BKH 10Q Q2 2014


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 June 30, 2014
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 July 31, 2014
Common stock, $1.00 par value
44,641,421

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 and Six Months Ended June 30, 2014 and 2013
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
 
 
 
   Three and Six Months Ended June 30, 2014 and 2013
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   June 30, 2014, December 31, 2013 and June 30, 2013
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Six Months Ended June 30, 2014 and 2013
 
 
 
 
 
 
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 currently being constructed in Cheyenne, Wyoming by Cheyenne Light and Black Hills Power. Construction is expected to be completed for this 132 megawatt facility in 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
Cooling degree day
A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth 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.
Conflict Minerals
As defined by Dodd-Frank, conflict minerals are cassiterite, columbite-tantalite, gold and wolframite that are mined in the Democratic Republic of the Congo or surrounding countries
CPCN
Certificate of Public Convenience and Necessity
CPUC
Colorado Public Utilities Commission
CT
Combustion turbine
CVA
Credit Valuation Adjustment
De-designated interest rate swaps
The $250 million notional amount interest rate swaps that were originally designated as cash flow hedges under accounting for derivatives and hedges but subsequently de-designated in December 2008. These swaps were settled in November 2013.
Dth
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
EPA
United States Environmental Protection Agency
FASB
Financial Accounting Standards Board
FERC
United States Federal Energy Regulatory Commission
Fitch
Fitch Ratings
GAAP
Accounting principles generally accepted in the United States of America
GCA
Gas Cost Adjustment -- adjustments that allow us to pass the prudently-incurred cost of gas and certain services through to customers.

3



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.
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 (7 Gallons equals 1 Mcfe)
NOAA
National Oceanic and Atmospheric Administration
NOAA Climate Normals
This dataset is produced once every 10 years. This dataset contains daily and monthly normals of temperature, precipitation, snowfall, heating and cooling degree days, frost/freeze dates, and growing degree days calculated from observations at approximately 9,800 stations operated by NOAA’s National Weather Service.
NOL
Net Operating Loss
OTC
Over-the-counter
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
June 30,
Six Months Ended
June 30,
 
2014
2013
2014
2013
 
(in thousands, except per share amounts)
 
 
 
 
 
Revenue
$
283,237

$
279,826

$
743,406

$
660,497

 
 
 
 
 
Operating expenses:
 
 
 
 
Utilities -
 
 
 
 
Fuel, purchased power and cost of natural gas sold
101,331

99,172

331,799

267,345

Operations and maintenance
66,074

64,977

137,301

130,667

Non-regulated energy operations and maintenance
21,350

20,890

43,682

42,219

Depreciation, depletion and amortization
36,712

35,152

72,795

69,933

Taxes - property, production and severance
11,044

10,069

21,380

20,449

Other operating expenses
149

529

274

1,001

Total operating expenses
236,660

230,789

607,231

531,614

 
 
 
 
 
Operating income
46,577

49,037

136,175

128,883

 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)
(17,886
)
(23,369
)
(35,746
)
(47,041
)
Allowance for funds used during construction - borrowed
256

411

526

484

Capitalized interest
246

272

503

538

Unrealized gain (loss) on interest rate swaps, net

18,793


26,249

Interest income
576

475

966

760

Allowance for funds used during construction - equity
293

42

531

242

Other income (expense), net
409

473

1,000

879

Total other income (expense), net
(16,106
)
(2,903
)
(32,220
)
(17,889
)
 
 
 
 
 
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes
30,471

46,134

103,955

110,994

Equity in earnings (loss) of unconsolidated subsidiaries



(86
)
Income tax benefit (expense)
(10,651
)
(15,616
)
(36,017
)
(37,193
)
Net income (loss) available for common stock
$
19,820

$
30,518

$
67,938

$
73,715

 
 
 
 
 
Earnings (loss) per share of common stock:
 
 
 
 
Earnings (loss) per share, Basic -
 
 
 
