BKH 063012 10Q


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, 2012
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, 2012
 
 
Common stock, $1.00 par value
44,188,286 shares





TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms and Abbreviations
 
 
 
 
 
PART I.
FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income and Comprehensive Income - unaudited
 
 
 
   Three and Six Months Ended June 30, 2012 and 2011
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   June 30, 2012, December 31, 2011 and June 30, 2011
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Six Months Ended June 30, 2012 and 2011
 
 
 
 
 
 
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
 
 
 
 
 
 
Exhibit Index
 



2


GLOSSARY OF TERMS AND ABBREVIATIONS
AND ACCOUNTING STANDARDS

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)
ARO
Asset Retirement Obligation
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
Bbl
Barrel
Bcf
Billion cubic feet
Bcfe
Billion cubic feet equivalent
BHC
Black Hills Corporation
BHEP
Black Hills Exploration and Production, Inc., representing our Oil and Gas segment, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Electric Generation
Black Hills Electric Generation, LLC, representing our Power Generation segment, a direct wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy
The name used to conduct the business activities of Black Hills Utility Holdings
Black Hills Non-regulated Holdings
Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of the Company
Black Hills Power
Black Hills Power, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Service Company
Black Hills Service Company, a direct wholly-owned subsidiary of the Company
Black Hills Utility Holdings
Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of the Company
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 the Company
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 Gas
Black Hills Colorado Gas 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, a direct wholly-owned subsidiary of Black Hills Electric Generation
CPCN
Certificate of Public Convenience and Necessity
CPUC
Colorado Public Utilities Commission
CT
Combustion Turbine
CVA
Credit Valuation Adjustment
CWIP
Construction Work-In-Progress
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.
Dodd-Frank
Dodd-Frank Wall Street Reform and Consumer Protection Act
DRIP
Dividend Reinvestment and Stock Purchase Plan
Dth
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
ECA
Energy Cost Adjustment
Enserco
Enserco Energy Inc., representing our Energy Marketing segment, sold February 29, 2012
Equity Forward Instrument
Equity Forward Agreement with J.P. Morgan connected to a public offering of 4,413,519 shares of Black Hills Corporation common stock

3


FASB
Financial Accounting Standards Board
FDIC
Federal Deposit Insurance Corporation
FERC
Federal Energy Regulatory Commission
GAAP
Generally Accepted Accounting Principles of the United States
Global Settlement
Settlement with the utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
IFRS
International Financial Reporting Standards
Iowa Gas
Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP
Independent Power Producer
IRS
Internal Revenue Service
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
LIBOR
London Interbank Offered Rate
LOE
Lease Operating Expense
Mcf
One thousand standard cubic feet
Mcfe
One thousand standard cubic feet equivalent. Natural gas liquid is converted by dividing gallons by 7. Crude oil is converted by multiplying barrels by 6.
MMBtu
One million British thermal units
MSHA
Mine Safety and Health Administration
MW
Megawatt
MWh
Megawatt-hour
Nebraska Gas
Black Hills Nebraska Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
NGL
Natural Gas Liquids
NPSC
Nebraska Public Service Commission
NYMEX
New York Mercantile Exchange
OTC
Over-the-counter
PGA
Purchase Gas Adjustment
PPA
Power Purchase Agreement
Revolving Credit Facility
Our $500 million five-year revolving credit facility which commenced on February 1, 2012 and expires on February 1, 2017
S&P
Standard and Poor's
SEC
United States Securities and Exchange Commission
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 AND COMPREHENSIVE INCOME
(unaudited)
 
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2012
2011
2012
2011
 
(in thousands, except per share amounts)
Revenue:
 
 
 
 
Utilities
$
214,946

$
236,053

$
551,601

$
610,749

Non-regulated energy
27,417

24,596

56,613

50,735

Total revenue
242,363

260,649

608,214

661,484

 
 
 
 
 
Operating expenses:
 
 
 
 
Utilities -
 
 
 
 
Fuel, purchased power and cost of gas sold
63,452

103,827

220,635

314,338

Operations and maintenance
59,563

58,689

124,323

126,098

Non-regulated energy operations and maintenance
20,713

22,436

43,308

46,626

Depreciation, depletion and amortization
41,431

32,246

79,990

64,156

Taxes - property, production and severance
9,478

7,239

20,988

15,436

Impairment of long-lived assets
26,868

—

26,868

—

Other operating expenses
267

52

1,463

303

Total operating expenses
221,772

224,489

517,575

566,957

 
 
 
 
 
Operating income
20,591

36,160

90,639

94,527

 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums, discounts and realized settlements on interest rate swaps)
(27,762
)
(28,593
)
(57,676
)
(57,796
)
Allowance for funds used during construction - borrowed
963

2,991

1,481

6,354

Capitalized interest
131

2,783

292

5,217

Unrealized gain (loss) on interest rate swaps, net
(15,552
)
(7,827
)
(3,507
)
(2,362
)
Interest income
627

463

1,064

1,011

Allowance for funds used during construction - equity
195

192

472

487

Other income, net
888

504

2,360

1,235

Total other income (expense)
(40,510
)
(29,487
)
(55,514
)
(45,854
)
 
 
 
 
 
Income (loss) before equity in earnings (loss) of unconsolidated subsidiaries and income taxes
(19,919
)
6,673

35,125

48,673

Equity in earnings (loss) of unconsolidated subsidiaries
22

40

(34
)
1,033

Income tax benefit (expense)
7,574

(3,007
)
(12,143
)
(16,932
)
Income (loss) from continuing operations
(12,323
)
3,706

22,948

32,774

Income (loss) from discontinued operations, net of tax
(1,160
)
4,046

(6,644
)
1,888

Net income (loss) available for common stock
(13,483
)
7,752

16,304

34,662

 
 
 
 
 
Other comprehensive income (loss), net of tax
(608
)
288

(774
)
(1,290
)
Comprehensive income (loss)
$
(14,091
)
$
8,040

$
15,530

$
33,372

 
 
