BKH 10Q Q1 2015


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 
EXCHANGE ACT OF 1934
 
For the quarterly period ended March 31, 2015
OR
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 
EXCHANGE ACT OF 1934
 
For the transition period from __________ to __________.
 
 
 
Commission File Number 001-31303
Black Hills Corporation
Incorporated in South Dakota
IRS Identification Number 46-0458824
625 Ninth Street
Rapid City, South Dakota 57701
Registrant’s telephone number (605) 721-1700
Former name, former address, and former fiscal year if changed since last report
NONE
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 
Yes x
 
No o
 

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).
 
Yes x
 
No o
 

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).
 
Large accelerated filer x
 
Accelerated filer o
 
 
Non-accelerated filer o
 
Smaller reporting company o
 

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
 
Yes o
 
No x
 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.
Class
Outstanding at April 30, 2015
Common stock, $1.00 par value
44,821,847

shares





TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms and Abbreviations
 
 
 
 
 
PART I.
FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income (Loss) - unaudited
 
 
 
   Three Months Ended March 31, 2015 and 2014
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
 
 
 
   Three Months Ended March 31, 2015 and 2014
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   March 31, 2015, December 31, 2014 and March 31, 2014
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Three Months Ended March 31, 2015 and 2014
 
 
 
 
 
 
Notes to Condensed Consolidated Financial Statements - unaudited
 
 
 
 
 
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
 
 
Item 3.
Quantitative and Qualitative Disclosures about Market Risk
 
 
 
 
 
Item 4.
Controls and Procedures
 
 
 
 
 
PART II.
OTHER INFORMATION
 
 
 
 
 
Item 1.
Legal Proceedings
 
 
 
 
 
Item 1A.
Risk Factors
 
 
 
 
 
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
 
 
 
 
Item 4.
Mine Safety Disclosures
 
 
 
 
 
Item 5.
Other Information
 
 
 
 
 
Item 6.
Exhibits
 
 
 
 
 
 
Signatures
 
 
 
 
 
 
Index to Exhibits
 


2


GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:
AFUDC
Allowance for Funds Used During Construction
AOCI
Accumulated Other Comprehensive Income (Loss)
ASU
Accounting Standards Update issued by the FASB
Bbl
Barrel
BHC
Black Hills Corporation; the Company
Black Hills Electric Generation
Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy
The name used to conduct the business of Black Hills Utility Holdings, Inc., and its subsidiaries
Black Hills Non-regulated Holdings
Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Power
Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings
Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Wyoming
Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Btu
British thermal unit
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation
Cheyenne Prairie
Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility jointly owned by Black Hills Power and Cheyenne Light in Cheyenne, Wyoming. Cheyenne Prairie was placed into commercial service on October 1, 2014.
Colorado Electric
Black Hills Colorado Electric Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado IPP
Black Hills Colorado IPP, LLC a direct wholly-owned subsidiary of Black Hills Electric Generation
CPCN
Certificate of Public Convenience and Necessity
CPUC
Colorado Public Utilities Commission
CVA
Credit Valuation Adjustment
Dodd-Frank
Dodd-Frank Wall Street Reform and Consumer Protection Act
Dth
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
Energy West
Energy West Wyoming, Inc., a subsidiary of Gas Natural, Inc.
FASB
Financial Accounting Standards Board
Fitch
Fitch Ratings
GAAP
Accounting principles generally accepted in the United States of America
GHG
Greenhouse Gases
GCA
Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of natural gas and certain services through to customers.
Global Settlement
Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders.
Heating Degree Day
A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
IFRS
International Financial Reporting Standards

3


Iowa Gas
Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP
Independent power producer
IRS
United States Internal Revenue Service
IUB
Iowa Utilities Board
Kansas Gas
Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
KCC
Kansas Corporation Commission
kV
Kilovolt
LIBOR
London Interbank Offered Rate
LOE
Lease Operating Expense
Mcf
Thousand cubic feet
Mcfe
Thousand cubic feet equivalent.
MMBtu
Million British thermal units
Moody’s
Moody’s Investors Service, Inc.
MW
Megawatts
MWh
Megawatt-hours
NGL
Natural Gas Liquids (1 barrel equals 6 Mcfe)
NPSC
Nebraska Public Service Commission
PPA
Power Purchase Agreement
Revolving Credit Facility
Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which matures in 2019.
SDPUC
South Dakota Public Utilities Commission
SEC
U. S. Securities and Exchange Commission
S&P
Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
WPSC
Wyoming Public Service Commission
WRDC
Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings

4




BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(unaudited)
Three Months Ended
March 31,
 
2015
2014
 
(in thousands, except per share amounts)
 
 
 
Revenue
$
441,987

$
460,169

 
 
 
Operating expenses:
 