 
Total income (loss) per share, Basic
$
0.45

$
0.69

$
1.53

$
1.67

Earnings (loss) per share, Diluted -
 
 
 
 
Total income (loss) per share, Diluted
$
0.44

$
0.69

$
1.52

$
1.66

Weighted average common shares outstanding:
 
 
 
 
Basic
44,399

44,172

44,365

44,113

Diluted
44,588

44,412

44,571

44,363

 
 
 
 
 
Dividends paid per share of common stock
$
0.39

$
0.38

$
0.78

$
0.76


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
June 30,
Six Months Ended
June 30,
 
2014
2013
2014
2013
 
(in thousands)
 
 
 
 
 
Net income (loss) available for common stock
$
19,820

$
30,518

$
67,938

$
73,715

 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $1,115 and $(2,174) for the three months ended 2014 and 2013 and $2,422 and $(1,057) for the six months ended 2014 and 2013, respectively)
(1,959
)
3,878

(4,216
)
2,217

Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $(774) and $(647) for the three months ended 2014 and 2013 and $(1,199) and $(883) for the six months ended 2014 and 2013, respectively)
1,403

1,201

2,183

1,669

Benefit plan liability adjustments - net gain (loss) (net of tax of $0 and $0 for the three months ended 2014 and 2013 and $2 and $0 for the six months ended 2014 and 2013, respectively)


(2
)

Benefit plan liability tax adjustments - net gain (loss)
(394
)

(394
)

Benefit plan liability adjustments - prior service cost (net of tax of $0 and $0 for the three months ended 2014 and 2013 and $(90) and $0 for the six months ended 2014 and 2013, respectively)


164


Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $39 and $(268) for the three months ended 2014 and 2013 and $43 and $(251) for the six months ended 2014 and 2013, respectively)
(70
)
364

(79
)
318

Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(91) and $0 for the three months ended 2014 and 2013 and $(176) and $(192) for the six months ended 2014 and 2013, respectively)
168


325

503

Other comprehensive income (loss), net of tax
(852
)
5,443

(2,019
)
4,707

 
 
 
 
 
Comprehensive income (loss) available for common stock
$
18,968

$
35,961

$
65,919

$
78,422


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
 
June 30,
2014
 
December 31, 2013
 
June 30,
2013
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
14,697

 
$
7,841

 
$
30,633

Restricted cash and equivalents
2

 
2

 
7,279

Accounts receivable, net
135,145

 
177,573

 
132,726

Materials, supplies and fuel
81,164

 
88,478

 
73,768

Derivative assets, current
1,737

 
717

 
903

Income tax receivable, net
1,043

 
1,460

 
146

Deferred income tax assets, net, current
23,872

 
18,889

 
38,764

Regulatory assets, current
64,735

 
24,451

 
26,258

Other current assets
21,660

 
25,877

 
27,595

Total current assets
344,055

 
345,288

 
338,072

 
 
 
 
 
 
Investments
17,096

 
16,697

 
16,566

 
 
 
 
 
 
Property, plant and equipment
4,408,291

 
4,259,445

 
4,066,502

Less: accumulated depreciation and depletion
(1,325,660
)
 
(1,269,148
)
 
(1,234,578
)
Total property, plant and equipment, net
3,082,631

 
2,990,297

 
2,831,924

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
353,396

 
353,396

 
353,396

Intangible assets, net
3,286

 
3,397

 
3,508

Regulatory assets, non-current
138,226

 
138,197

 
180,646

Other assets, non-current
31,808

 
27,906

 
22,402

Total other assets, non-current
526,716

 
522,896

 
559,952

 
 
 
 
 
 
TOTAL ASSETS
$
3,970,498

 
$
3,875,178

 
$
3,746,514


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
 
June 30,
2014
 
December 31, 2013
 
June 30,
2013
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
100,098

 
$
130,416

 
$
88,071

Accrued liabilities
141,177

 
151,277

 
135,819

Derivative liabilities, current
3,480

 
3,474

 
69,270

Regulatory liabilities, current
828

 
10,727

 
20,550

Notes payable
132,700

 
82,500

 
100,000

Current maturities of long-term debt
275,000

 

