BKH 10Q Q3 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 September 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 October 31, 2014
Common stock, $1.00 par value
44,655,369

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 Nine Months Ended September 30, 2014 and 2013
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income (Loss) - unaudited
 
 
 
   Three and Nine Months Ended September 30, 2014 and 2013
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   September 30, 2014, December 31, 2013 and September 30, 2013
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Nine Months Ended September 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 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
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.
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.
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)
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

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
PCA
Purchased Cost Adjustment - Adjustments passed through to the customer based on purchased fuel costs that are higher or lower than costs approved in the rate case.
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.
TCA
Transmission Cost Adjustment -- adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
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
September 30,
Nine Months Ended
September 30,
 
2014
2013
2014
2013
 
(in thousands, except per share amounts)
 
 
 
 
 
Revenue
$
272,087

$
259,907

$
1,015,493

$
920,404

 
 
 
 
 
Operating expenses:
 
 
 
 
Utilities -
 
 
 
 
Fuel, purchased power and cost of natural gas sold
84,674

71,503

416,473

338,848

Operations and maintenance
64,245

66,061

201,546

196,728

Non-regulated energy operations and maintenance
20,170

20,484

63,852

62,703

Depreciation, depletion and amortization
37,463

36,135

110,258

106,068

Taxes - property, production and severance
11,082

10,068

32,462

30,517

Other operating expenses
49

90

323

1,091

Total operating expenses
217,683

204,341

824,914

735,955

 
 
 
 
 
Operating income
54,404

55,566

190,579

184,449

 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)
(17,919
)
(23,840
)
(53,665
)
(70,881
)
Allowance for funds used during construction - borrowed
319

347

845

831

Capitalized interest
231

273

734

811

Unrealized gain (loss) on interest rate swaps, net

3,144


29,393

Interest income
575

565

1,541

1,325

Allowance for funds used during construction - equity
297

85

828

327

Other income (expense), net
261

318

1,262

1,197

Total other income (expense), net
(16,236
)
(19,108
)
(48,455
)
(36,997
)
 
 
 
 
 
Income (loss) before earnings (loss) of unconsolidated subsidiaries and income taxes
38,168

36,458

142,124

147,452

Equity in earnings (loss) of unconsolidated subsidiaries


(1
)
(86
)
Income tax benefit (expense)
(11,332
)
(13,334
)
(47,349
)
(50,527
)
Net income (loss) available for common stock
$
26,836

$
23,124

$
94,774

$
96,839

 
 
 
 
 
Earnings (loss) per share of common stock:
 
 
 
 
Earnings (loss) per share, Basic -
 
 
 
 
Total income (loss) per share, Basic
$
0.60

$
0.52

$
2.14

$
2.19

Earnings (loss) per share, Diluted -
 
 
 
 
Total income (loss) per share, Diluted
$
0.60

$
0.52

$
2.13

$
2.18

Weighted average common shares outstanding:
 
 
 
 
Basic
44,415

44,201

44,382

44,143

Diluted
44,608

44,457

44,584

44,395

 
 
 
 
 
Dividends declared per share of common stock
$
0.39

$
0.38

$
1.17

$
1.14


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
September 30,
Nine Months Ended
September 30,
 
2014
2013
2014
2013
 
(in thousands)
 
 
 
 
 
Net income (loss) available for common stock
$
26,836

$
23,124

$
94,774

$
96,839

 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
Fair value adjustments on derivatives designated as cash flow hedges (net of tax (expense) benefit of $(1,840) and $964 for the three months ended 2014 and 2013 and $582 and $(93) for the nine months ended 2014 and 2013, respectively)
3,145

(2,083
)
(1,071
)
134

Reclassification adjustments for cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $(732) and $(586) for the three months ended 2014 and 2013 and $(1,931) and $(1,469) for the nine months ended 2014 and 2013, respectively)
1,328

1,426

3,511

3,095

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 nine months ended 2014 and 2013, respectively)


(2
)

Benefit plan liability tax adjustments - net gain (loss)


(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 nine months ended 2014 and 2013, respectively)


164


Reclassification adjustments of benefit plan liability - prior service cost (net of tax of $17 and $22 for the three months ended 2014 and 2013 and $60 and $66 for the nine months ended 2014 and 2013, respectively)
(31
)
(41
)
(110
)
(123
)
Reclassification adjustments of benefit plan liability - net gain (loss) (net of tax of $(86) and $(242) for the three months ended 2014 and 2013 and $(262) and $(729) for the nine months ended 2014 and 2013, respectively)
160

