 million, respectively. 

Included in the benefit expenses discussed above, for the three
months ended Mar. 31, 2016 and 2015, TEC reclassified $2.0 million and $1.9 million, respectively, of unamortized prior service benefit and actuarial losses from regulatory assets to net income. 

 

6. Short-Term Debt 

At Mar. 31, 2016 and Dec. 31, 2015, the following credit
facilities and related borrowings existed: 
  
 
	
Credit
 Facilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
Mar. 31,
2016
	
 
	
 
	
Dec. 31,
2015
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
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
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.5
	
 

	
3-year accounts

   receivable facility
(3)
	
 
	
150.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
150.0
	
 
	
 
	
 
	
61.0
	
 
	
 
	
 
	
0.0
	
 

	
Total
	
$
	
475.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.5
	
 
	
 
	
$
	
475.0
	
 
	
 
	
$
	
61.0
	
 
	
 
	
$
	
0.5
	
 





	 (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.



 At
Mar. 31, 2016, these credit facilities required commitment fees ranging from 12.5 to 30.0 basis points. The weighted-average interest rate on outstanding amounts payable under the credit facilities at Mar. 31, 2016 and Dec. 31, 2015 was 1.0% and
0.89%, respectively.
  
  

7. Long-Term Debt 

Fair Value of Long-Term Debt 

At Mar. 31, 2016, TEC’s total long-term debt had a carrying
amount of $2,245.3 million and an estimated fair market value of $2,483.1 million. At Dec. 31, 2015, TEC’s total long-term debt had a carrying amount of $2,245.0 million and an estimated fair market value of $2,433.3 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 (see Note 11 for
information regarding the fair value hierarchy). 
 Purchase in
Lieu of Redemption of Revenue Refunding Bonds
 
On Mar. 
19, 2008, the HCIDA remarketed $86.0 million HCIDA Pollution Control Revenue Refunding Bonds, Series 2006 (Non-AMT) (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. On Mar. 
15, 2012, TEC purchased in lieu of redemption the Series 2006 HCIDA Bonds. The Series 2006 HCIDA Bonds bore interest at a term rate of 1.875% per annum from Mar. 15, 2012 to Mar. 15, 2016. On Mar. 
15, 2016, pursuant to the terms of the Loan and Trust Agreement governing the Series 2006 HCIDA Bonds, a mandatory tender occurred and a term rate of 2.00% per annum will apply from Mar. 15, 2016 to Mar. 
15, 2020. The 2016 mandatory tender did not impact the Consolidated Condensed Balance Sheet. TEC is 

33


  

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.
  

As of Mar. 31, 2016, $232.6 million of bonds purchased in lieu of
redemption, including the series 2006 HCIDA Bonds described above, were held by the trustee at the direction of TEC to provide an opportunity to evaluate refinancing alternatives.

 

8. 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. 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 not believe that their ultimate resolution will have a material adverse effect on the
company’s results of operations, financial condition or cash flows. 

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 October 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. On Apr. 18, 2016, PGS reached a settlement regarding this matter with the OPC and FPSC staff and agreed to pay a $1 million civil penalty and customer refunds of $2 million. The FPSC approved the settlement agreement on May 5, 2016.

 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
Mar. 31, 2016, 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 
 34


  

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. 

Letters of Credit 

A summary of the face amount or maximum theoretical obligation
under TEC’s letters of credit as of Mar. 31, 2016 is as follows: 

 
 
	
Letters
 of Credit - Tampa Electric Company
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
After (1)
	
 
	
 
	
 
	
 
	
 
	
 
	
Liabilities
Recognized
	
 

	
Letters of Credit for the Benefit of:
	
2016
	
 
	
 
	
2017-2020
	
 
	
 
	
2020
	
 
	
 
	
Total
	
 
	
 
	
at Mar. 31,
2016
	
 

	
TEC
(2)
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.5
	
 
	
 
	
$
	
0.5
	
 
	
 
	
$
	
0.1
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(1)     These letters of credit 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 Mar. 31, 2016. 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 its bank credit facilities, TEC must meet
certain financial tests, including a debt to capital ratio, as defined in the applicable agreements. In addition, TEC has certain restrictive covenants in specific agreements and debt instruments. At Mar. 31, 2016, TEC was in compliance with all
applicable financial covenants. 
  