 
255,507

Total current liabilities
653,283

 
378,394

 
669,217

 
 
 
 
 
 
Long-term debt, net of current maturities
1,121,950

 
1,396,948

 
958,559

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
476,059

 
432,287

 
387,674

Derivative liabilities, non-current
4,251

 
5,614

 
12,384

Regulatory liabilities, non-current
119,462

 
109,429

 
129,013

Benefit plan liabilities
116,403

 
111,479

 
177,216

Other deferred credits and other liabilities
137,765

 
133,279

 
129,763

Total deferred credits and other liabilities
853,940

 
792,088

 
836,050

 
 
 
 
 
 
Commitments and contingencies (See Notes 7, 8, 13, 14 and 15)


 

 

 
 
 
 
 
 
Stockholders’ equity:
 
 
 
 
 
Common stock equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 44,682,885; 44,550,239; and 44,516,472 shares, respectively
44,683

 
44,550

 
44,517

Additional paid-in capital
744,505

 
742,344

 
737,729

Retained earnings
573,379

 
540,244

 
532,810

Treasury stock, at cost – 40,951; 50,877; and 42,480 shares, respectively
(1,801
)
 
(1,968
)
 
(1,587
)
Accumulated other comprehensive income (loss)
(19,441
)
 
(17,422
)
 
(30,781
)
Total stockholders’ equity
1,341,325

 
1,307,748

 
1,282,688

 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
3,970,498

 
$
3,875,178

 
$
3,746,514


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)
Six Months Ended June 30,
 
2014
2013
Operating activities:
(in thousands)
Net income (loss) available for common stock
$
67,938

$
73,715

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
72,795

69,933

Deferred financing cost amortization
1,107

2,188

Derivative fair value adjustments
(1,660
)
4,248

Stock compensation
6,908

6,896

Unrealized (gain) loss on interest rate swaps, net

(26,249
)
Deferred income taxes
35,514

36,607

Employee benefit plans
7,409

11,096

Other adjustments, net
1,481

8,967

Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
7,314

8,940

Accounts receivable, unbilled revenues and other operating assets
(5,851
)
28,377

Accounts payable and other operating liabilities
(24,978
)
(26,739
)
Other operating activities, net
5,858

(594
)
Net cash provided by (used in) operating activities
173,835

197,385

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(177,302
)
(147,230
)
Other investing activities
(2,994
)
2,006

Net cash provided by (used in) investing activities
(180,296
)
(145,224
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(34,803
)
(33,774
)
Common stock issued
1,693

2,570

Short-term borrowings - issuances
214,100

133,300

Short-term borrowings - repayments
(163,900
)
(310,300
)
Long-term debt - issuances

275,000

Long-term debt - repayments

(103,786
)
Other financing activities
(3,773
)

Net cash provided by (used in) financing activities
13,317

(36,990
)
Net change in cash and cash equivalents
6,856

15,171

Cash and cash equivalents, beginning of period
7,841

15,462

Cash and cash equivalents, end of period
$
14,697

$
30,633


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 2013 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 2013 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 June 30, 2014, December 31, 2013, and June 30, 2013 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 and six months ended June 30, 2014 and June 30, 2013, and our financial condition as of June 30, 2014, December 31, 2013, and June 30, 2013, 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 and do not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on our financial position, results of operations, or cash flows.

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. ASU 2014-09 is effective for annual and interim reporting periods beginning after December 15, 2016 and early adoption is not 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.



10




(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 June 30, 2014
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
158,740

 
$
3,144

 
$
11,427

   Gas
 
102,499

 

 
1,994

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,267

 
20,713

 
7,194

   Coal Mining
 
5,583

 
9,068

 
2,016

   Oil and Gas
 
15,148

 

 
(1,660
)
Corporate activities
 

 

 
(1,151
)
Inter-company eliminations
 

 
(32,925
)
 

Total
 
$
283,237

 
$

 
$
19,820


Three Months Ended June 30, 2013
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
154,338

 
$
3,694

 
$
10,610

   Gas
 
105,836

 

 
3,192

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,031

 
19,094

 
5,031

   Coal Mining
 
6,807

 
7,511

 
1,973

   Oil and Gas
 
11,814

 

 
(1,964
)
Corporate activities (a)
 

 

 
11,679

Inter-company eliminations
 

 
(30,299
)
 
(3
)
Total
 
$
279,826

 
$

 
$
30,518


Six Months Ended June 30, 2014
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
336,835

 
$
7,151

 
$
26,002

   Gas
 
361,836

 

 
26,692

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
2,536

 
41,792

 
15,267

   Coal Mining
 
12,201

 
17,948

 
4,480

   Oil and Gas
 
29,998

 

 
(3,682
)
Corporate activities
 

 

 
(821
)
Inter-company eliminations
 

 
(66,891
)
 

Total
 
$
743,406

 
$

 
$
67,938


11



Six Months Ended June 30, 2013
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
312,821

 
$
7,841

 
$
22,966

   Gas
 
305,648

 

 
21,675

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
2,053

 
38,432

 
10,675

   Coal Mining
 
12,817

 
15,084

 
3,038

   Oil and Gas
 
27,158

 

 
(2,017
)
Corporate activities (a)
 

 

 
17,378

Inter-company eliminations
 

 
(61,357
)
 

Total
 
$
660,497

 
$

 
$
73,715

__________
(a)
Corporate activities include a $12 million and a $17 million after-tax non-cash mark-to-market gain for the three and six months ended June 30, 2013, respectively on certain interest rate swaps.

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:
June 30, 2014
 
December 31, 2013
 
June 30, 2013
Utilities:
 
 
 
 
 
   Electric (a)
$
2,603,900

 
$
2,525,947

 
$
2,417,952

   Gas
799,365

 
805,617

 
734,337

Non-regulated Energy:
 
 
 
 
 
   Power Generation (a)
85,269

 
95,692

 
108,515

   Coal Mining
73,701

 
78,825

 
82,553

   Oil and Gas
307,837

 
288,366

 
256,855

Corporate activities
100,426

 
80,731

 
146,302

Total assets
$
3,970,498

 
$
3,875,178

 
$
3,746,514

__________
(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.


12



 
(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
June 30, 2014
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
48,333

$
21,716

$
(622
)
$
69,427

Gas Utilities
43,104

9,265

(1,027
)
51,342

Power Generation
1,388



1,388

Coal Mining
1,866



1,866

Oil and Gas
9,123


(13
)
9,110

Corporate
2,012



2,012

Total
$
105,826

$
30,981

$
(1,662
)
$
135,145


 
Accounts
Unbilled
Less Allowance for
Accounts
December 31, 2013
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
52,437

$
23,823

$
(666
)
$
75,594

Gas Utilities
49,162

41,195

(558
)
89,799

Power Generation
1,722



1,722

Coal Mining
1,711



1,711

Oil and Gas
8,156


(13
)
8,143

Corporate
604



604

Total
$
113,792

$
65,018

$
(1,237
)
$
177,573


 
Accounts
Unbilled
Less Allowance for
Accounts
June 30, 2013
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
45,250

$
24,290

$
(630
)
$
68,910

Gas Utilities
38,749

13,192

(1,074
)
50,867

Power Generation
157



157

Coal Mining
2,503



2,503

Oil and Gas
8,373


(19
)
8,354

Corporate
1,935



1,935

Total
$
96,967

$
37,482

$
(1,723
)
$
132,726



13




(4)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands):
 
Maximum
As of
As of
As of
 
Amortization (in years)
June 30, 2014
December 31, 2013
June 30, 2013
Regulatory assets
 
 
 