 
 
 
Income (loss) per share, Basic -
 
 
 
 
Income (loss) from continuing operations, per share
$
(0.28
)
$
0.09

$
0.52

$
0.84

Income (loss) from discontinued operations, per share
(0.03
)
0.11

(0.15
)
0.05

Total income (loss) per share, Basic
$
(0.31
)
$
0.20

$
0.37

$
0.89

Income (loss) per share, Diluted -
 
 
 
 
Income (loss) from continuing operations, per share
$
(0.28
)
$
0.09

$
0.52

$
0.82

Income (loss) from discontinued operations, per share
(0.03
)
0.10

(0.15
)
0.05

Total income (loss) per share, Diluted
$
(0.31
)
$
0.19

$
0.37

$
0.87

Weighted average common shares outstanding:
 
 
 
 
Basic
43,799

39,109

43,765

39,084

Diluted
43,799

39,823

43,984

39,793

 
 
 
 
 
Dividends paid per share of common stock
$
0.370

$
0.365

$
0.740

$
0.730


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

5


BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)

 
June 30,
2012
 
December 31,
2011
 
June 30,
2011
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
40,110

 
$
21,628

 
$
21,971

Restricted cash and equivalents
4,772

 
9,254

 
3,710

Accounts receivable, net
109,157

 
156,774

 
108,203

Materials, supplies and fuel
61,455

 
84,064

 
61,104

Derivative assets, current
16,595

 
18,583

 
9,544

Income tax receivable, net
12,141

 
9,344

 
6,661

Deferred income tax assets, net, current
30,401

 
37,202

 
20,924

Regulatory assets, current
34,781

 
59,955

 
37,584

Other current assets
26,591

 
21,266

 
17,499

Assets of discontinued operations
—

 
340,851

 
358,669

Total current assets
336,003

 
758,921

 
645,869

 
 
 
 
 
 
Investments
16,208

 
17,261

 
17,302

 
 
 
 
 
 
Property, plant and equipment
3,863,380

 
3,724,016

 
3,550,783

Less accumulated depreciation and depletion
(1,006,827
)
 
(934,441
)
 
(913,503
)
Total property, plant and equipment, net
2,856,553

 
2,789,575

 
2,637,280

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
353,396

 
353,396

 
353,396

Intangible assets, net
3,731

 
3,843

 
3,955

Derivative assets, non-current
1,770

 
1,971

 
724

Regulatory assets, non-current
186,886

 
182,175

 
139,309

Other assets, non-current
19,733

 
19,941

 
19,325

Total other assets
565,516

 
561,326

 
516,709

 
 
 
 
 
 
TOTAL ASSETS
$
3,774,280

 
$
4,127,083

 
$
3,817,160


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
(Continued)
(unaudited)


 
June 30,
2012
 
December 31,
2011
 
June 30,
2011
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
59,739

 
$
104,748

 
$
84,195

Accrued liabilities
158,240

 
151,319

 
131,175

Derivative liabilities, current
85,675

 
84,367

 
65,627

Regulatory liabilities, current
16,785

 
16,231

 
17,220

Notes payable
225,000

 
345,000

 
380,000

Current maturities of long-term debt
227,590

 
2,473

 
3,613

Liabilities of discontinued operations
—

 
173,929

 
182,723

Total current liabilities
773,029

 
878,067

 
864,553

 
 
 
 
 
 
Long-term debt, net of current maturities
1,044,891

 
1,280,409

 
1,183,583

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
316,393

 
300,988

 
304,860

Derivative liabilities, non-current
42,077

 
49,033

 
17,281

Regulatory liabilities, non-current
114,593

 
108,217

 
83,643

Benefit plan liabilities
162,530

 
177,480

 
131,169

Other deferred credits and other liabilities
124,482

 
123,553

 
124,002

Total deferred credits and other liabilities
760,075

 
759,271

 
660,955

 
 
 
 
 
 
Commitments and contingencies (See Notes 6, 7, 10, 11, 13 and 16)


 

 

 
 
 
 
 
 
Stockholders' equity:
 
 
 
 
 
Common stockholders' —
 
 
 
 
 
Common stock $1 par value: 100,000,000 shares authorized: issued 44,176,520; 43,957,502 and 39,462,001 shares, respectively
44,177

 
43,958

 
39,462

Additional paid-in capital
727,613

 
722,623

 
602,961

Retained earnings
460,324

 
476,603

 
491,208

Treasury stock at cost – 69,657; 32,766 and 23,637 shares, respectively
(2,177
)
 
(970
)
 
(691
)
Accumulated other comprehensive income (loss)
(33,652
)
 
(32,878
)
 
(24,871
)
Total stockholders' equity
1,196,285

 
1,209,336

 
1,108,069

 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
3,774,280

 
$
4,127,083

 
$
3,817,160


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

7


BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
 
Six Months Ended
June 30,
 
2012
2011
Operating activities:
(in thousands)
Net income (loss) available to common stock
$
16,304

$
34,662

(Income) loss from discontinued operations, net of tax
6,644

(1,888
)
Income (loss) from continuing operations
22,948

32,774

Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
79,990

64,156

Deferred financing cost amortization
4,050

3,199

Impairment of long-lived assets
26,868

—

Derivative fair value adjustments
(4,895
)
(3,235
)
Stock compensation
3,269

3,185

Unrealized mark-to-market (gain) loss on interest rate swaps
3,507

2,362

Deferred income taxes
11,200

29,836

Equity in (earnings) loss of unconsolidated subsidiaries
34

(1,033
)
Allowance for funds used during construction - equity
(472
)
(487
)
Employee benefit plans
10,492

7,287

Other adjustments, net
4,258

(160
)
Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
22,609

1,811

Accounts receivable, unbilled revenues and other current assets
42,262

51,615

Accounts payable and other current liabilities
(55,015
)
(65,673
)
Regulatory assets
14,533