458

485

1,361

Other comprehensive income (loss), net of tax
4,602

(240
)
2,583

4,467

 
 
 
 
 
Comprehensive income (loss) available for common stock
$
31,438

$
22,884

$
97,357

$
101,306


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
 
September 30,
2014
 
December 31, 2013
 
September 30,
2013
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
11,939

 
$
7,841

 
$
13,637

Restricted cash and equivalents
1,918

 
2

 
6,782

Accounts receivable, net
123,399

 
177,573

 
114,137

Materials, supplies and fuel
105,726

 
88,478

 
95,230

Derivative assets, current

 
717

 
126

Income tax receivable, net
1,268

 
1,460

 
4,539

Deferred income tax assets, net, current
34,756

 
18,889

 
37,163

Regulatory assets, current
68,444

 
24,451

 
30,208

Other current assets
26,502

 
25,877

 
27,075

Total current assets
373,952

 
345,288

 
328,897

 
 
 
 
 
 
Investments
17,144

 
16,697

 
16,612

 
 
 
 
 
 
Property, plant and equipment
4,493,696

 
4,259,445

 
4,152,097

Less: accumulated depreciation and depletion
(1,338,509
)
 
(1,269,148
)
 
(1,258,450
)
Total property, plant and equipment, net
3,155,187

 
2,990,297

 
2,893,647

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
353,396

 
353,396

 
353,396

Intangible assets, net
3,231

 
3,397

 
3,453

Regulatory assets, non-current
140,422

 
138,197

 
183,119

Derivative assets, non-current

 

 

Other assets, non-current
29,930

 
27,906

 
22,116

Total other assets, non-current
526,979

 
522,896

 
562,084

 
 
 
 
 
 
TOTAL ASSETS
$
4,073,262

 
$
3,875,178

 
$
3,801,240


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
 
September 30,
2014
 
December 31, 2013
 
September 30,
2013
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
100,444

 
$
130,416

 
$
77,077

Accrued liabilities
163,374

 
151,277

 
152,911

Derivative liabilities, current
3,397

 
3,474

 
65,944

Regulatory liabilities, current
828

 
10,727

 
14,707

Notes payable
184,000

 
82,500

 
138,300

Current maturities of long-term debt
275,000

 

 
255,694

Total current liabilities
727,043

 
378,394

 
704,633

 
 
 
 
 
 
Long-term debt, net of current maturities
1,107,519

 
1,396,948

 
955,979

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
506,166

 
432,287

 
403,772

Derivative liabilities, non-current
3,273

 
5,614

 
11,388

Regulatory liabilities, non-current
118,856

 
109,429

 
131,730

Benefit plan liabilities
108,924

 
111,479

 
169,448

Other deferred credits and other liabilities
144,089

 
133,279

 
133,341

Total deferred credits and other liabilities
881,308

 
792,088

 
849,679

 
 
 
 
 
 
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 44,696,670; 44,550,239; and 44,532,245 shares, respectively
44,697

 
44,550

 
44,532

Additional paid-in capital
746,575

 
742,344

 
740,209

Retained earnings
582,800

 
540,244

 
539,030

Treasury stock, at cost – 41,552; 50,877; and 41,127 shares, respectively
(1,841
)
 
(1,968
)
 
(1,801
)
Accumulated other comprehensive income (loss)
(14,839
)
 
(17,422
)
 
(31,021
)
Total stockholders’ equity
1,357,392

 
1,307,748

 
1,290,949

 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
4,073,262

 
$
3,875,178

 
$
3,801,240


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)
Nine Months Ended September 30,
 
2014
2013
Operating activities:
(in thousands)
Net income (loss) available for common stock
$
94,774

$
96,839

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
110,258

106,068

Deferred financing cost amortization
1,608

3,209

Derivative fair value adjustments
2,136

275

Stock compensation
6,978

9,100

Unrealized (gain) loss on interest rate swaps, net

(29,393
)
Deferred income taxes
48,007

54,865

Employee benefit plans
11,109

16,644

Other adjustments, net
2,016

9,434

Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
(17,248
)
(12,522
)
Accounts receivable, unbilled revenues and other operating assets
(61
)
28,762