 
Utilities -
 
 
Fuel, purchased power and cost of natural gas sold
205,327

230,468

Operations and maintenance
71,084

71,227

Non-regulated energy operations and maintenance
22,050

22,332

Depreciation, depletion and amortization
39,586

36,083

Taxes - property, production and severance
11,936

10,336

Other operating expenses
52

125

Total operating expenses
350,035

370,571

 
 
 
Operating income
91,952

89,598

 
 
 
Other income (expense):
 
 
Interest charges -
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)
(19,910
)
(17,860
)
Allowance for funds used during construction - borrowed
158

270

Capitalized interest
276

257

Interest income
448

390

Allowance for funds used during construction - equity
56

238

Other income (expense), net
331

592

Total other income (expense), net
(18,641
)
(16,113
)
 
 
 
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes
73,311

73,485

Equity in earnings (loss) of unconsolidated subsidiaries
(297
)
(1
)
Income tax benefit (expense)
(25,120
)
(25,366
)
Net income (loss) available for common stock
$
47,894

$
48,118

 
 
 
Earnings (loss) per share of common stock:
 
 
Earnings (loss) per share, Basic
$
1.08

$
1.09

Earnings (loss) per share, Diluted
$
1.07

$
1.08

Weighted average common shares outstanding:
 
 
Basic
44,541

44,330

Diluted
44,660

44,554

 
 
 
Dividends declared per share of common stock
$
0.405

$
0.390


The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

5




BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)


(unaudited)
Three Months Ended
March 31,
 
2015
2014
 
(in thousands)
 
 
 
Net income (loss) available for common stock
$
47,894

$
48,118

 
 
 
Other comprehensive income (loss), net of tax:
 
 
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $(1,042) and $1,307 for the three months ended 2015 and 2014, respectively)
1,836

(2,257
)
Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $1,254 and $(425) for the three months ended 2015 and 2014, respectively)
(1,241
)
780

Benefit plan liability adjustments - net gain (loss) (net of tax (expense) benefit of $15 and $2 for the three months ended 2015 and 2014, respectively)
(27
)
(2
)
Benefit plan liability adjustments - prior service cost (net of tax (expense) benefit of $(90) for the three months ended 2014
—

164

Reclassification adjustments of benefit plan liability - prior service cost (net of tax (expense) benefit of $19 and $4 for the three months ended 2015 and 2014, respectively)
(36
)
(9
)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(247) and $(85) for the three months ended 2015 and 2014, respectively)
458

157

Other comprehensive income (loss), net of tax
990

(1,167
)
 
 
 
Comprehensive income (loss) available for common stock
$
48,884

$
46,951


See Note 11 for additional disclosures.

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

6


BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)
As of
 
March 31,
2015
 
December 31, 2014
 
March 31,
2014
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
63,385

 
$
21,218

 
$
17,641

Restricted cash and equivalents
2,191

 
2,056

 
2

Accounts receivable, net
178,421

 
189,992

 
203,625

Materials, supplies and fuel
66,626

 
91,191

 
66,187

Derivative assets, current
—

 
—

 
1,846

Income tax receivable, net
159

 
2,053

 
1,826

Deferred income tax assets, net, current
23,913

 
48,288

 
25,780

Regulatory assets, current
56,542

 
74,396

 
62,946

Other current assets
47,448

 
24,842

 
24,563

Total current assets
438,685

 
454,036

 
404,416

 
 
 
 
 
 
Investments
17,210

 
17,294

 
16,916

 
 
 
 
 
 
Property, plant and equipment
4,652,058

 
4,563,400

 
4,318,194

Less: accumulated depreciation and depletion
(1,351,857
)
 
(1,324,025
)
 
(1,298,398
)
Total property, plant and equipment, net
3,300,201

 
3,239,375

 
3,019,796

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
353,396

 
353,396

 
353,396

Intangible assets, net
3,121

 
3,176

 
3,342

Regulatory assets, non-current
178,935

 
183,443

 
138,173

Other assets, non-current
28,280

 
29,086

 
28,925

Total other assets, non-current
563,732

 
569,101

 
523,836

 
 
 
 
 
 
TOTAL ASSETS
$
4,319,828

 
$
4,279,806

 
$
3,964,964


The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

7


BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)
As of
 
March 31,
2015
 
December 31, 2014
 
March 31,
2014
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
88,770

 
$
124,139

 
$
149,681

Accrued liabilities
166,781

 
170,115

 
145,973

Derivative liabilities, current
3,342

 
3,340

 
3,498

Regulatory liabilities, current
17,621

 
3,687

 
583

Notes payable
102,600

 
75,000

 
100,000

Current maturities of long-term debt
—

 
275,000

 
—

Total current liabilities
379,114

 
651,281

 
399,735

 
 
 
 
 
 