32,029

Regulatory liabilities
(385
)
11,573

Contributions to defined benefit pension plans
(25,000
)
(550
)
Other operating activities, net
(4,738
)
(6,190
)
Net cash provided by operating activities of continuing operations
155,515

162,499

Net cash provided by (used in) operating activities of discontinued operations
21,184

19,518

Net cash provided by operating activities
176,699

182,017

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(148,807
)
(223,456
)
Other investing activities
4,095

799

Net cash provided by (used in) investing activities of continuing operations
(144,712
)
(222,657
)
Proceeds from sale of business operations
108,837

—

Net cash provided by (used in) investing activities of discontinued operations
(824
)
(2,407
)
Net cash provided by (used in) investing activities
(36,699
)
(225,064
)
 
 
 
Financing activities:
 
 
Dividends paid on common stock
(32,583
)
(29,530
)
Common stock issued
1,510

1,437

Short-term borrowings - issuances
56,453

564,000

Short-term borrowings - repayments
(176,453
)
(433,000
)
Long-term debt - repayments
(10,418
)
(4,052
)
Other financing activities
2,833

(16
)
Net cash provided by (used in) financing activities of continuing operations
(158,658
)
98,839

Net cash provided by (used in) financing activities of discontinued operations
—

(157
)
Net cash provided by (used in) financing activities
(158,658
)
98,682

Net change in cash and cash equivalents
(18,658
)
55,635

Cash and cash equivalents, beginning of period*
58,768

32,438

Cash and cash equivalents, end of period*
$
40,110

$
88,073

_______________________
*
Cash and cash equivalents include cash of discontinued operations of $37.1 million, $66.1 million and $16.0 million at December 31, 2011, June 30, 2011 and December 31, 2010, respectively.
See Note 3 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.

8


BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company's 2011 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 2011 Annual Report on Form 10-K filed with the SEC.

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, 2012, December 31, 2011 and June 30, 2011 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 gas utilities is November through March and 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, 2012 and June 30, 2011, and our financial condition as of June 30, 2012, December 31, 2011, and June 30, 2011 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.

On February 29, 2012, we sold our Energy Marketing segment, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations. For further information see Note 18.

Certain prior year data presented in the financial statements has been reclassified to conform to the current year presentation. Specifically, the Company has reclassified deferred financing cost amortization into a separate line on the Condensed Consolidated Statements of Cash Flows. This reclassification had no effect on total assets, net income, cash flows or earnings per share.


(2)    RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION

Recently Adopted Accounting Standards and Legislation

Other Comprehensive Income: Presentation of Comprehensive Income, ASU 2011-05 and ASU 2011-12

FASB issued an accounting standards update amending ASC 220, Comprehensive Income, to improve the comparability, consistency and transparency of reporting of comprehensive income. It amends existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income. Also, items that are reclassified from other comprehensive income to net income must be presented on the face of the financial statements. ASU 2011-05 requires retrospective application, and it is effective for the fiscal years, and interim periods within those years beginning after December 15, 2011. In December 2011, FASB issued ASU 2011-12, which indefinitely deferred the provisions of ASU 2011-05 requiring the presentation of reclassification adjustments on the face of the financial statements for items reclassified from other comprehensive income to net income.


9


At December 31, 2011, we elected to early adopt the provisions of ASU 2011-05 as amended by ASU 2011-12. The adoption changed our presentation of certain financial statements and provided additional details in the notes to the financial statements, but did not have any other impact on our financial statements.

Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements, ASU 2011-04

In May 2011, FASB issued an accounting standards update amending ASC 820, Fair Value Measurements and Disclosures, to achieve common fair value measurement and disclosure requirements between GAAP and IFRS. Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements - quantitative information about unobservable inputs used, a description of the valuation processes used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity's use of a non-financial asset that is different from the asset's highest and best use - the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required - the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. ASU 2011-04 is effective for fiscal years, and interim periods within those years, beginning after December 31, 2011. The amendment required additional details in notes to financial statements, but did not have any other impact on our financial statements. Additional disclosures are included in Notes 14 and 15.

Intangibles - Goodwill and Other: Testing Goodwill for Impairment, ASU 2011-08

In September 2011, the FASB issued an amendment to ASC 350, Intangibles - Goodwill and Other, to provide an option to perform a qualitative assessment to determine whether further impairment testing of goodwill is necessary. Specifically, an entity has the option to first assess qualitative factors to determine whether it is necessary to perform the current two-step test. If an entity believes, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. Otherwise, no further testing is required. This standard is effective for annual and interim goodwill impairment testing performed for fiscal years beginning after December 15, 2011. We perform our annual impairment testing in November of each year. The adoption of this standard will not have an impact on our financial statements.

Recently Issued Accounting Standards and Legislation

Balance Sheet: Disclosure about Offsetting Assets and Liabilities, ASU 2011-11
In December 2011, the FASB issued revised accounting guidance to amend ASC 210, Balance Sheet, related to the existing disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures, as well as to improve comparability of balance sheets prepared under GAAP and IFRS. The revised disclosure guidance affects all companies that have financial instruments and derivative instruments that are either offset in the balance sheet (i.e., presented on a net basis) or subject to an enforceable master netting and/or similar arrangement. In addition, the revised guidance requires that certain enhanced quantitative and qualitative disclosures are made with respect to a company's netting arrangements and/or rights of offset associated with its financial instruments and/or derivative instruments. The revised disclosure guidance is effective on a retrospective basis for interim and annual periods beginning January 1, 2013. The adoption of this standard will not have an impact on our financial position, results of operations or cash flows.

Intangible - Goodwill and Other: Testing Indefinite Lived Intangible Assets for Impairment, ASU 2012-02

In July 2012, the FASB issued an amendment to ASC 350, Intangibles - Goodwill and Other, to provide an option to perform a qualitative assessment to determine whether further impairment testing of indefinite lived intangible assets is necessary. This ASU aligns the impairment testing for intangible assets with that of goodwill as amended by ASU 2011-11. This guidance is effective for interim and annual periods beginning after September 15, 2012, with early adoption permitted. The adoption of this standard will not have an impact on our financial statements, results of operations or cash flows.