Accounts payable and other operating liabilities
(14,307
)
(23,774
)
Contributions to defined benefit pension plans
(10,200
)
(12,500
)
Other operating activities, net
4,087

4,759

Net cash provided by (used in) operating activities
239,157

251,766

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(290,299
)
(239,485
)
Proceeds from sale of assets
22,342


Other investing activities
(2,364
)
2,846

Net cash provided by (used in) investing activities
(270,321
)
(236,639
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(52,218
)
(50,678
)
Common stock issued
2,393

3,606

Short-term borrowings - issuances
396,250

269,600

Short-term borrowings - repayments
(294,750
)
(408,300
)
Long-term debt - issuances

275,000

Long-term debt - repayments
(12,200
)
(106,180
)
Other financing activities
(4,213
)

Net cash provided by (used in) financing activities
35,262

(16,952
)
Net change in cash and cash equivalents
4,098

(1,825
)
Cash and cash equivalents, beginning of period
7,841

15,462

Cash and cash equivalents, end of period
$
11,939

$
13,637


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 September 30, 2014, December 31, 2013, and September 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 nine months ended September 30, 2014 and September 30, 2013, and our financial condition as of September 30, 2014, December 31, 2013, and September 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 September 30, 2014
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
171,395

 
$
3,156

 
$
18,154

   Gas
 
78,735

 

 
1,597

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,602

 
20,419

 
7,829

   Coal Mining
 
6,884

 
8,689

 
2,638

   Oil and Gas
 
13,471

 

 
(3,110
)
Corporate activities
 

 

 
(272
)
Inter-company eliminations
 

 
(32,264
)
 

Total
 
$
272,087

 
$

 
$
26,836


Three Months Ended September 30, 2013
 
External
Operating
Revenue
 
Inter-company
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
169,401

 
$
2,003

 
$
15,097

   Gas
 
67,792

 

 
(1,450
)
Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,575

 
20,393

 
6,707

   Coal Mining
 
6,713

 
8,604

 
2,142

   Oil and Gas
 
14,426

 

 
(1,682
)
Corporate activities (a)
 

 

 
2,310

Inter-company eliminations
 

 
(31,000
)
 

Total
 
$
259,907

 
$

 
$
23,124


Nine Months Ended September 30, 2014
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
508,230

 
$
10,307

 
$
44,156

   Gas
 
440,571

 

 
28,289

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
4,138

 
62,211

 
23,096

   Coal Mining
 
19,085

 
26,637

 
7,118

   Oil and Gas
 
43,469

 

 
(6,792
)
Corporate activities
 

 

 
(1,093
)
Inter-company eliminations
 

 
(99,155
)
 

Total
 
$
1,015,493

 
$

 
$
94,774


11



Nine Months Ended September 30, 2013
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
482,222

 
$
9,844

 
$
38,063

   Gas
 
373,440

 

 
20,225

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
3,628

 
58,825

 
17,382

   Coal Mining
 
19,530

 
23,688

 
5,180

   Oil and Gas
 
41,584

 

 
(3,699
)
Corporate activities (a)
 

 

 
19,688

Inter-company eliminations
 

 
(92,357
)
 

Total
 
$
920,404

 
$

 
$
96,839

__________
(a)
Corporate activities include a $2.0 million and a $19 million after-tax non-cash mark-to-market gain on certain interest rate swaps for the three and nine months ended September 30, 2013, respectively.

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:
September 30, 2014
 
December 31, 2013
 
September 30, 2013
Utilities:
 
 
 
 
 
   Electric (a)
$
2,671,601

 
$
2,525,947

 
$
2,464,123

   Gas
827,069

 
805,617

 
757,746

Non-regulated Energy:
 
 
 
 
 
   Power Generation (a)
64,359

 
95,692

 
102,331

   Coal Mining
74,130

 
78,825

 
82,155

   Oil and Gas
330,781

 
288,366

 
264,785

Corporate activities
105,322

 
80,731

 
130,100

Total assets
$
4,073,262

 
$
3,875,178

 
$
3,801,240

__________
(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
September 30, 2014
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
53,717

$
21,485

$
(724
)
$
74,478

Gas Utilities
23,409

13,218

(740
)
35,887

Power Generation
1,368



1,368

Coal Mining
2,563



2,563

Oil and Gas
7,657


(13
)
7,644

Corporate
1,459



1,459

Total
$
90,173

$
34,703

$
(1,477
)
$
123,399


 
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
September 30, 2013
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
49,254