Long-term debt, net of current maturities
1,542,658

 
1,267,589

 
1,396,949

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
522,290

 
523,716

 
466,856

Derivative liabilities, non-current
2,143

 
2,680

 
4,805

Regulatory liabilities, non-current
148,918

 
145,144

 
116,793

Benefit plan liabilities
162,334

 
158,966

 
113,324

Other deferred credits and other liabilities
154,604

 
154,406

 
129,083

Total deferred credits and other liabilities
990,289

 
984,912

 
830,861

 
 
 
 
 
 
Commitments and contingencies (See Notes 7, 8, 13, 14)


 

 

 
 
 
 
 
 
Stockholders’ equity:
 
 
 
 
 
Common stock equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 44,856,790; 44,714,072; and 44,666,953 shares, respectively
44,857

 
44,714

 
44,667

Additional paid-in capital
749,517

 
748,840

 
742,016

Retained earnings
629,135

 
599,389

 
570,963

Treasury stock, at cost – 33,755; 42,226; and 37,038 shares, respectively
(1,688
)
 
(1,875
)
 
(1,638
)
Accumulated other comprehensive income (loss)
(14,054
)
 
(15,044
)
 
(18,589
)
Total stockholders’ equity
1,407,767

 
1,376,024

 
1,337,419

 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
4,319,828

 
$
4,279,806

 
$
3,964,964


The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

8


BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Three Months Ended March 31,
 
2015
2014
Operating activities:
(in thousands)
Net income (loss) available for common stock
$
47,894

$
48,118

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
39,586

36,083

Deferred financing cost amortization
519

568

Stock compensation
2,083

3,716

Deferred income taxes
22,048

25,953

Employee benefit plans
5,283

3,703

Other adjustments, net
6,748

5,190

Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
25,689

22,291

Accounts receivable, unbilled revenues and other operating assets
47,947

(78,576
)
Accounts payable and other operating liabilities
(44,652
)
29,074

Other operating activities, net
(1,658
)
1,978

Net cash provided by (used in) operating activities
151,487

98,098

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(117,523
)
(83,609
)
Other investing activities
(348
)
(3,220
)
Net cash provided by (used in) investing activities
(117,871
)
(86,829
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(18,148
)
(17,399
)
Common stock issued
999

881

Short-term borrowings - issuances
77,700

86,800

Short-term borrowings - repayments
(50,100
)
(69,300
)
Other financing activities
(1,900
)
(2,451
)
Net cash provided by (used in) financing activities
8,551

(1,469
)
Net change in cash and cash equivalents
42,167

9,800

Cash and cash equivalents, beginning of period
21,218

7,841

Cash and cash equivalents, end of period
$
63,385

$
17,641


See Note 12 for supplemental disclosure of cash flow information.

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these Condensed Consolidated Financial Statements.

9


BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2014 Annual Report on Form 10-K)

(1)    MANAGEMENT’S STATEMENT

The unaudited Condensed Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company,” “us,” “we,” or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Condensed Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2014 Annual Report on Form 10-K filed with the SEC.

We conduct our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation, Coal Mining and Oil and Gas. Our reportable segments are based on our method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. All of our operations and assets are located within the United States.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying Condensed Consolidated Financial Statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the March 31, 2015, December 31, 2014, and March 31, 2014 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market price. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2015 and March 31, 2014, and our financial condition as of March 31, 2015, December 31, 2014, and March 31, 2014, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period. All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

Recently Issued and Adopted Accounting Standards

We have implemented all new accounting pronouncements that are in effect and may impact our financial statements. We are currently assessing the impact any other new accounting pronouncements that have been issued may have on our financial position, results of operations, or cash flows.

Simplifying the Presentation of Debt Issuance Costs, ASU 2015-03

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as an asset. Amortization of these costs will continue to be reported as interest expense. ASU 2015-03 is effective for annual and interim reporting periods beginning after December 15, 2015. Early adoption is permitted. We are currently evaluating the impact of adoption that ASU 2015-03 will have on our financial position, results of operations, or cash flows.


10


Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. On April 1, 2015, FASB voted to propose to defer the effective date of ASU 2014-09 by one year. The proposed guidance would be effective for annual and interim reporting periods beginning after December 15, 2017 and early adoption is permitted. We are currently assessing the impact, if any, that ASU 2014-09 will have on our financial position, results of operations or cash flows.