10


(3)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

 
Six Months Ended
 
June 30,
2012
 
June 30,
2011
 
(in thousands)
Non-cash investing activities from continuing operations—
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
52,204

 
$
34,171

Capitalized assets associated with retirement obligations
$
3,406

 
$
—

Cash (paid) refunded during the period for continuing operations—
 
 
 
Interest (net of amounts capitalized)
$
(55,364
)
 
$
(49,425
)
Income taxes, net
$
(383
)
 
$
(10,726
)


(4)    MATERIALS, SUPPLIES AND FUEL

The amounts of Materials, supplies and fuel included in the accompanying Condensed Consolidated Balance Sheets, by major classification, were as follows (in thousands) as of:
 
 
June 30,
2012
 
December 31,
2011
 
June 30,
2011
Materials and supplies
 
$
41,963

 
$
40,838

 
$
36,382

Fuel - Electric Utilities
 
8,089

 
8,201

 
8,808

Natural gas in storage held for distribution
 
11,403

 
35,025

 
15,914

Total materials, supplies and fuel
 
$
61,455

 
$
84,064

 
$
61,104



(5)    ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Accounts receivable consists primarily of customer trade accounts. The Gas Utilities' accounts receivable balance fluctuates primarily due to seasonality. We maintain an allowance for doubtful accounts that reflects our best estimate of probable uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect our ability to collect.
Following is a summary of receivables (in thousands) as of:
 
Accounts
Unbilled
Less Allowance for
Accounts
June 30, 2012
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
36,336

$
25,726

$
(620
)
$
61,442

Gas Utilities
20,627

11,085

(950
)
30,762

Oil and Gas
13,749

—

(105
)
13,644

Coal Mining
1,982

—

—

1,982

Power Generation
197

—

—

197

Corporate
1,130

—

—

1,130

Total
$
74,021

$
36,811

$
(1,675
)
$
109,157



11


 
Accounts
Unbilled
Less Allowance for
Accounts
December 31, 2011
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
42,773

$
21,151

$
(545
)
$
63,379

Gas Utilities
39,353

38,992

(1,011
)
77,334

Oil and Gas
11,282

—

(105
)
11,177

Coal Mining
4,056

—

—

4,056

Power Generation
282

—

—

282

Corporate
546

—

—

546

Total
$
98,292

$
60,143

$
(1,661
)
$
156,774


 
Accounts
Unbilled
Less Allowance for
Accounts
June 30, 2011
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
38,067

$
16,535

$
(685
)
$
53,917

Gas Utilities
33,572

11,891

(1,420
)
44,043

Oil and Gas
7,803

—

(161
)
7,642

Coal Mining
1,652

—

—

1,652

Power Generation
106

—

—

106

Corporate
843

—

—

843

Total
$
82,043

$
28,426

$
(2,266
)
$
108,203



(6)    NOTES PAYABLE

Our credit facility and debt securities contain certain restrictive financial covenants. As of June 30, 2012, we were in compliance with all of these covenants.

We had the following short-term debt outstanding as of the Condensed Consolidated Balance Sheet dates (in thousands):
 
June 30, 2012
December 31, 2011
June 30, 2011
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$
75,000

$
36,256

$
195,000

$
43,700

$
130,000

$
43,000

Term Loan due 2011(a)
—

—

—

—

100,000

—

Term Loan due 2013 (b)
150,000

—

150,000

—

150,000

—

Total
$
225,000

$
36,256

$
345,000

$
43,700

$
380,000

$
43,000

______________
(a)     The short-term loan was renegotiated to a longer term note, maturing on September 30, 2013.
(b)    In June 2012, this short-term loan was extended for one year. See discussion below.

Revolving Credit Facility

On February 1, 2012, we entered into a new $500 million Revolving Credit Facility expiring February 1, 2017. The facility contains an accordion feature allowing us, with the consent of the administrative agent, to increase the capacity of the facility to $750 million. The Revolving Credit Facility can be used for the issuance of letters of credit, to fund working capital needs and for other corporate purposes. Borrowings are available under a base rate option or a Eurodollar option. The cost of borrowings or letters of credit is determined based upon our credit ratings. At current credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.50%, 1.50% and 1.50%, respectively, at June 30, 2012. The facility contains a commitment fee that is charged on the unused amount of the Revolving Credit Facility. Based upon current credit ratings, the fee is 0.25%.

12



Deferred financing costs on the new facility of $2.8 million are being amortized over the estimated useful life of the Revolving Credit Facility and are included in Interest expense on the accompanying Condensed Consolidated Statements of Income and Comprehensive Income. Upon entering into the new facility, $1.5 million of deferred financing costs relating to the previous credit facility were written off through Interest expense.

Term Loan due 2013

On June 24, 2012, we extended the term of the $150 million term loan to June 24, 2013. The cost of borrowing is based on 1.10% over LIBOR.

Debt Covenants

Certain debt obligations require compliance with the following covenants at the end of each quarter (dollars in thousands):
 
 
As of
 
 
 
 
 
June 30, 2012
 
Covenant Requirement
Consolidated Net Worth
 
$
1,196,285

 
Greater than
$
892,283

Recourse Leverage Ratio
 
56.8
%
 
Less than
65.0
%


(7)    LONG TERM DEBT

On May 15, 2012, Black Hills Power repaid its 4.8% Pollution Control Refund Revenue Bonds in full for $6.5 million principal and interest. These bonds were originally due to mature on October 1, 2014.


(8)    EARNINGS PER SHARE
 
Basic income (loss) per share from continuing operations is computed by dividing Income (loss) from continuing operations by the weighted-average number of common shares outstanding during the period. Diluted income (loss) per share is computed by including all dilutive common shares potentially outstanding during a period.