$
20,153

$
(648
)
$
68,759

Gas Utilities
20,693

11,877

(542
)
32,028

Power Generation
3



3

Coal Mining
2,677



2,677

Oil and Gas
8,463


(19
)
8,444

Corporate
2,226



2,226

Total
$
83,316

$
32,030

$
(1,209
)
$
114,137



13




(4)    REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands):
 
Maximum
As of
As of
As of
 
Amortization (in years)
September 30, 2014
December 31, 2013
September 30, 2013
Regulatory assets
 
 
 
 
Deferred energy and fuel cost adjustments - current (a)(d)
1
$
26,211

$
16,775

$
17,925

Deferred gas cost adjustments and natural gas price derivatives (a)(d)
7
49,870

12,366

16,845

AFUDC (b)
45
12,411

12,315

12,398

Employee benefit plans (c)
13
64,908

67,059

114,386

Environmental (a)
subject to approval
1,314

1,800

1,800

Asset retirement obligations (a)
44
3,282

3,266

3,262

Bond issue cost (a)
24
3,311

3,419

3,454

Renewable energy standard adjustment (a)
5
12,007

14,186

14,936

Flow through accounting (c)
35
25,157

20,916

19,222

Other regulatory assets (a)
15
10,395

10,546

9,099

 
 
$
208,866

$
162,648

$
213,327

 
 
 
 
 
Regulatory liabilities
 
 
 
 
Deferred energy and gas costs (a)
1
$
5,535

$
11,708

$
14,032

Employee benefit plans (c)
13
34,409

34,431

60,707

Cost of removal (a)
44
71,362

64,970

62,069

Other regulatory liabilities (c)
25
8,378

9,047

9,629

 
 
$
119,684

$
120,156

$
146,437

__________
(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 September 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:
 
September 30, 2014
 
December 31, 2013
 
September 30, 2013
Materials and supplies
$
52,682

 
$
50,196

 
$
50,564

Fuel - Electric Utilities
7,108

 
6,213

 
6,384

Natural gas in storage held for distribution
45,936

 
32,069

 
38,282

Total materials, supplies and fuel
$
105,726

 
$
88,478

 
$
95,230



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 September 30,
 
Nine Months Ended September 30,
 
2014
2013
 
2014
2013
 
 
 
 
 
 
Net income (loss) available for common stock
$
26,836

$
23,124

 
$
94,774

$
96,839

 
 
 
 
 
 
Weighted average shares - basic
44,415

44,201

 
44,382

44,143

Dilutive effect of:
 
 
 
 
 
Equity compensation
193

256

 
202

252

 
 
 
 
 
 
Weighted average shares - diluted
44,608

44,457

 
44,584

44,395


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 September 30,
 
Nine Months Ended September 30,
 
2014
2013
 
2014
2013
 
 
 
 
 
 
Equity compensation
99


 
75

9

Anti-dilutive shares
99


 
75

9



(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:
 
September 30, 2014
December 31, 2013
September 30, 2013
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$
184,000

$
31,726

$
82,500

$
22,100

$
138,300

$
53,137


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 September 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 September 30, 2014, our $275 million Corporate term loan due June 19, 2015 is classified as Current maturities of long-term debt.


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

As of September 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 September 30, 2014, our credit exposure included a $0.5 million exposure to non-investment grade energy marketing companies. 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:
 
September 30, 2014
 
December 31, 2013
 
September 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)
391,500

7,930,000

 
412,500

7,082,500

 
499,500

9,874,000

Maximum terms in months (b)
1

1

 
3

1

 
3

1

Derivative assets, current
$

$

 
$
55

$

 
$
13

$
113

Derivative assets, non-current
$

$

 
$

$

 
$

$

Derivative liabilities, current
$

$

 
$

$

 
$
98

$
52

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.
A $0.7 million gain is included in AOCI at September 30, 2014, and would be realized over the next 12 months if market prices remained equal to September 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:
 
September 30, 2014
 
December 31, 2013
 
September 30, 2013
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
 
Notional
(MMBtus)
 