(2)    BUSINESS SEGMENT INFORMATION

Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) were as follows (in thousands):
Three Months Ended March 31, 2015
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
182,974

 
$
3,424

 
$
18,929

   Gas
 
237,651

 
—

 
22,212

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,953

 
20,721

 
8,145

   Coal Mining
 
8,142

 
7,792

 
3,010

   Oil and Gas
 
11,267

 
—

 
(5,071
)
Corporate activities
 
—

 
—

 
669

Inter-company eliminations
 
—

 
(31,937
)
 
—

Total
 
$
441,987

 
$
—

 
$
47,894


Three Months Ended March 31, 2014
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
178,095

 
$
4,007

 
$
14,575

   Gas
 
259,337

 
—

 
24,698

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,269

 
21,079

 
8,073

   Coal Mining
 
6,618

 
8,880

 
2,464

   Oil and Gas
 
14,850

 
—

 
(2,022
)
Corporate activities
 
—

 
—

 
330

Inter-company eliminations
 
—

 
(33,966
)
 
—

Total
 
$
460,169

 
$
—

 
$
48,118


 
 
 
 
 
 
 
 
 
 
 
 
 
 


11


Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
Total Assets (net of inter-company eliminations) as of:
March 31, 2015
 
December 31, 2014
 
March 31, 2014
Utilities:
 
 
 
 
 
   Electric (a)
$
2,817,423

 
$
2,748,680

 
$
2,572,616

   Gas
839,802

 
906,922

 
842,660

Non-regulated Energy:
 
 
 
 
 
   Power Generation (a)
75,945

 
76,945

 
90,643

   Coal Mining
77,399

 
74,407

 
74,523

   Oil and Gas
403,657

 
366,247

 
295,083

Corporate activities
105,602

 
106,605

 
89,439

Total assets
$
4,319,828

 
$
4,279,806

 
$
3,964,964

__________
(a)
The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation Station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.


(3)    ACCOUNTS RECEIVABLE

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
Accounts
Unbilled
Less Allowance for
Accounts
March 31, 2015
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
53,862

$
24,540

$
(834
)
$
77,568

Gas Utilities
63,252

28,785

(1,588
)
90,449

Power Generation
1,152

—

—

1,152

Coal Mining
3,638

—

—

3,638

Oil and Gas
4,646

—

(13
)
4,633

Corporate
981

—

—

981

Total
$
127,531

$
53,325

$
(2,435
)
$
178,421


 
Accounts
Unbilled
Less Allowance for
Accounts
December 31, 2014
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
59,714

$
26,474

$
(722
)
$
85,466

Gas Utilities
47,394

45,546

(781
)
92,159

Power Generation
1,369

—

—

1,369

Coal Mining
3,151

—

—

3,151

Oil and Gas
5,305

—

(13
)
5,292

Corporate
2,555

—

—

2,555

Total
$
119,488

$
72,020

$
(1,516
)
$
189,992



12


 
Accounts
Unbilled
Less Allowance for
Accounts
March 31, 2014
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
53,733

$
20,063

$
(690
)
$
73,106

Gas Utilities
77,982

35,791

(814
)
112,959

Power Generation
1,340

—

—

1,340

Coal Mining
2,616

—

—

2,616

Oil and Gas
10,920

—

(13
)
10,907

Corporate
2,697

—

—

2,697

Total
$
149,288

$
55,854

$
(1,517
)
$
203,625


(4)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands):
 
Maximum
As of
As of
As of
 
Amortization (in years)
March 31, 2015
December 31, 2014
March 31, 2014
Regulatory assets
 
 
 
 
Deferred energy and fuel cost adjustments - current (a) (d)
1
$
30,833

$
23,820

$
23,935

Deferred gas cost adjustments (a)(d)
2
6,138

37,471

38,505

Gas price derivatives (a)
7
21,606

18,740

4,420

AFUDC (b)
45
12,114

12,358

12,349

Employee benefit plans (c) (e)
12
97,700

97,126

65,833

Environmental (a)
subject to approval
1,240

1,314

1,317

Asset retirement obligations (a)
44
3,237

3,287

3,271

Bond issue cost (a)
23
3,240

3,276

3,383

Renewable energy standard adjustment (a)
5
5,590

9,622

16,088

Flow through accounting (c)
35
26,835

25,887

21,837

Decommissioning costs
10
13,702

12,484

—

Other regulatory assets (a)
15
13,242

12,454

10,181

 
 
$
235,477

$
257,839

$
201,119

 
 
 
 
 
Regulatory liabilities
 
 
 
 
Deferred energy and gas costs (a) (d)
1
$
18,094

$
6,496

$
6,485

Employee benefit plans (c) (e)
12
53,151

53,139

34,355

Cost of removal (a)
44
81,449

78,249

67,640

Other regulatory liabilities (c)
25
13,845

10,947

8,896

 
 
$
166,539

$
148,831

$
117,376

__________
(a)
Recovery of costs, but we are not allowed a rate of return.
(b)
In addition to recovery of costs, we are allowed a rate of return.
(c)
In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.
(d)
Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric and gas utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. Fluctuations in deferred gas cost adjustments compared to the same period in the prior year are primarily due to higher natural gas prices driven by demand and market conditions from the peak winter heating season in the first part of 2014. Our electric and gas utilities file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.
(e)
Increase compared to March 31, 2014 is due to a decrease in the discount rate and a change in the mortality tables used in employee benefit plan estimates.

13



(5)    MATERIALS, SUPPLIES AND FUEL

The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
March 31, 2015
 
December 31, 2014
 
March 31, 2014
Materials and supplies
$
52,429

 
$
49,555

 
$
50,727

Fuel - Electric Utilities
6,780

 
6,637

 
7,218

Natural gas in storage held for distribution
7,417

 
34,999

 
8,242

Total materials, supplies and fuel
$
66,626

 
$
91,191

 
$
66,187



(6)    EARNINGS PER SHARE

A reconciliation of share amounts used to compute Earnings (loss) per share in the accompanying Condensed Consolidated Statements of Income (loss) is as follows (in thousands):
 
Three Months Ended March 31,
 
2015
2014
 
 
 
Net income (loss) available for common stock
$
47,894

$
48,118

 
 
 
Weighted average shares - basic
44,541

44,330

Dilutive effect of:
 
 
Equity compensation
119

224

Weighted average shares - diluted
44,660

44,554


The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):
 
Three Months Ended March 31,
 
2015
2014
 
 
 
Equity compensation
107

46

Anti-dilutive shares
107

46



14



(7)    NOTES PAYABLE AND LONG-TERM DEBT

We had the following short-term debt outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
March 31, 2015
December 31, 2014
March 31, 2014
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$
102,600

$
22,300

$
75,000

$
35,000

$
100,000

$
27,700


Revolving Credit Facility

On May 29, 2014, we amended our $500 million corporate Revolving Credit Facility agreement to extend the term through May 29, 2019. This facility is substantially similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to $750 million. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from S&P and Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125%, 1.125%, and 1.125%, respectively at March 31, 2015. A commitment fee is charged on the unused amount of the Revolving Credit Facility and was 0.175% based on our credit rating.

Replacement of Corporate Term Loan

On April 13, 2015, we entered into a new $300 million Corporate term loan expiring April 12, 2017. This new term loan replaced the $275 million Corporate term loan due on June 19, 2015. In accordance with the terms of the agreement, the $275 million Corporate term loan is classified as Long-Term Debt as of March 31, 2015. The additional $25 million, less interest and fees, will be used for general corporate purposes. The cost of the borrowing under the new term loan is LIBOR plus a margin of 0.9%. The covenants on the new term loan are substantially the same as the revolving credit facility.

Debt Covenants

Our Revolving Credit Facility and our Term Loan require compliance with the following financial covenant at the end of each quarter:
 
As of March 31, 2015
 
Covenant Requirement
Recourse Leverage Ratio
55%
 
Less than
65%

As of March 31, 2015, we were in compliance with this covenant.

(8)    RISK MANAGEMENT ACTIVITIES

Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operation of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures as discussed in our 2014 Annual Report on Form 10-K.

Market Risk

Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks including, but not limited to:

•
Commodity price risk associated with our natural long position in crude oil and natural gas reserves and production; and our fuel procurement for certain of our gas-fired generation assets; and

•
Interest rate risk associated with our variable-rate debt.


15


Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and other security agreements.

We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified.

Our derivative and hedging activities recorded in the accompanying Condensed Consolidated Balance Sheets, Condensed Consolidated Statements of Income (Loss) and Condensed Consolidated Statements of Comprehensive Income (Loss) are detailed below and in Note 9.

Oil and Gas

We produce natural gas, NGLs and crude oil through our exploration and production activities. Our natural long positions, or unhedged open positions, result in commodity price risk and variability to our cash flows.

To mitigate commodity price risk and preserve cash flows, we primarily use exchange traded futures and related options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on these instruments. These transactions were designated at inception as cash flow hedges, documented under accounting standards for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.

The derivatives were marked to fair value and were recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. The effective portion of the gain or loss on these derivatives for which we have elected cash flow hedge accounting is reported in AOCI in the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue in the accompanying Condensed Consolidated Statements of Income (Loss).

The contract or notional amounts, terms of our commodity derivatives, and the derivative balances for our Oil and Gas segment reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:
 
March 31, 2015
 
December 31, 2014
 
March 31, 2014
 
Crude Oil Futures, Swaps and Options
Natural Gas Futures and Swaps
 
Crude Oil Futures, Swaps and Options
Natural Gas Futures and Swaps
 
Crude Oil Futures, Swaps and Options
Natural Gas Futures and Swaps
Notional (a)
305,000

5,367,500

 
334,500

6,582,500

 
442,500

8,296,250

Maximum terms in months (b)
1

1

 
1

1

 
1

1

Derivative assets, current
$
—

$
—

 
$
—

$
—

 
$
—

$
—

Derivative assets, non-current
$
—

$
—

 
$
—

$
—

 
$
—

$
—

Derivative liabilities, current
$
—

$
—

 
$
—

$
—

 
$
—

$
—

Derivative liabilities, non-current
$
—

$
—

 
$
—

$
—

 
$
—

$
—

__________
(a)
Crude oil in Bbls, natural gas in MMBtus.
(b)
Refers to the tenor of the derivative instrument. Assets and liabilities are classified as current/non-current based on the production month hedged and the corresponding settlement of the derivative instrument.
Based on March 31, 2015, prices a $9.9 million gain would be reclassified from AOCI over the next 12 months. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.


16


Utilities

The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used for Electric Utility generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. Unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Condensed Consolidated Balance Sheets in accordance with state commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Condensed Consolidated Statements of Income (Loss), or the Condensed Consolidated Statements of Comprehensive Income (Loss).


The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities were as follows, as of:
 
March 31, 2015
 
December 31, 2014
 
March 31, 2014
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
Natural gas futures purchased
17,280,000

 
69
 
19,370,000

 
72
 
16,140,000

 
80
Natural gas options purchased
1,320,000

 
12
 
4,020,000

 
8
 
1,320,000

 
12
Natural gas basis swaps purchased
15,735,000

 
57
 
12,005,000

 
60
 
14,575,000

 
69
__________
(a) Term reflects the maximum forward period hedged.

We had the following derivative balances related to the hedges in our Utilities reflected in our Condensed Consolidated Balance Sheets as of (in thousands):
 
March 31, 2015
December 31, 2014
March 31, 2014
Derivative assets, current
$
—

$
—

$
1,846

Derivative assets, non-current
$
—

$
—

$
—

Derivative liabilities, non-current
$
—

$
—

$
—

Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities
$
21,606

$
18,740

$
4,420



17


Financing Activities

We entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Condensed Consolidated Balance Sheets were as follows (dollars in thousands) as of:
 
March 31, 2015
 
December 31, 2014
 
March 31, 2014
 
Interest Rate
Swaps (a)
 
Interest Rate
Swaps (a)
 
Interest Rate
Swaps (a)
Notional
$
75,000

 
$
75,000

 
$
75,000

Weighted average fixed interest rate
4.97
%
 
4.97
%
 
4.97
%
Maximum terms in years
1.75

 
2.00

 
2.75

Derivative liabilities, current
$
3,342

 
$
3,340

 
$
3,498

Derivative liabilities, non-current
$
2,143

 
$
2,680

 
$
4,805

__________
(a)
These swaps are designated to borrowings on our Revolving Credit Facility, and are priced using three-month LIBOR, matching the floating portion of the related borrowings.

Based on March 31, 2015, market interest rates and balances related to our interest rate swaps, a loss of approximately $3.3 million would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market interest rates change.

Cash Flow Hedges

The impacts of cash flow hedges on our Condensed Consolidated Statements of Income (Loss) were as follows (in thousands):
Three Months Ended March 31, 2015
Derivatives in Cash Flow Hedging Relationships
 
Amount of
Gain/(Loss)
Recognized
in AOCI
Derivative
(Effective
Portion)
 
Location
of Gain/(Loss)
Reclassified
from AOCI
into Income
(Effective
Portion)
 
Amount of
Reclassified
Gain/(Loss)
from AOCI
into Income
(Effective
Portion)
 
Location of
Gain/(Loss)
Recognized
in Income
on Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps
 
$
(886
)
 
Interest expense
 
$
1,437

 
 
 
$
—

Commodity derivatives
 
3,764

 
Revenue
 
(3,932
)
 
 
 
—

Total
 
$
2,878

 
 
 
$
(2,495
)
 
 
 
$
—


Three Months Ended March 31, 2014
Derivatives in Cash Flow Hedging Relationships
 
Amount of
Gain/(Loss)
Recognized
in AOCI
Derivative
(Effective
Portion)
 
Location
of Gain/(Loss)
Reclassified
from AOCI
into Income
(Effective
Portion)
 
Amount of
Reclassified
Gain/(Loss)
from AOCI
into Income
(Effective
Portion)
 
Location of
Gain/(Loss)
Recognized
in Income
on Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps
 
$
(91
)
 
Interest expense
 
$
(894
)
 
 
 
$
—

Commodity derivatives
 
(3,473
)
 
Revenue
 
(311
)
 
 
 
—

Total
 
$
(3,564
)
 
 
 
$
(1,205
)
 
 
 
$
—


 
 
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 
 
 


18



(9)    FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. This guidance establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. For additional information see Notes 1, 8, 9 and 10 to the Consolidated Financial Statements included in our 2014 Annual Report on Form 10-K filed with the SEC.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Valuation Methodologies for Derivatives

Oil and Gas Segment:

•
The commodity contracts for our Oil and Gas segment are valued using the market approach and include exchange-traded futures and basis swaps. Fair value was derived using exchange quoted settlement prices from third party brokers for similar instruments as to quantity and timing. The prices are then validated through third-party sources and therefore support Level 2 disclosure.

Utilities Segments:

•
The commodity contracts for our Utilities Segments, valued using the market approach, include exchange-traded futures, options and basis swaps (Level 2) for natural gas contracts. For Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments.

Corporate Activities:

•
The interest rate swaps are valued using the market approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting a Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings.


19


Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances. Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties.

The following tables set forth by level within the fair value hierarchy our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. A discussion of fair value of financial instruments is included in Note 10:

 
As of March 31, 2015
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 


    Options -- Oil
$
—

$
—

$
—

 
$
—

$
—

    Basis Swaps -- Oil
—

8,096

—

 
(8,096
)
—

    Options -- Gas
—

—

—

 
—

—

    Basis Swaps -- Gas
—

6,526

—

 
(6,526
)
—

Commodity derivatives — Utilities
—

1,184

—

 
(1,184
)
—

Total
$
—

$
15,806

$
—

 
$
(15,806
)
$
—

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 


Options -- Oil
$
—

$
—

$
—

 
$
—

$
—

Basis Swaps -- Oil
—

2

—

 
(2
)
—

Options -- Gas
—

—

—

 
—

—

Basis Swaps -- Gas
—

256

—

 
(256
)
—

Commodity derivatives — Utilities
—

22,002

—

 
(22,002
)
—

Interest rate swaps
—

5,485

—

 
—

5,485

Total
$
—

$
27,745

$
—

 
$
(22,260
)
$
5,485




20



 
As of December 31, 2014
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
Options -- Oil
$
—

$
—

$
—

 
$
—

$
—

Basis Swaps -- Oil
—

8,599

—

 
(8,599
)
—

Options -- Gas
—

—

—

 
—

—

Basis Swaps -- Gas
—

6,558

—

 
(6,558
)
—

Commodity derivatives —Utilities
—

2,389

—

 
(2,389
)
—

Total
$
—

$
17,546

$
—

 
$
(17,546
)
$
—

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
Options -- Oil
$
—

$
—

$
—

 
$
—

$
—

Basis Swaps -- Oil
—

—

—

 
—

—

Options -- Gas
—

—

—

 
—

—

Basis Swaps -- Gas
—

473

—

 
(473
)
—

Commodity derivatives — Utilities
—

19,303

—

 
(19,303
)
—

Interest rate swaps
—

6,020

—

 
—

6,020

Total
$
—

$
25,796

$
—

 
$
(19,776
)
$
6,020



 
As of March 31, 2014
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
Options -- Oil
$
—

$
—

$
—

 
$
—

$
—

Basis Swaps -- Oil
—

7

—

 
(7
)
—

Options -- Gas
—

—

—

 
—

—

Basis Swaps -- Gas
—

490

—

 
(490
)
—

Commodity derivatives — Utilities
—

3,226

—

 
(1,380
)
1,846

Total
$
—

$
3,723

$
—

 
$
(1,877
)
$
1,846

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
Options -- Oil
$
—

$
—

$
—

 
$
—

$
—

Basis Swaps -- Oil
—

1,983

—

 
(1,983
)
—

Options -- Gas
—

—

—

 
—

—

Basis Swaps -- Gas
—

2,114

—

 
(2,114
)
—

Commodity derivatives — Utilities
—

6,919

—

 
(6,919
)
—

Interest rate swaps
—

8,303

—

 
—

8,303

Total
$
—

$
19,319

$
—

 
$
(11,016
)
$
8,303



21



Fair Value Measures by Balance Sheet Classification

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis reflecting the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions; however, the amounts do not include net cash collateral on deposit in margin accounts at March 31, 2015, December 31, 2014, and March 31, 2014, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not agree with the amounts presented on our Condensed Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 8.

The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):
As of March 31, 2015
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
9,989

$
—

Commodity derivatives
Derivative assets — non-current
 
4,633

—

Commodity derivatives
Derivative liabilities — current
 
—

126

Commodity derivatives
Derivative liabilities — non-current
 
—

132

Interest rate swaps
Derivative liabilities — current
 
—

3,342

Interest rate swaps
Derivative liabilities — non-current
 
—

2,143

Total derivatives designated as hedges
 
 
$
14,622

$
5,743

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
—

$
—

Commodity derivatives
Derivative assets — non-current
 
—

—

Commodity derivatives
Derivative liabilities — current
 
—

7,530

Commodity derivatives
Derivative liabilities — non-current
 
—

13,288

Total derivatives not designated as hedges
 
 
$
—

$
20,818


As of December 31, 2014
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
10,391