A reconciliation of share amounts used to compute earnings (loss) per share is as follows (in thousands):
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2012
2011
 
2012
2011
 
 
 
 
 
 
Income (loss) from continuing operations
$
(12,323
)
$
3,706

 
$
22,948

$
32,774

 
 
 
 
 
 
Weighted average shares - basic
43,799

39,109

 
43,765

39,084

Dilutive effect of:
 
 
 
 
 
Restricted stock
—

148

 
150

140

Stock options
—

20

 
15

20

Equity forward instruments
—

533

 
—

496

Other dilutive effects
—

13

 
54

53

Weighted average shares - diluted
43,799

39,823

 
43,984

39,793



13


Below is a discussion of our potentially dilutive shares that were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive.

Due to our net loss for the quarter ended June 30, 2012, potentially dilutive securities, consisting of outstanding stock options, restricted common stock, restricted stock units, non-vested performance-based share awards and warrants, were excluded from the diluted loss per share calculation due to their anti-dilutive effect. In computing diluted net loss per share, 13,081 options to purchase shares of common stock, 152,318 vested and non-vested restricted stock shares, 34,248 warrants and other performance shares were excluded from the computations for the three months ended June 30, 2012.

In addition to these potentially dilutive shares excluded due to our net loss for second quarter of 2012, the following outstanding securities were also excluded in the computation of diluted income (loss) per share from continuing operations as their inclusion would have been anti-dilutive (in thousands):
 
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2012
2011
2012
2011
Stock options
99

102

113

81

Restricted stock
66

24

48

16

Other stock
42

31

29

15

Anti-dilutive shares
207

157

190

112



(9)    COMPREHENSIVE INCOME (LOSS)

The following table presents the components of our comprehensive income (loss) (in thousands):
Three Months Ended June 30, 2012
Pre-tax Amount
 
Tax (Expense) Benefit
 
Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges
$
178

 
$
(167
)
 
$
11

Reclassification adjustments of cash flow hedges settled and included in net income (loss)
(1,051
)
 
432

 
(619
)
Other comprehensive income (loss)
$
(873
)
 
$
265

 
$
(608
)


Three Months Ended June 30, 2011
Pre-tax Amount
 
Tax (Expense) Benefit
 
Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges
$
(996
)
 
$
231

 
$
(765
)
Reclassification adjustments of cash flow hedges settled and included in net income (loss)
1,617

 
(564
)
 
1,053

Other comprehensive income (loss)
$
621

 
$
(333
)
 
$
288


Six Months Ended June 30, 2012
Pre-tax Amount
 
Tax (Expense) Benefit
 
Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges
$
699

 
$
(112
)
 
$
587

Reclassification adjustments of cash flow hedges settled and included in net income (loss)
(2,238
)
 
877

 
(1,361
)
Other comprehensive income (loss)
$
(1,539
)
 
$
765

 
$
(774
)

Six Months Ended June 30, 2011
Pre-tax Amount
 
Tax (Expense) Benefit
 
Net-of-tax Amount
Fair value adjustment of derivatives designated as cash flow hedges
$
(4,781
)
 
$
1,868

 
$
(2,913
)
Reclassification adjustments of cash flow hedges settled and included in net income (loss)
2,478

 
(855
)
 
1,623

Other comprehensive income (loss)
$
(2,303
)
 
$
1,013

 
$
(1,290
)

14



Balances by classification included within Accumulated other comprehensive income (loss) on the accompanying Condensed Consolidated Balance Sheets are as follows (in thousands):
 
Derivatives Designated as Cash Flow Hedges
Employee Benefit Plans
Total
Balance as of December 31, 2011
$
(13,802
)
$
(19,076
)
$
(32,878
)
Other comprehensive income (loss)
(774
)
—

(774
)
Ending Balance June 30, 2012
$
(14,576
)
$
(19,076
)
$
(33,652
)
 
 
 
 
 
Derivatives Designated as Cash Flow Hedges
Employee Benefit Plans
Total
Balance as of December 31, 2010
$
(12,439
)
$
(11,142
)
$
(23,581
)
Other comprehensive income (loss)
(1,290
)
—

(1,290
)
Ending Balance June 30, 2011
$
(13,729
)
$
(11,142
)
$
(24,871
)


(10)     COMMON STOCK

Other than the following transactions, we had no material changes in our common stock during the six months ended June 30, 2012 from the amount reported in Note 11 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Equity Compensation Plans

•
We granted 66,690 target performance shares to certain officers and business unit leaders for the January 1, 2012 through December 31, 2014 performance period during the six months ended June 30, 2012. Actual shares are issued after the end of the performance period. Performance shares are awarded based on our total stockholder return over the designated performance period as measured against a selected peer group and can range from 0% to 200% of target. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria. The performance awards are paid 50% in cash and 50% in shares of common stock. The grant date fair value was $32.26 per share.

•
We granted 145,787 shares of restricted common stock and restricted stock units during the six months ended June 30, 2012. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $5.1 million will be recognized over the vesting period.

•
Stock options totaling 41,206 shares of common stock were exercised during the six months ended June 30, 2012 at a weighted-average exercise price of $28.28 per share, providing $1.2 million of proceeds.

•
We issued 3,690 shares of common stock under our short-term incentive compensation plan during the six months ended June 30, 2012. Pre-tax compensation cost related to the awards was approximately $0.1 million, which was expensed in 2011.

Stock-based compensation expense for the three months ended June 30, 2012 and 2011 was $1.5 million and $0.9 million, respectively, and for the six months ended June 30, 2012 and 2011 was $3.3 million and $3.1 million, respectively.

As of June 30, 2012, total unrecognized compensation expense related to non-vested stock awards was $10.3 million and is expected to be recognized over a weighted-average period of 2.2 years.


15


Dividend Reinvestment and Stock Purchase Plan

We have a DRIP under which stockholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We are currently issuing new shares. We issued 52,247 new shares at a weighted-average price of $32.70 during the six months ended June 30, 2012. Unissued common stock totaling 401,017 shares was available for future offering under the DRIP at June 30, 2012.