9. Segment Information

 

 
 
	
 (millions)
	
Tampa
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
Tampa
Electric
	
 

	
Three months ended Mar. 31,
	
Electric
	
 
	
 
	
PGS
	
 
	
 
	
Eliminations
	
 
	
 
	
Company
	
 

	
2016
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Revenues - external
	
$
	
424.2
	
 
	
 
	
$
	
126.8
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
551.0
	
 

	
Intracompany sales
	
 
	
0.3
	
 
	
 
	
 
	
4.4
	
 
	
 
	
 
	
(4.7
	
)
	
 
	
 
	
0.0
	
 

	
Total revenues
	
 
	
424.5
	
 
	
 
	
 
	
131.2
	
 
	
 
	
 
	
(4.7
	
)
	
 
	
 
	
551.0
	
 

	
Depreciation and
amortization
	
 
	
66.1
	
 
	
 
	
 
	
14.8
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
80.9
	
 

	
Total interest charges
	
 
	
23.8
	
 
	
 
	
 
	
3.7
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
27.5
	
 

	
Provision for income
taxes
	
 
	
27.8
	
 
	
 
	
 
	
8.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
36.7
	
 

	
Net income
	
$
	
50.2
	
 
	
 
	
$
	
13.1
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
63.3
	
 

	
2015
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Revenues - external
	
$
	
450.4
	
 
	
 
	
$
	
121.7
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
572.1
	
 

	
Intracompany sales
	
 
	
0.2
	
 
	
 
	
 
	
1.2
	
 
	
 
	
 
	
(1.4
	
)
	
 
	
 
	
0.0
	
 

	
Total revenues
	
 
	
450.6
	
 
	
 
	
 
	
122.9
	
 
	
 
	
 
	
(1.4
	
)
	
 
	
 
	
572.1
	
 

	
Depreciation and
amortization
	
 
	
62.9
	
 
	
 
	
 
	
13.9
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
76.8
	
 

	
Total interest charges
	
 
	
23.5
	
 
	
 
	
 
	
3.5
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
27.0
	
 

	
Provision for income
taxes
	
 
	
27.4
	
 
	
 
	
 
	
9.2
	
 
	
 
	
 
	
0.0
	
 
	
 
	
 
	
36.6
	
 

	
Net income
	
$
	
48.2
	
 
	
 
	
$
	
14.6
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
62.8
	
 

	
Total assets at Mar. 31,
2016
	
$
	
6,600.4
	
 
	
 
	
$
	
1,109.6
	
 
	
 
	
$
	
(5.2
	
)
	
 
	
$
	
7,704.8
	
 

	
Total assets at Dec. 31, 2015 (1)
	
 
	
6,620.2
	
 
	
 
	
 
	
1,097.7
	
 
	
 
	
 
	
(9.3
	
)
	
 
	
 
	
7,708.6
	
 




 
 
	 (1)
	 Certain prior year amounts have been
reclassified to conform to current year presentation.



  

10. 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. 




35


  

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 11). 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 Mar. 31, 2016, all of TEC’s physical contracts qualify for the NPNS exception. 

The derivatives that are designated as cash flow hedges at Mar.
31, 2016 and Dec. 31, 2015 are reflected on TEC’s Consolidated Condensed 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 Mar. 31, 2016 and Dec. 31, 2015. Derivative liabilities totaled $23.0 million and $26.2 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively. There are minor offset amount differences between the gross
derivative assets and liabilities and the net amounts presented on the Consolidated Condensed Balance Sheets. There was no cash collateral posted with or received from any counterparties. 

All of the derivative assets and liabilities at Mar. 31, 2016 and
Dec. 31, 2015 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 Condensed Balance Sheets as current and long-term regulatory assets and
liabilities. Based on the fair value of the instruments at Mar. 31, 2016, net pretax losses of $22.2 million are expected to be reclassified from regulatory assets or liabilities to the Consolidated Condensed Statements of Income within the next
twelve months. 
 The Mar. 31, 2016 and Dec. 31, 2015 balance
in AOCI related to the cash flow hedges and interest rate swaps (unsettled and previously settled) is presented in Note 12. 

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 three months ended Mar. 31, 2016 and 2015, 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 three months ended Mar. 31, 2016 and 2015 is presented in Note 12. Gains and losses were the result of
interest rate contracts and the reclassification to income was reflected in “Interest expense”. 

36


  

The maximum length of time over which TEC is hedging its exposure to the variability in future cash flows extends to Feb. 28, 2018 for financial natural gas contracts. The following table presents TEC’s derivative volumes that, as of Mar. 31, 2016, are expected to settle during the 2016, 2017 and 2018 fiscal years:

 
 
	
 
	
Natural Gas
Contracts
	
 

	
(millions)
	
(MMBTUs)
	
 

	
Year
	
Physical
	
 
	
 
	
Financial
	
 

	
2016
	
 
	
0.0
	
 
	
 
	
 
	
25.1
	
 

	
2017
	
 
	
0.0
	
 
	
 
	
 
	
9.9
	
 

	
2018
	
 
	
0.0
	
 
	
 
	
 
	
0.7
	
 

	
Total
	
 
	
0.0
	
 
	
 
	
 
	
35.7
	
 




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 Mar. 31, 2016,
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. 