 
Deferred energy and fuel cost adjustments - current (a)(d)
1
$
29,605

$
16,775

$
15,951

Deferred gas cost adjustments and natural gas price derivatives (a)(d)
7
39,040

12,366

13,090

AFUDC (b)
45
12,468

12,315

12,456

Employee benefit plans (c)
13
65,874

67,059

115,379

Environmental (a)
subject to approval
1,314

1,800

1,798

Asset retirement obligations (a)
44
3,278

3,266

3,257

Bond issue cost (a)
24
3,347

3,419

3,489

Renewable energy standard adjustment (a)
5
14,501

14,186

14,694

Flow through accounting (c)
35
22,754

20,916

17,995

Other regulatory assets (a)
15
10,780

10,546

8,795

 
 
$
202,961

$
162,648

$
206,904

 
 
 
 
 
Regulatory liabilities
 
 
 
 
Deferred energy and gas costs (a)
1
$
6,490

$
11,708

$
22,340

Employee benefit plans (c)
13
34,356

34,431

60,214

Cost of removal (a)
44
70,841

64,970

59,461

Other regulatory liabilities (c)
25
8,603

9,047

7,548

 
 
$
120,290

$
120,156

$
149,563

__________
(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. Increases in the current year balances as of June 30, 2014 are primarily due to higher natural gas prices driven by demand and market conditions during our peak winter heating season. 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.


(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:
 
June 30, 2014
 
December 31, 2013
 
June 30, 2013
Materials and supplies
$
51,925

 
$
50,196

 
$
51,334

Fuel - Electric Utilities
7,679

 
6,213

 
6,817

Natural gas in storage held for distribution
21,560

 
32,069

 
15,617

Total materials, supplies and fuel
$
81,164

 
$
88,478

 
$
73,768



14




(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 June 30,
 
Six Months Ended June 30,
 
2014
2013
 
2014
2013
 
 
 
 
 
 
Net income (loss) available for common stock
$
19,820

$
30,518

 
$
67,938

$
73,715

 
 
 
 
 
 
Weighted average shares - basic
44,399

44,172

 
44,365

44,113

Dilutive effect of:
 
 
 
 
 
Equity compensation
189

240

 
206

250

Weighted average shares - diluted
44,588

44,412

 
44,571

44,363


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 June 30,
 
Six Months Ended June 30,
 
2014
2013
 
2014
2013
 
 
 
 
 
 
Equity compensation
81

28

 
63

34

Anti-dilutive shares
81

28

 
63

34



(7)    NOTES PAYABLE AND CURRENT MATURITIES OF LONG-TERM DEBT

We had the following short-term debt outstanding in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
June 30, 2014
December 31, 2013
June 30, 2013
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$
132,700

$
20,272

$
82,500

$
22,100

$
100,000

$
43,157


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, from May 29, 2014 through June 30, 2014; a reduction of 0.25% for each method of borrowing as compared to the previous arrangement. Borrowings under the facility are primarily Eurodollar based. A commitment fee is charged on the unused amount of the Revolving Credit Facility and was 0.175% based on our credit rating, a reduction of 0.025% compared to the prior arrangement.

Current Maturities Of Long-Term Debt

As of June 30, 2014, our Corporate term loan due June 19, 2015, for $275 million has been re-classified to Current maturities of long-term debt from Long-term debt, net of current maturities.




15





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 June 30, 2014
 
Covenant Requirement
Recourse Leverage Ratio
54%
 
Less than
65%

As of June 30, 2014, 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 2013 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.

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.

As of June 30, 2014, our credit exposure included a $0.5 million exposure to a non-investment grade energy marketing company. The remainder of our credit exposure was concentrated primarily among retail utility customers, investment grade rated companies, cooperative utilities and federal agencies. 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.


16



Oil and Gas

We produce natural gas 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 OTC swaps, 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. 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:
 
June 30, 2014
 
December 31, 2013
 
June 30, 2013
 
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)
424,500

9,265,000

 
412,500

7,082,500

 
520,500

10,712,500

Maximum terms in months (b)
1

1

 
3

1

 
6

1

Derivative assets, current
$

$

 
$
55

$

 
$
610

$
293

Derivative assets, non-current
$

$

 
$

$

 
$

$

Derivative liabilities, current
$

$

 
$

$

 
$
130

$
276

Derivative liabilities, non-current
$

$

 
$

$

 
$

$

__________
(a)
Crude oil in Bbls, natural gas in MMBtus.
(b)
Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the term of the hedged transaction and the corresponding settlement of the derivative instrument.
A $3.4 million loss is included in AOCI at June 30, 2014, and would be realized over the next 12 months if market prices remained equal to June 30, 2014 prices. Future realized gains or losses fluctuate with market prices.

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).

17




The contract or notional amounts and terms of the natural gas derivative commodity instruments held at our Utilities were as follows, as of:
 
June 30, 2014
 
December 31, 2013
 
June 30, 2013
 
Notional
(MMBtus)
 
Maximum
Term
(months)
 
Notional
(MMBtus)
 
Maximum
Term
(months)
 
Notional
(MMBtus)
 
Maximum
Term
(months)
Natural gas futures purchased
16,240,000

 
78
 
17,930,000

 
84
 
13,330,000

 
77
Natural gas options purchased
3,980,000

 
9
 
3,890,000

 
8
 
2,850,000

 
5
Natural gas basis swaps purchased
13,415,000

 
66
 
14,785,000

 
60
 
10,650,000

 
66

We had the following derivative balances related to the hedges in our Utilities reflected in our Condensed Consolidated Balance Sheets as of (in thousands):
 
June 30, 2014
December 31, 2013
June 30, 2013
Derivative assets, current
$
1,737

$
662

$

Derivative assets, non-current
$

$

$

Derivative liabilities, non-current
$

$

$

Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities
$
3,561

$
7,567

$
8,450


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:
 
June 30, 2014
 
December 31, 2013
 
June 30, 2013
 
Interest Rate
Swaps (a)
 
Interest Rate
Swaps (a)
 
Interest Rate
Swaps (b)
De-designated
Interest Rate
Swaps (c)
Notional
$
75,000

 
$
75,000

 
$
150,000

$
250,000

Weighted average fixed interest rate
4.97
%
 
4.97
%
 
5.04
%
5.67
%
Maximum terms in years
2.5

 
3.0

 
3.5

0.5

Derivative liabilities, current
$
3,480

 
$
3,474

 
$
6,965

$
61,899

Derivative liabilities, non-current
$
4,251

 
$
5,614

 
$
12,384

$

__________
(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 debt.
(b)
At June 30, 2013, $75 million of these interest rate swaps were designated to borrowings on our Revolving Credit Facility and $75 million were designated to borrowings on our project financing debt at Black Hills Wyoming. These swaps are priced using three-month LIBOR, matching the floating portion of the related debt. The portion of the swaps that were designated to Black Hills Wyoming were settled during the fourth quarter of 2013 upon repayment of the Black Hills Wyoming project financing.
(c)
These swaps were settled during the fourth quarter of 2013.

Based on June 30, 2014, market interest rates and balances related to our interest rate swaps, a loss of approximately $3.5 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.


18



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 June 30, 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
 
$
(337
)
 
Interest expense
 
$
(926
)
 
 
 
$

Commodity derivatives
 
(2,737
)
 
Revenue
 
(1,251
)
 
 
 

Total
 
$
(3,074
)
 
 
 
$
(2,177
)
 
 
 
$


Three Months Ended June 30, 2013
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
 
$
1,067

 
Interest expense
 
$
(1,820
)
 
 
 
$

Commodity derivatives
 
4,985

 
Revenue
 
(28
)
 
 
 

Total
 
$
6,052

 
 
 
$
(1,848
)
 
 
 
$


Six Months Ended June 30, 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
 
$
(429
)
 
Interest expense
 
$
(1,820
)
 
 
 
$

Commodity derivatives
 
(6,209
)
 
Revenue
 
(1,562
)
 
 
 

Total
 
$
(6,638
)
 
 
 
$
(3,382
)
 
 
 
$


Six Months Ended June 30, 2013
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
 
$
1,048

 
Interest expense
 
$
(3,616
)
 
 
 
$

Commodity derivatives
 
2,226

 
Revenue
 
1,064

 
 
 

Total
 
$
3,274

 
 
 
$
(2,552
)
 
 
 
$



19



 
(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 and 10 to the Consolidated Financial Statements included in our 2013 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 option contracts for our Oil and Gas segment are valued using the market approach and can include calls and puts. Fair value was derived using quoted 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.

The commodity basis swaps for our Oil and Gas segment are valued using the market approach with the instrument’s current forward price strip hedged for the same quantity and date and discounted based on the three-month LIBOR. We utilize observable inputs which support a 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) and OTC basis swaps (Level 3) 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. For Level 3 assets and liabilities, fair value was derived using average price quotes from the OTC contract broker and an independent third-party market participant because these instruments are not traded on an exchange.

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.


20



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 June 30, 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



 


    Options -- Gas



 


    Basis Swaps -- Gas

600


 
(600
)

Commodity derivatives — Utilities

4,342


 
(2,605
)
1,737

Total
$

$
4,942

$

 
$
(3,205
)
$
1,737

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 


Options -- Oil
$

$

$

 
$

$

Basis Swaps -- Oil

4,020


 
(4,020
)

Options -- Gas



 


Basis Swaps -- Gas

2,030


 
(2,030
)

Commodity derivatives — Utilities

5,989


 
(5,989
)

Interest rate swaps

7,731


 

7,731

Total
$

$
19,770

$

 
$
(12,039
)
$
7,731




21




 
As of December 31, 2013
 
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

130


 
(75
)
55

Options -- Gas



 


Basis Swaps -- Gas

815


 
(815
)

Commodity derivatives —Utilities

3,030


 
(2,368
)
662

Total
$

$
3,975

$

 
$
(3,258
)
$
717

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

$

$

 
$

$

Basis Swaps -- Oil

1,229


 
(1,229
)

Options -- Gas



 


Basis Swaps -- Gas

531


 
(531
)

Commodity derivatives — Utilities

9,100


 
(9,100
)

Interest rate swaps

9,088


 

9,088

Total
$

$
19,948

$

 
$
(10,860
)
$
9,088



 
As of June 30, 2013
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
 
(in thousands)
Assets:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
Options -- Oil
$

$
45

$

 
$
(6
)
$
39

Basis Swaps -- Oil

1,109


 
(538
)
571

Options -- Gas



 


Basis Swaps -- Gas

1,882


 
(1,589
)
293

Commodity derivatives — Utilities

1,378


 
(1,378
)

Total
$

$
4,414

$

 
$
(3,511
)
$
903

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

$
181

$

 
$
(98
)
$
83

Basis Swaps -- Oil

350


 
(303
)
47

Options -- Gas



 


Basis Swaps -- Gas

445


 
(169
)
276

Commodity derivatives — Utilities

8,581


 
(8,581
)

Interest rate swaps

87,208


 
(5,960
)
81,248

Total
$

$
96,765

$

 
$
(15,111
)
$
81,654



22




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 June 30, 2014, December 31, 2013, and June 30, 2013, 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 June 30, 2014
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
262

$

Commodity derivatives
Derivative assets — non-current
 
338


Commodity derivatives
Derivative liabilities — current
 

3,702

Commodity derivatives
Derivative liabilities — non-current
 

2,348

Interest rate swaps
Derivative liabilities — current
 

3,480

Interest rate swaps
Derivative liabilities — non-current
 

4,251

Total derivatives designated as hedges
 
 
$
600

$
13,781

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
1,737

$

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 


Commodity derivatives
Derivative liabilities — non-current
 

3,384

Total derivatives not designated as hedges
 
 
$