Dividend Restrictions

Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. As of June 30, 2012, we were in compliance with these covenants.

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our stockholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at June 30, 2012:

•
Our utilities are generally limited to the amount of dividends allowed to be paid to us as a utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of June 30, 2012, the restricted net assets at our Utilities Group were approximately $215.1 million.

•
As required by the covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has maintained restricted equity of at least $100.0 million.


(11)     EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

We have three non-contributory defined benefit pension plans (the "Pension Plans"). One covers certain eligible employees of Black Hills Service Company, Black Hills Power, WRDC and BHEP, one covers certain eligible employees of Cheyenne Light, and one covers certain eligible employees of Black Hills Energy. The Pension Plan benefits are based on years of service and compensation levels.

The components of net periodic benefit cost for the Pension Plans were as follows (in thousands):
 
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2012
2011
2012
2011
Service cost
$
1,430

$
1,356

$
2,860

$
2,711

Interest cost
3,687

3,732

7,374

7,464

Expected return on plan assets
(4,084
)
(4,239
)
(8,168
)
(8,478
)
Prior service cost
22

25

44

50

Net loss (gain)
2,408

1,135

4,816

2,270

Net periodic benefit cost
$
3,463

$
2,009

$
6,926

$
4,017


Non-pension Defined Benefit Postretirement Healthcare Plans

We sponsor the following retiree healthcare plans (the "Healthcare Plans"): the Black Hills Corporation Postretirement Healthcare Plan, the Healthcare Plan for Retirees of Cheyenne Light, and the Black Hills Energy Postretirement Healthcare Plan. Employees who participate in the Healthcare Plans and who retire on or after meeting certain eligibility requirements are entitled to postretirement healthcare benefits.


16


The components of net periodic benefit cost for the Healthcare Plans were as follows (in thousands):
 
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2012
2011
2012
2011
Service cost
$
402

$
375

$
804

$
750

Interest cost
523

542

1,046

1,084

Expected return on plan assets
(19
)
(41
)
(38
)
(82
)
Prior service cost (benefit)
(125
)
(120
)
(250
)
(240
)
Net loss (gain)
222

169

444

338

Net periodic benefit cost
$
1,003

$
925

$
2,006

$
1,850


Supplemental Non-qualified Defined Benefit Plans

We have various supplemental retirement plans for key executives (the "Supplemental Plans"). The Supplemental Plans are non-qualified defined benefit plans.

The components of net periodic benefit cost for the Supplemental Plans were as follows (in thousands):
 
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2012
2011
2012
2011
Service cost
$
246

$
257

$
492

$
514

Interest cost
331

325

662

649

Prior service cost
1

1

2

2

Net loss (gain)
202

128

404

255

Net periodic benefit cost
$
780

$
711

$
1,560

$
1,420


Contributions

We anticipate that we will make contributions to the benefit plans during 2012 and 2013. Contributions to the Pension Plans will be made in cash, and contributions to the Healthcare Plans and the Supplemental Plans are expected to be made in the form of benefit payments. Contributions are as follows (in thousands):
 
Contributions Made
Contributions Made
Additional
 
 
Three Months Ended June 30, 2012
Six Months Ended June 30, 2012
Contributions Anticipated for 2012
Contributions Anticipated for 2013
Defined Benefit Pension Plans
$
—

$
25,000

$
—

$
4,500

Non-pension Defined Benefit Postretirement Healthcare Plans
$
1,063

$
2,126

$
2,125

$
4,380

Supplemental Non-qualified Defined Benefit Plans
$
278

$
556

$
555

$
1,090



(12)     BUSINESS SEGMENTS INFORMATION

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.

On February 29, 2012, we sold our Energy Marketing segment, Enserco, which resulted in this segment being classified as discontinued operations. For comparative purposes, all prior periods presented have been restated to reflect the classification of this segment as discontinued operations. Indirect corporate costs and inter-segment interest expense related to Enserco that have not been classified as discontinued operations have been reclassified to our Corporate segment. For further information see Note 18.


17


We conduct our operations through the following five reportable segments:

Utilities Group —

•
Electric Utilities, which supplies electric utility service to areas in South Dakota, Wyoming, Colorado and Montana and natural gas utility service to Cheyenne, Wyoming and vicinity; and

•
Gas Utilities, which supplies natural gas utility service to areas in Colorado, Iowa, Kansas and Nebraska.

Non-regulated Energy Group —

•
Oil and Gas, which acquires, explores for, develops and produces crude oil and natural gas interests located in the Rocky Mountain region and other states;

•
Power Generation, which produces and sells power and capacity to wholesale customers from power plants located in Wyoming and Colorado; and

•
Coal Mining, which engages in the mining and sale of coal from our mine near Gillette, Wyoming.

Segment information follows the accounting policies described in Note 1 of the Notes to Consolidated Financial Statements in our 2011 Annual Report on Form 10-K.

Segment information included in the accompanying Condensed Consolidated Statements of Income and Comprehensive Income and Condensed Consolidated Balance Sheets was as follows (in thousands):
Three Months Ended June 30, 2012
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
144,560

 
$
5,174

 
$
14,159

   Gas
 
70,386

 
—

 
1,159

Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas (a)
 
20,621

 


 
(19,621
)
   Power Generation
 
759

 
17,975

 
3,926

   Coal Mining
 
6,037

 
7,090

 
1,234

Corporate (b)
 
—

 
—

 
(13,180
)
Intercompany eliminations
 
—

 
(30,239
)
 
—

Total
 
$
242,363

 
$
—

 
$
(12,323
)

Three Months Ended June 30, 2011
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
136,131

 
$
3,410

 
$
8,614

   Gas
 
99,922

 
—

 
4,440

Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas  
 
18,838

 
—

 
(79
)
   Power Generation
 
891

 
6,889

 
548

   Coal Mining
 
6,266

 
9,274

 
(381
)
Corporate (b)(c)
 
—

 
—

 
(9,443
)
Intercompany eliminations
 
—

 
(20,972
)
 
7

Total
 
$
262,048

 
$
(1,399
)
 
$
3,706



18


Six Months Ended June 30, 2012
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
300,693

 
$
8,210

 
$
22,905

   Gas
 
250,908

 
—

 
16,366

Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas (a)
 
42,266

 
—

 
(19,608
)
   Power Generation
 
1,937

 
36,424

 
10,840

   Coal Mining
 
12,410

 
15,706

 
2,234

Corporate (b)(c)
 
—

 
—

 
(9,789
)
Intercompany eliminations
 
—

 
(60,340
)
 
—

Total
 
$
608,214

 
$
—

 
$
22,948


Six Months Ended June 30, 2011
 
External
Operating
Revenues
 
Intercompany
Operating
Revenues
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
280,561

 
$
7,249

 
$
18,863

   Gas
 
330,188

 
—

 
23,703

Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas  
 
36,744

 
—

 
(794
)
   Power Generation
 
1,578

 
13,822

 
1,734

   Coal Mining
 
13,880

 
17,155

 
(1,679
)
Corporate (b)(c)
 
—

 
—

 
(8,992
)
Intercompany eliminations
 
—

 
(39,693
)
 
(61
)
Total
 
$
662,951

 
$
(1,467
)
 
$
32,774

____________
(a)
Income (loss) from continuing operations includes a $17.3 million non-cash after-tax ceiling test impairment charge. See Note 17 for further information.
(b)
Income (loss) from continuing operations includes $10.1 million and $2.3 million net after-tax mark-to-market loss on interest rate swaps for the three and six months ended June 30, 2012, respectively, and a $5.1 million and $1.5 million net after-tax mark-to-market loss on interest rate swaps for the three and six months ended June 30, 2011, respectively.
(c)
Certain direct corporate costs and inter-segment interest expense previously allocated to our Energy Marketing segment were not classified as discontinued operations but were included in the Corporate segment. See Note 18 for further information.

19



Total Assets (net of inter-company eliminations)
June 30,
2012
 
December 31,
2011
 
June 30,
2011
 
Utilities:
 
 
 
 
 
 
   Electric (a)
$
2,300,948

 
$
2,254,914

 
$
1,900,806

 
   Gas
684,545

 
746,444

 
659,349

 
Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas
416,617

 
425,970

 
366,270

 
   Power Generation (a)
122,856

 
129,121

 
353,794

 
   Coal Mining
90,021

 
88,704

 
89,627

 
Corporate
159,293

 
141,079

(b) 
88,645

(b) 
Discontinued operations
—

 
340,851

(c) 
358,669

(c) 
Total assets
$
3,774,280

 
$
4,127,083

 
$
3,817,160

 
____________
(a)
The PPA under which the new generating facility was constructed at our Pueblo Airport Generation site by Colorado IPP to support Colorado Electric customers is accounted for as a capital lease. Therefore, commencing December 31, 2011, assets previously recorded at Power Generation are now accounted for at Colorado Electric as a capital lease.
(b) Assets of the Corporate segment were restated due to deferred taxes that were not classified as discontinued operations.
(c) See Note 18 for further information relating to discontinued operations.


(13)     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 2011 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:

•
Commodity price risk associated with our natural long position with crude oil and natural gas reserves and production, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our regulated segment; and

•
Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our derivative instruments.

Our exposure to these market risks is affected by a number of factors including the size, duration, and composition of our energy portfolio, the absolute and relative levels of interest rates and commodity prices, the volatility of these prices and rates, and the liquidity of the related interest rate and commodity markets.

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 investment grade companies and credit quality municipalities and electric cooperatives, 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.


20


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, 2012, our credit exposure (exclusive of retail customers of the regulated utilities) was concentrated primarily among investment grade companies, municipal cooperatives and federal agencies. Credit exposure with non-investment grade or non-rated counterparties, was supported partially through letters of credit, prepayments or parental guarantees.

We actively manage our exposure to certain market and credit risks as described in Note 3 of the Notes to the Consolidated Financial Statements in our 2011 Annual Report on Form 10-K. Our derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income and Comprehensive Income are detailed below and within Note 14.

Oil and Gas Exploration and Production

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.

We hold a portfolio of swaps and options to hedge portions of our crude oil and natural gas production. We elect hedge accounting on those OTC swaps and options. These transactions were designated at inception as cash flow hedges, documented under accounting for derivatives and hedging, and initially met prospective effectiveness testing. Effectiveness of our hedging position is evaluated at least quarterly.

The derivatives are marked to fair value and are 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 Accumulated other comprehensive income (loss) and the ineffective portion, if any, is reported in Revenue.

We had the following derivatives and related balances for our Oil and Gas segment (dollars in thousands) as of:
 
June 30, 2012
 
December 31, 2011
 
June 30, 2011
 
Crude Oil
Swaps/
Options
Natural Gas
Swaps
 
Crude Oil
Swaps/
Options
Natural Gas
Swaps
 
Crude Oil
Swaps/
Options
Natural Gas
Swaps
Notional (a)
672,000

9,020,500

 
528,000

5,406,250

 
463,500

5,969,250

Maximum terms in years (b)
1.50

1.25

 
1.25

1.75

 
1.00

0.25

Derivative assets, current
$
2,483

$
4,386

 
$
729

$
8,010

 
$
449

$
6,160

Derivative assets, non-current
$
1,316

$
255

 
$
771

$
1,148

 
$
214

$
456

Derivative liabilities, current
$
456

$
452

 
$
2,559

$
—

 
$
2,385

$
—

Derivative liabilities, non-current
$
981

$
331

 
$
811

$
7

 
$
1,201

$
117

Pre-tax accumulated other comprehensive income (loss)
$
1,727

$
3,305

 
$
(1,928
)
$
9,152

 
$
3,173

$
6,499

Cash collateral included in Derivative liabilities
$
613

$
553

 
$
—

$
—

 
$
—

$
—

Cash collateral included in Other current assets
$
267

$
51

 
$
—

$
—

 
$
—

$
—

Expense included in Revenue (c)
$
245

$
51

 
$
58

$
—

 
$
250

$
—

____________
(a)
Crude oil in Bbls, gas in MMBtus
(b)
Refers to the term of the derivative instrument. Assets and liabilities are classified as current or non-current based on the term of the hedged transaction and the corresponding settlement of the derivative instruments.
(c)
Represents the amortization of put premiums.
Based on June 30, 2012 market prices, a $4.5 million gain would be reclassified from AOCI during the next 12 months. Estimated and actual realized gains will change during future periods as market prices fluctuate.


21


Utilities

Our utility customers are exposed to the effect of volatile natural gas prices; therefore, as allowed or required by state utility commissions, we have entered into certain 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. Gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in accordance with accounting standards for regulated utility operations. Accordingly, the hedging activity is recognized in the Condensed Consolidated Statements of Income and Comprehensive Income when the related costs are recovered through our rates.

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, 2012
 
December 31, 2011
 
June 30, 2011
 
Notional
(MMBtus)
 
Latest
Expiration
(months)
 
Notional
(MMBtus)
 
Latest
Expiration
(months)
 
Notional
(MMBtus)
 
Latest
Expiration
(months)
Natural gas futures purchased
12,440,000

 
78

 
14,310,000

 
84

 
7,820,000

 
21

Natural gas options purchased
2,840,000

 
9

 
1,720,000

 
3

 
1,560,000

 
9

Natural gas basis swaps purchased
7,270,000

 
78

 
7,160,000

 
60

 
—

 
—


We had the following derivative balances related to the hedges in our Utilities (in thousands) as of:
 
June 30,
2012
 
December 31,
2011
 
June 30,
2011
Derivative assets, current
$
9,726

 
$
9,844

 
$
2,935

Derivative assets, non-current
$
199

 
$
52

 
$
53

Derivative liabilities, non-current
$
6,453

 
$
7,156

 
$
175

Net unrealized (gain) loss included in Regulatory assets or liabilities
$
13,691

 
$
17,556

 
$
4,229

Included in Derivatives:
 
 
 
 
 
  Cash collateral receivable (payable)
$
15,925

 
$
19,416

 
$
6,254

  Option premiums and commissions
$
1,238

 
$
880

 
$
760



22


Financing Activities

We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. Our interest rate swaps and related balances were as follows (dollars in thousands) as of:
 
June 30, 2012
 
December 31, 2011
 
June 30, 2011
 
Designated 
Interest Rate
Swaps
 
De-designated
Interest Rate
Swaps*
 
Designated
Interest Rate
Swaps
 
De-designated
Interest Rate
Swaps*
 
Designated
Interest Rate
Swaps
 
De-designated
Interest Rate
Swaps*
Notional
$
150,000

 
$
250,000

 
$
150,000

 
$
250,000

 
$
150,000

 
$
250,000

Weighted average fixed interest rate
5.04
%
 
5.67
%
 
5.04
%
 
5.67
%
 
5.04
%
 
5.67
%
Maximum terms in years
4.50

 
1.50

 
5.00

 
2.00

 
5.50

 
0.50

Derivative liabilities, current
$
6,766

 
$
78,001

 
$
6,513

 
$
75,295

 
$
6,900

 
$
56,342

Derivative liabilities, non-current
$
18,976

 
$
15,336

 
$
20,363

 
$
20,696

 
$
15,788

 
$
—

Pre-tax accumulated other comprehensive income (loss)
$
(25,742
)
 
$
—

 
$
(26,876
)
 
$
—

 
$
(22,688
)
 
$
—

Pre-tax gain (loss)
$
—

 
$
(3,507
)
 
$
—

 
$
(42,010
)
 
$
—

 
$
(2,362
)
Cash collateral receivable (payable) included in derivative
$
—

 
$
6,160

 
$
—

 
$
—

 
$
—

 
$
—

_____________
*
Maximum terms in years reflect the amended early termination dates. If the early termination dates are not extended, the swaps will require cash settlement based on the swap value on the termination date. If extended, de-designated swaps totaling $100 million notional terminate in 6.5 years and de-designated swaps totaling $150 million notional terminate in 16.5 years.

Collateral requirements based on our corporate credit rating apply to $50 million of our de-designated swaps. At our current credit ratings, we are required to post collateral for any amount by which the swaps' negative mark-to-market fair value exceeds $20 million. If our senior unsecured credit rating drops to BB+ or below by S&P, or to Ba1 or below by Moody's, we would be required to post collateral for the entire amount of the swaps' negative mark-to-market fair value.

Based on June 30, 2012 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $6.8 million would be reclassified from AOCI during the next 12 months. Estimated and realized losses will change during future periods as market interest rates change.


(14)     FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

Assets and liabilities carried at fair value are classified and disclosed in one of the following categories:

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives.

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management's best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

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.


23


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 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

Oil and Gas Segment:

•
The commodity option contracts for the Oil and Gas segment are valued under the market approach and 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 multiple sources and therefore support Level 2 disclosure.

•
The commodity basis swaps for the Oil and Gas segment are valued under the market approach using 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 Level 2 disclosure.

Utilities Segment:

•
The commodity contracts for the Utilities, 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.

Corporate Segment:

•
The interest rate swaps are valued using the market valuation 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 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.


24


Recurring Fair Value Measurements

There have been no significant transfers between Level 1 and Level 2 derivative balances. The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):
 
 
As of June 30, 2012
 
 
Level 1
 
Level 2
 
Level 3
 
Counterparty
Netting
 
Cash Collateral
 
Total
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
 
 
 
 
 


    Options -- Oil
 
$
—

 
$
1,014

 
$
—

 
$
—

 
$
—

 
$
1,014

    Basis Swaps -- Oil
 
—

 
2,785

 
—

 
—

 
—