 

11. 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: 

 

37


  


(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, TEC’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of Mar. 31, 2016 and Dec. 31, 2015. 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 Mar. 31,
2016
	
 

	
(millions)
	
Level 1
	
 
	
 
	
Level 2
	
 
	
 
	
Level 3
	
 
	
 
	
Total
	
 

	
Liabilities
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Natural gas swaps
	
$
	
0.0
	
 
	
 
	
$
	
23.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
23.0
	
 

	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
 
	
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
	
 




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 10). 

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 Mar. 31, 2016, the fair value of derivatives was not materially affected by nonperformance risk. There were no Level 3 assets or liabilities for the periods presented. 

 

12. Other Comprehensive Income

 
 
	
Other
 Comprehensive Income
	
 
	
Three months ended
Mar. 31,
	
 

	
(millions)
	
 
	
Gross
	
 
	
 
	
Tax
	
 
	
 
	
Net
	
 

	
2016
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Unrealized gain on cash flow
hedges
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 
	
 
	
$
	
0.0
	
 

	
Reclassification from AOCI to net
income
	
 
	
 
	
0.3
	
 
	
 
	
 
	
(0.1
	
)
	
 
	
 
	
0.2
	
 

	
Gain on cash flow
hedges
	
 
	
 
	
0.3
	
 
	
 
	
 
	
(0.1
	
)
	
 
	
 
	
0.2
	
 

	
Total other comprehensive
income
	
 
	
$
	
0.3
	
 
	
 
	
$
	
(0.1
	
)
	
 
	
$
	
0.2
	
 

	
2015
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
Unrealized gain on cash flow
hedges
	
 
	
$
	
0.3
	
 
	
 
	
$
	
(0.2
	
)
	
 
	
$
	
0.1
	
 

	
Reclassification from AOCI to net
income
	
 
	
 
	
0.4
	
 
	
 
	
 
	
(0.2
	
)
	
 
	
 
	
0.2
	
 

	
Gain on cash flow
hedges
	
 
	
 
	
0.7
	
 
	
 
	
 
	
(0.4
	
)
	
 
	
 
	
0.3
	
 

	
Total other comprehensive
income
	
 
	
$
	
0.7
	
 
	
 
	
$
	
(0.4
	
)
	
 
	
$
	
0.3
	
 




 
  
 
	
Accumulated
 Other Comprehensive Loss
	
 
	
 
	
 
	
 
	
 
	
 
	
 
	
 

	
(millions)
	
 
	
Mar. 31,
2016
	
 
	
 
	
Dec. 31,
2015
	
 

	
Net unrealized losses from cash
flow hedges (1)
	
 
	
$
	
(3.4
	
)
	
 
	
$
	
(3.6
	
)

	
Total accumulated other
comprehensive loss
	
 
	
$
	
(3.4
	
)
	
 
	
$
	
(3.6
	
)




38


  
 
	 (1)
	 Net of tax benefit of $2.1 million and $2.3 million as of Mar. 31, 2016 and Dec. 31, 2015, respectively.  




 

13. 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 250 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. As a result, Tampa Electric is not the primary beneficiary and is not required to consolidate
any of these entities. Tampa Electric purchased $12.6 million and $5.4 million under these PPAs for the three months ended Mar. 31, 2016 and 2015, 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 Condensed Balance Sheets,
Statements of Income or Cash Flows. 
 14. 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 and the Committee on Foreign Investment in the United States, was obtained on Jan. 20, 2016 and Mar. 23, 2016, respectively), (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. 

On Apr. 11, 2016, Emera and TECO Energy filed with the NMPRC an
unopposed stipulation agreement reflecting a settlement reached with certain intervening parties in the acquisition case currently pending before the NMPRC for approval of the transaction. The stipulation is subject to review and approval by the
NMPRC. The NMPRC hearing to consider the acquisition is scheduled to begin in May 2016.

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. 

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) or (ii) a law or judgment preventing or prohibiting the closing of the Merger has become final.
If the Merger Agreement is terminated under certain circumstances, including the failure to obtain required regulatory approvals, Emera must pay TECO Energy a termination fee of $326.9 million. 

 

 

39