$
—

Commodity derivatives
Derivative assets — non-current
 
4,766

—

Commodity derivatives
Derivative liabilities — current
 
—

185

Commodity derivatives
Derivative liabilities — non-current
 
—

288

Interest rate swaps
Derivative liabilities — current
 
—

3,340

Interest rate swaps
Derivative liabilities — non-current
 
—

2,680

Total derivatives designated as hedges
 
 
$
15,157

$
6,493

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
—

$
—

Commodity derivatives
Derivative assets — non-current
 
—

—

Commodity derivatives
Derivative liabilities — current
 
—

8,032

Commodity derivatives
Derivative liabilities — non-current
 
—

8,882

Total derivatives not designated as hedges
 
 
$
—

$
16,914



22


As of March 31, 2014
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
30

$
—

Commodity derivatives
Derivative assets — non-current
 
466

—

Commodity derivatives
Derivative liabilities — current
 
—

3,187

Commodity derivatives
Derivative liabilities — non-current
 
—

910

Interest rate swaps
Derivative liabilities — current
 
—

3,498

Interest rate swaps
Derivative liabilities — non-current
 
—

4,805

Total derivatives designated as hedges
 
 
$
496

$
12,400

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
1,846

$
—

Commodity derivatives
Derivative assets — non-current
 
—

—

Commodity derivatives
Derivative liabilities — current
 
—

—

Commodity derivatives
Derivative liabilities — non-current
 
—

5,539

Interest rate swaps
Derivative liabilities — current
 
—

—

Interest rate swaps
Derivative liabilities — non-current
 
—

—

Total derivatives not designated as hedges
 
 
$
1,846

$
5,539

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



23



(10)    FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 9, were as follows (in thousands) as of:
 
March 31, 2015
 
December 31, 2014
 
March 31, 2014
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
Cash and cash equivalents (a)
$
63,385

$
63,385

 
$
21,218

$
21,218

 
$
17,641

$
17,641

Restricted cash and equivalents (a)
$
2,191

$
2,191

 
$
2,056

$
2,056

 
$
2

$
2

Notes payable (a)
$
102,600

$
102,600

 
$
75,000

$
75,000

 
$
100,000

$
100,000

Long-term debt, including current maturities (b)
$
1,542,658

$
1,767,113

 
$
1,542,589

$
1,734,555

 
$
1,396,949

$
1,541,727

__________
(a)
Carrying value approximates fair value due to either the short-term length of maturity or variable interest rates that approximate prevailing market rates, and therefore is classified in Level 1 in the fair value hierarchy.
(b)
Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

(11)
OTHER COMPREHENSIVE INCOME (LOSS)

The components of the reclassification adjustments, net of tax, included in Other Comprehensive Income (Loss) for the periods were as follows (in thousands):
 
Location on the Condensed Consolidated Statements of Income (Loss)
Amount Reclassified from AOCI
Three Months Ended
March 31, 2015
March 31, 2014
Gains (losses) on cash flow hedges:
 
 
 
Interest rate swaps
Interest expense
$
1,437

$
894

Commodity contracts
Revenue
(3,932
)
311

 
 
(2,495
)
1,205

Income tax
Income tax benefit (expense)
1,254

(425
)
Reclassification adjustments related to cash flow hedges, net of tax
 
$
(1,241
)
$
780

 
 
 
 
Amortization of defined benefit plans:
 
 
 
Prior service cost
Utilities - Operations and maintenance
$
(27
)
$
(25
)
 
Non-regulated energy operations and maintenance
(28
)
12

 
 
 
 
Actuarial gain (loss)
Utilities - Operations and maintenance
454

157

 
Non-regulated energy operations and maintenance
251

85

 
 
650

229

Income tax
Income tax benefit (expense)
(228
)
(81
)
Reclassification adjustments related to defined benefit plans, net of tax
 
$
422

$
148



24


Balances by classification included within Accumulated other comprehensive income (loss) on the accompanying Condensed Consolidated Balance Sheets are as follows (in thousands):
 
Derivatives Designated as Cash Flow Hedges
Employee Benefit Plans
Total
Balance as of December 31, 2013
$
(7,133
)
$
(10,289
)
$
(17,422
)
Other comprehensive income (loss), net of tax
(1,478
)
311

(1,167
)
Balance as of March 31, 2014
$
(8,611
)
$
(9,978
)
$
(18,589
)
 
 
 
 
Balance as of December 31, 2014
$
5,093

$
(20,137
)
$
(15,044
)
Other comprehensive income (loss), net of tax
595

395

990

Balance as of March 31, 2015
$
5,688

$
(19,742
)
$
(14,054
)


(12)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Three months ended
March 31, 2015
 
March 31, 2014
 
(in thousands)
Non-cash investing and financing activities from continuing operations—
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
33,534

 
$
40,939

Increase (decrease) in capitalized assets associated with asset retirement obligations
$
—

 
$
(2,785
)