Maximum
Term
(months) (a)
Natural gas futures purchased
16,290,000

 
74
 
17,930,000

 
84
 
14,010,000

 
74
Natural gas options purchased
7,070,000

 
6
 
3,890,000

 
8
 
6,810,000

 
6
Natural gas basis swaps purchased
12,025,000

 
63
 
14,785,000

 
60
 
9,790,000

 
63
__________
(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):
 
September 30, 2014
December 31, 2013
September 30, 2013
Derivative assets, current
$

$
662

$

Derivative assets, non-current
$

$

$

Derivative liabilities, non-current
$

$

$

Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities
$
7,470

$
7,567

$
10,652


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:
 
September 30, 2014
 
December 31, 2013
 
September 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
2.25

 
3.00

 
3.25

0.25

Derivative liabilities, current
$
3,397

 
$
3,474

 
$
7,039

$
58,755

Derivative liabilities, non-current
$
3,273

 
$
5,614

 
$
11,388

$

__________
(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 September 30, 2013, $75 million of these interest rate swaps was designated to borrowings on our Revolving Credit Facility and $75 million was designated to borrowings on our project financing debt at Black Hills Wyoming. These swaps were priced using three-month LIBOR, matching the floating portion of the related debt. The portion of the swaps that was designated to Black Hills Wyoming was 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 September 30, 2014, market interest rates and balances related to our interest rate swaps, a loss of approximately $3.4 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 September 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
 
$
152

 
Interest expense
 
$
(925
)
 
 
 
$

Commodity derivatives
 
4,833

 
Revenue
 
(1,135
)
 
 
 

Total
 
$
4,985

 
 
 
$
(2,060
)
 
 
 
$


Three Months Ended September 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
 
$
(907
)
 
Interest expense
 
$
(1,844
)
 
 
 
$

Commodity derivatives
 
(2,140
)
 
Revenue
 
(168
)
 
 
 

Total
 
$
(3,047
)
 
 
 
$
(2,012
)
 
 
 
$


Nine Months Ended September 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
 
$
(277
)
 
Interest expense
 
$
(2,745
)
 
 
 
$

Commodity derivatives
 
(1,376
)
 
Revenue
 
(2,697
)
 
 
 

Total
 
$
(1,653
)
 
 
 
$
(5,442
)
 
 
 
$


Nine Months Ended September 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
 
$
141

 
Interest expense
 
$
(5,460
)
 
 
 
$

Commodity derivatives
 
86

 
Revenue
 
896

 
 
 

Total
 
$
227

 
 
 
$
(4,564
)
 
 
 
$



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 September 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

322


 
(322
)

    Options -- Gas



 


    Basis Swaps -- Gas

1,545


 
(1,545
)

Commodity derivatives — Utilities

4,029


 
(4,029
)

Total
$

$
5,896

$

 
$
(5,896
)
$

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 


Options -- Oil
$

$

$

 
$

$

Basis Swaps -- Oil

487


 
(487
)

Options -- Gas



 


Basis Swaps -- Gas

865


 
(865
)

Commodity derivatives — Utilities

8,679


 
(8,679
)

Interest rate swaps

6,670


 

6,670

Total
$

$
16,701

$

 
$
(10,031
)
$
6,670




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

$
2

$

 
$

$
2

Basis Swaps -- Oil

51


 
(40
)
11

Options -- Gas



 


Basis Swaps -- Gas

1,752


 
(1,639
)
113

Commodity derivatives — Utilities

2,351


 
(2,351
)

Total
$

$
4,156

$

 
$
(4,030
)
$
126

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

$
142

$

 
$
(77
)
$
65

Basis Swaps -- Oil

1,318


 
(1,284
)
34

Options -- Gas



 


Basis Swaps -- Gas

232


 
(181
)
51

Commodity derivatives — Utilities

10,747


 
(10,747
)

Interest rate swaps

83,142


 
(5,960
)
77,182

Total
$

$
95,581

$

 
$
(18,249
)
$
77,332



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 September 30, 2014, December 31, 2013, and September 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 September 30, 2014
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
1,174

$

Commodity derivatives
Derivative assets — non-current
 
692


Commodity derivatives
Derivative liabilities — current
 

497

Commodity derivatives
Derivative liabilities — non-current
 

856

Interest rate swaps
Derivative liabilities — current
 

3,397

Interest rate swaps
Derivative liabilities — non-current
 

3,273

Total derivatives designated as hedges
 
 
$
1,866

$
8,023

 
 
 
 
 
Derivatives not designated as hedges: