BKH 063013 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, 2013
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, 2013
Common stock, $1.00 par value
44,518,338

shares






TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms and Abbreviations
 
 
 
 
 
PART I.
FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income (Loss) - unaudited
 
 
 
   Three and Six Months Ended June 30, 2013 and 2012
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income (Loss)- unaudited
 
 
 
   Three and Six Months Ended June 30, 2013 and 2012
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   June 30, 2013, Dec. 31, 2012 and June 30, 2012
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Six Months Ended June 30, 2013 and 2012
 
 
 
 
 
 
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
Basin Electric
Basin Electric Power Cooperative
Bbl
Barrel
BHC
Black Hills Corporation; the Company
BHEP
Black Hills Exploration and Production, Inc., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, and Black Hills Gas Resources, Inc. and Black Hills Plateau Production, LLC, direct wholly-owned subsidiaries of Black Hills Exploration and Production, Inc.

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 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
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation
Cheyenne Prairie
Cheyenne Prairie Generating Station currently being constructed in Cheyenne, Wyo. by Cheyenne Light and Black Hills Power. Construction is expected to be completed for this 132 megawatt facility in 2014.
Colorado Electric
Black Hills Colorado Electric Utility Company, LP (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado 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, LLC a direct wholly-owned subsidiary of Black Hills Electric Generation
Cooling degree day
A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
Conflict Minerals
As defined by the Dodd-Frank, conflict minerals are cassiterite, columbite-tantalite, gold and wolframite that are mined in the Democratic Republic of the Congo or surrounding countries
CPCN
Certificate of Public Convenience and Necessity
CPUC
Colorado Public Utilities Commission
 
 
 
 
 
 
 
 
 
 
 
 
 
 

3



CTII
The 40 megawatt Gillette CT, a simple-cycle, gas-fired combustion turbine owned by Black Hills Wyoming
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 were subsequently de-designated
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)
Enserco
Enserco Energy Inc., representing our Energy Marketing segment, sold Feb. 29, 2012
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
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.
Iowa Gas
Black Hills Iowa Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP
Independent power producer
IRS
United States Internal Revenue Service
IUB
Iowa Utilities Board
Kansas Gas
Black Hills Kansas Gas Utility Company, LLC (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
LIBOR
London Interbank Offered Rate
LOE
Lease Operating Expense
Mcf
Thousand cubic feet of natural gas
Mcfe
Thousand cubic feet equivalent. Natural gas liquid is converted by dividing gallons by 7. Crude oil is converted by multiplying barrels by 6.
MMBtu
Million British thermal units
Moody’s
Moody’s Investors Service, Inc.
MWh
Megawatt-hour
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

4



 
 
 
 
NGL
Natural Gas Liquids. One gallon equals 1/7 Mcfe
NOL
Net Operating Loss
OTC
Over-the-counter
PPA
Power Purchase Agreement
PSCo
Public Service Company of Colorado
Revolving Credit Facility
Our $500 million credit facility which matures in 2017
SDPUC
South Dakota Public Utilities Commission
SEC
U. S. Securities and Exchange Commission
S&P
Standard and Poor’s, a division of The McGraw-Hill Companies, Inc.
WPSC
Wyoming Public Service Commission

5





BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(unaudited)
Three Months Ended June 30,
Six Months Ended June 30,
 
2013
2012
2013
2012
 
(in thousands, except per share and per share amounts)
 
 
 
 
 
Revenue
$
279,826

$
242,363

$
660,497

$
608,214

 
 
 
 
 
Operating expenses:
 
 
 
 
Utilities -
 
 
 
 
Fuel, purchased power and cost of gas sold
99,172

63,452

267,345

220,635

Operations and maintenance
64,977

59,563

130,667

124,323

Non-regulated energy operations and maintenance
20,890

20,713

42,219

43,308

Depreciation, depletion and amortization
35,152

41,431

69,933

79,990

Taxes - property, production and severance
10,069

9,478

20,449

20,988

Impairment of long-lived assets

26,868


26,868

Other operating expenses
529

267

1,001

1,463

Total operating expenses
230,789

221,772

531,614

517,575

 
 
 
 
 
Operating income
49,037

20,591

128,883

90,639

 
 
 
 
 
Other income (expense):
 
 
 
 
Interest charges -
 
 
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)
(23,369
)
(27,762
)
(47,041
)
(57,676
)
Allowance for funds used during construction - borrowed
410

963

484

1,481

Capitalized interest
272

131

538

292

Unrealized gain (loss) on interest rate swaps, net
18,793

(15,552
)
26,249

(3,507
)
Interest income
475

627

760

1,064

Allowance for funds used during construction - equity
42

195

242

472

Other income (expense), net
474

888

879

2,360

Total other income (expense), net
(2,903
)
(40,510
)
(17,889
)
(55,514
)
 
 
 
 
 
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes
46,134

(19,919
)
110,994

35,125

Equity in earnings (loss) of unconsolidated subsidiaries

22

(86
)
(34
)
Income tax benefit (expense)
(15,616
)
7,574

(37,193
)
(12,143
)
Income (loss) from continuing operations
30,518

(12,323
)
73,715

22,948

Income (loss) from discontinued operations, net of tax

(1,160
)

(6,644
)
Net income (loss) available for common stock
$
30,518

$
(13,483
)
$
73,715

$
16,304

 
 
 
 
 
Earnings (loss) per share, Basic -
 
 
 
 
Income (loss) from continuing operations, per share
$
0.69

$
(0.28
)
$
1.67

$
0.52

Income (loss) from discontinued operations, per share

(0.03
)

(0.15
)
Total income (loss) per share, Basic
$
0.69

$
(0.31
)
$
1.67

$
0.37

Earnings (loss) per share, Diluted -
 
 
 
 
Income (loss) from continuing operations, per share
$
0.69

$
(0.28
)
$
1.66

$
0.52

Income (loss) from discontinued operations, per share

(0.03
)

(0.15
)
Total income (loss) per share, Diluted
$
0.69

$
(0.31
)
$
1.66

$
0.37

Weighted average common shares outstanding:
 
 
 
 
Basic
44,172

43,799

44,113

43,765

Diluted
44,412

43,799

44,363

43,984

 
 
 
 
 
Dividends paid per share of common stock
$
0.380

$
0.370

$
0.760

$
0.740


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

6





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


(unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2013
2012
2013
2012
 
(in thousands)
 
 
 
 
 
Net income (loss) available for common stock
$
30,518

$
(13,483
)
$
73,715

$
16,304

 
 
 
 
 
Other comprehensive income (loss), net of tax:
 
 
 
 
Fair value adjustment on derivatives designated as cash flow hedges (net of tax (expense) benefit of $(2,174) and $(167) for the three months ended 2013 and 2012 and $(1,057) and $(112) for the six months ended 2013 and 2012, respectively)
3,878

11

2,217

587

Reclassification adjustments related to defined benefit plan (net of tax of $(268) and $0 for the three months ended 2013 and 2012 and $(443) and $0 for the six months ended 2013 and 2012, respectively)
364


821


Reclassification adjustments of cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $(647) and $432 for the three months ended 2013 and 2012 and $(883) and $877 for the six months ended 2013 and 2012, respectively)
1,201

(619
)
1,669

(1,361
)
Other comprehensive income (loss), net of tax
5,443

(608
)
4,707

(774
)
 
 
 
 
 
Comprehensive income (loss) available for common stock
$
35,961

$
(14,091
)
$
78,422

$
15,530


See Note 7 for additional disclosures.

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
(unaudited)
As of
 
June 30,
2013
 
Dec. 31, 2012
 
June 30,
2012
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
30,633

 
$
15,462

 
$
40,110

Restricted cash and equivalents
7,279

 
7,916

 
4,772

Accounts receivable, net
132,726

 
163,698

 
109,157

Materials, supplies and fuel
73,768

 
77,643

 
61,455

Derivative assets, current
903

 
3,236

 
16,595

Income tax receivable, net
146

 

 
12,141

Deferred income tax assets, net, current
38,764

 
77,231

 
30,401

Regulatory assets, current
26,258

 
31,125

 
34,781

Other current assets
27,595

 
28,795

 
26,591

Total current assets
338,072

 
405,106

 
336,003

 
 
 
 
 
 
Investments
16,566

 
16,402

 
16,208

 
 
 
 
 
 
Property, plant and equipment
4,066,502

 
3,930,772

 
3,863,380

Less: accumulated depreciation and depletion
(1,234,578
)
 
(1,188,023
)
 
(1,006,827
)
Total property, plant and equipment, net
2,831,924

 
2,742,749

 
2,856,553

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
353,396

 
353,396

 
353,396

Intangible assets, net
3,508

 
3,620

 
3,731

Derivative assets, non-current

 
510

 
1,770

Regulatory assets, non-current
180,646

 
188,268

 
186,886

Other assets, non-current
22,402

 
19,420

 
19,733

Total other assets, non-current
559,952

 
565,214

 
565,516

 
 
 
 
 
 
TOTAL ASSETS
$
3,746,514

 
$
3,729,471

 
$
3,774,280


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

8



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)
As of
 
June 30,
2013
 
Dec. 31, 2012
 
June 30,
2012
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
88,071

 
$
84,422

 
$
59,739

Accrued liabilities
135,819

 
154,389

 
158,240

Derivative liabilities, current
69,270

 
96,541

 
85,675

Accrued income tax, net

 
4,936

 

Regulatory liabilities, current
20,550

 
13,628

 
16,785

Notes payable
100,000

 
277,000

 
225,000

Current maturities of long-term debt
255,507

 
103,973

 
227,590

Total current liabilities
669,217

 
734,889

 
773,029

 
 
 
 
 
 
Long-term debt, net of current maturities
958,559

 
938,877

 
1,044,891

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
387,674

 
385,908

 
316,393

Derivative liabilities, non-current
12,384

 
16,941

 
42,077

Regulatory liabilities, non-current
129,013

 
127,656

 
114,593

Benefit plan liabilities
177,216

 
167,397

 
162,530

Other deferred credits and other liabilities
129,763

 
125,294

 
124,482

Total deferred credits and other liabilities
836,050

 
823,196

 
760,075

 
 
 
 
 
 
Commitments and contingencies (See Notes 5, 8, 10 and 13)


 

 

 
 
 
 
 
 
Stockholders’ equity:
 
 
 
 
 
Common stock equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 44,516,472; 44,278,189; and 44,176,520 shares, respectively
44,517

 
44,278

 
44,177

Additional paid-in capital
737,729

 
733,095

 
727,613

Retained earnings
532,810

 
492,869

 
460,324

Treasury stock, at cost – 42,480; 71,782; and 69,657 shares, respectively
(1,587
)
 
(2,245
)
 
(2,177
)
Accumulated other comprehensive income (loss)
(30,781
)
 
(35,488
)
 
(33,652
)
Total stockholders’ equity
1,282,688

 
1,232,509

 
1,196,285

 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
3,746,514

 
$
3,729,471

 
$
3,774,280


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

9



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
Six Months Ended June 30,
 
 
2013
2012
 
Operating activities:
(in thousands)
 
Net income (loss) available to common stock
$
73,715

$
16,304

 
(Income) loss from discontinued operations, net of tax

6,644

 
Income (loss) from continuing operations
73,715

22,948

 
Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
69,933

79,990

 
Deferred financing cost amortization
2,188

4,050

 
Impairment of long-lived assets

26,868

 
Derivative fair value adjustments
4,248

(4,895
)
 
Stock compensation
6,896

3,269

 
Unrealized (gain) loss on interest rate swaps, net
(26,249
)
3,507

 
Deferred income taxes
36,607

11,200

 
Employee benefit plans
11,096

10,492

 
Other adjustments, net
8,967

3,820

 
Changes in certain operating assets and liabilities:
 
 
 
Materials, supplies and fuel
8,940

22,609

 
Accounts receivable, unbilled revenues and other operating assets
28,377

64,028

 
Accounts payable and other current liabilities
(26,739
)
(60,233
)
 
Contributions to defined benefit pension plans

(25,000
)
 
Other operating activities, net
(594
)
(7,138
)
 
Net cash provided by operating activities of continuing operations
197,385

155,515

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

21,184

 
Net cash provided by operating activities
197,385

176,699

 
 
 
 
 
Investing activities:
 
 
 
Property, plant and equipment additions
(147,230
)
(148,807
)
 
Other investing activities
2,006

4,095

 
Net cash provided by (used in) investing activities of continuing operations
(145,224
)
(144,712
)
 
Proceeds from sale of discontinued business operations

108,837

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

(824
)
 
Net cash provided by (used in) investing activities
(145,224
)
(36,699
)
 
 
 
 
 
Financing activities:
 
 
 
Dividends paid on common stock
(33,774
)
(32,583
)
 
Common stock issued
2,570

1,510

 
Short-term borrowings - issuances
133,300

56,453

 
Short-term borrowings - repayments
(310,300
)
(176,453
)
 
Long-term debt - issuances
275,000


 
Long-term debt - repayments
(103,786
)
(10,418
)
 
Other financing activities

2,833

 
Net cash provided by (used in) financing activities of continuing operations
(36,990
)
(158,658
)
 
Net cash provided by (used in) financing activities of discontinued operations


 
Net cash provided by (used in) financing activities
(36,990
)
(158,658
)
 
Net change in cash and cash equivalents
15,171

(18,658
)
 
Cash and cash equivalents, beginning of period
15,462

58,768

*
Cash and cash equivalents, end of period
$
30,633

$
40,110

 
_______________
*
Includes cash of discontinued operations of $37.1 million at Dec. 31, 2011.

See Note 2 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.

10



BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2012 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 2012 Annual Report on Form 10-K filed with the SEC.

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

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying Condensed Consolidated Financial Statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2013, Dec. 31, 2012, and June 30, 2012 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market price. In particular, the normal peak usage season for electric utilities is June through August while the normal peak usage season for gas utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months ended June 30, 2013 and June 30, 2012, and our financial condition as of June 30, 2013, Dec. 31, 2012, and June 30, 2012 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 Feb. 29, 2012, we sold our Energy Marketing segment, which resulted in this segment being classified as discontinued operations.


11



Recently Adopted Accounting Standards

Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Income, ASU 2013-02

In February 2013, the FASB issued ASU 2013-02 which requires new disclosures for items reclassified out of AOCI. ASU 2013-02 requires disclosure of (1) changes in components of other comprehensive income, (2) items reclassified out of AOCI and into net income in their entirety, the effect of the reclassification on each affected net income line item and (3) cross references to other disclosures that provide additional detail for components of other comprehensive income that are not reclassified in their entirety to net income. Disclosures are required either on the face of the statements of income or as a separate disclosure in the notes to the financial statements. The new disclosure requirements are effective for interim and annual periods beginning after Dec. 15, 2012. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows. See additional disclosures in Note 7.

Balance Sheet: Disclosure about Offsetting Assets and Liabilities, ASU 2011-11

In December 2011, the FASB issued revised accounting guidance to amend disclosure requirements for offsetting financial assets and liabilities to enhance current disclosures. 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 Jan. 1, 2013. The adoption of this standard did not have an impact on our financial position, results of operations or cash flows. See additional disclosures in Note 11.

Recently Issued Accounting Pronouncements and Legislation

Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists

In July 2013, the FASB issued an amendment to accounting for income taxes which provides guidance on financial statement presentation of an unrecognized tax benefit when an NOL carryforward, a similar tax loss, or a tax credit carryforward exists. The objective in issuing this amendment is to eliminate diversity in practice resulting from a lack of guidance on this topic in current GAAP. Under the amendment, an entity must present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, in the financial statements as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward except under certain conditions. The amendment is effective for fiscal years beginning after Dec. 15, 2013, and interim periods within those years and should be applied to all unrecognized tax benefits that exist as of the effective date. The adoption of this standard is not expected to have an impact on our financial position, results of operations or cash flows.


12



Inclusion of the Fed Funds Effective Swap Rate as a Benchmark Interest Rate for Hedge Accounting Purposes, ASU 2013-10

In July 2013, the FASB issued an amendment to accounting for derivatives and hedges to permit the Fed Funds Effective Swap Rate to be used as a U.S. benchmark interest rate for hedge accounting purposes effective for new or re-designated hedging relationships entered into on or after July 17, 2013. The amendment also removed the restriction on using different benchmark rates for similar hedges. We will evaluate the impact of this amendment upon re-designating or entering into a new hedging relationship.

Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date, ASU 2013-04

In March 2013, the FASB issued new disclosure requirements for recognition, measurement and disclosure of obligations resulting from joint and several liability arrangements including disclosure of the nature and amount of the obligations. The new disclosure requirements are effective for interim and annual periods beginning after Dec. 15, 2013. The amendment requires additional details in the notes to financial statements, but will not have any other impact on our financial statements.

Dodd-Frank Wall Street Reform and Consumer Protection Act, SEC Final Rule No. 34-67716

In August 2012, under Dodd-Frank, the SEC adopted new requirements for companies that manufacture or contract to manufacture products that contain certain minerals and metals, known as conflict minerals. The final rule requires all issuers that file reports with the SEC, and use conflict minerals, to report supply chain and sourcing information on an annual basis. These new requirements will require due diligence efforts in 2013, with initial disclosure requirements beginning in May 2014. Based on our preliminary analysis, we do not believe that our products contain conflict minerals as defined by the rule; however, our assessment process to determine whether conflict minerals are necessary to the functionality or production of any of our products is not complete.


(2)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
 
Six Months Ended
 
June 30, 2013
 
June 30, 2012
 
(in thousands)
Non-cash investing and financing activities from continuing operations—
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
45,000

 
$
52,204

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

 
$
3,406

 
 
 
 
Cash (paid) refunded during the period for continuing operations—
 
 
 
Interest (net of amounts capitalized)
$
(44,191
)
 
$
(55,364
)
Income taxes, net
$
(5,406
)
 
$
(383
)



13



(3)    MATERIALS, SUPPLIES AND FUEL

The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
June 30, 2013
 
Dec. 31, 2012
 
June 30, 2012
Materials and supplies
$
51,334

 
$
43,397

 
$
41,963

Fuel - Electric Utilities
6,817

 
8,589

 
8,089

Natural gas in storage held for distribution
15,617

 
25,657

 
11,403

Total materials, supplies and fuel
$
73,768

 
$
77,643

 
$
61,455



(4)    ACCOUNTS RECEIVABLE

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
Accounts
Unbilled
Less Allowance for
Accounts
June 30, 2013
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
45,250

$
24,290

$
(630
)
$
68,910

Gas Utilities
38,749

13,192

(1,074
)
50,867

Power Generation
157



157

Coal Mining
2,503



2,503

Oil and Gas
8,373


(19
)
8,354

Corporate
1,935



1,935

Total
$
96,967

$
37,482

$
(1,723
)
$
132,726


 
Accounts
Unbilled
Less Allowance for
Accounts
Dec. 31, 2012
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
54,482

$
23,843

$
(527
)
$
77,798

Gas Utilities
31,495

39,962

(222
)
71,235

Power Generation
16



16

Coal Mining
2,247



2,247

Oil and Gas
11,622


(19
)
11,603

Corporate
799



799

Total
$
100,661

$
63,805

$
(768
)
$
163,698


14




 
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

Power Generation
197



197

Coal Mining
1,982



1,982

Oil and Gas
13,749


(105
)
13,644

Corporate
1,130



1,130

Total
$
74,021

$
36,811

$
(1,675
)
$
109,157



(5)    NOTES PAYABLE AND LONG-TERM DEBT

We had the following short-term debt outstanding in the Condensed Consolidated Balance Sheets (in thousands) as of:

 
June 30, 2013
Dec. 31, 2012
June 30, 2012
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$
100,000

$
43,157

$
127,000

$
36,300

$
75,000

$
36,256

Term Loan due June 2013


150,000


150,000


Total
$
100,000

$
43,157

$
277,000

$
36,300

$
225,000

$
36,256


Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of June 30, 2013, we were in compliance with all of these covenants.

Replacement of Notes Payable and Long-term Term Loan

On June 21, 2013, we entered into a new $275 million term loan expiring on June 19, 2015. This new term loan replaced the $150 million term loan due on June 24, 2013, the $100 million corporate term loan due on Sept. 30, 2013, and $25 million in short-term borrowing under our Revolving Credit Facility. At June 30, 2013, the cost of borrowing under this new term loan was 1.375 percent based on LIBOR plus a margin of 1.125 percent. The covenants of the new term loan are substantially the same as the Revolving Credit Facility.


15



Debt Covenants

Certain debt obligations require compliance with the following covenants at the end of each quarter (dollars in thousands):
 
As of
 
 
 
June 30, 2013
 
Covenant Requirement
Consolidated Net Worth
$
1,282,688

 
Greater than
$
961,752

Recourse Leverage Ratio
51.5
%
 
Less than
65.0
%



(6)    EARNINGS PER SHARE

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,
 
2013
2012
 
2013
2012
 
 
 
 
 
 
Income (loss) from continuing operations
$
30,518

$
(12,323
)
 
$
73,715

$
22,948

 
 
 
 
 
 
Weighted average shares - basic
44,172

43,799

 
44,113

43,765

Dilutive effect of:
 
 
 
 
 
Restricted stock
125


 
140

150

Stock options
12


 
13

15

Other dilutive effects
103


 
97

54

Weighted average shares - diluted
44,412

43,799

 
44,363

43,984


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.


16



In addition to these dilutive shares excluded due to our net loss for the quarter ended June 30, 2012, the following outstanding securities were not included in the computation of diluted earnings (loss) per share as their effect would have been anti-dilutive (in thousands):
 
Three Months Ended June 30,
Six Months Ended June 30,
 
2013
2012
2013
2012
Stock options
10

99

8

113

Restricted stock
18

66

26

48

Other stock

42


29

Anti-dilutive shares
28

207

34

190



(7)
OTHER COMPREHENSIVE INCOME (LOSS)

The components of the reclassification adjustments for the period, net of tax, included in Other Comprehensive Income (Loss) were as follows (in thousands):
 
Location on the Condensed Consolidated Statements of Income (Loss)
Amount Reclassified from AOCI
Three Months Ended
Six Months Ended
June 30, 2013
June 30, 2012
June 30, 2013
June 30, 2012
Gains (losses) on cash flow hedges:
 
 
 
 
 
Interest rate swaps
Interest expense
$
1,820

$
1,843

$
3,616

$
3,665

Commodity contracts
Revenue
28

(2,894
)
(1,064
)
(5,903
)
 
 
1,848

(1,051
)
2,552

(2,238
)
Income tax
Income tax benefit (expense)
(647
)
432

(883
)
877

Reclassification adjustments related to cash flow hedges, net of tax
 
$
1,201

$
(619
)
$
1,669

$
(1,361
)
 
 
 
 
 
 
Amortization of defined benefit plans:
 
 
 
 
 
Prior service cost
Utilities - Operations and maintenance
$
(31
)
$

$
(62
)
$

 
Non-regulated energy operations and maintenance
(32
)

(64
)

 
 
 
 
 
 
Actuarial gain (loss)
Utilities - Operations and maintenance
421


842


 
Non-regulated energy operations and maintenance
274


548


 
 
632


1,264


Income tax
Income tax benefit (expense)
(268
)

(443
)

Reclassification adjustments related to defined benefit plans, net of tax
 
$
364

$

$
821

$



17



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 Dec. 31, 2011
$
(13,802
)
$
(19,076
)
$
(32,878
)
Other comprehensive income (loss), net of tax
(166
)

(166
)
Balance as of March 31, 2012
(13,968
)
(19,076
)
(33,044
)
Other comprehensive income (loss), net of tax
(608
)

(608
)
Ending Balance June 30, 2012
$
(14,576
)
$
(19,076
)
$
(33,652
)
 
 
 
 
Balance as of Dec. 31, 2012
$
(15,713
)
$
(19,775
)
$
(35,488
)
Other comprehensive income (loss), net of tax
(1,193
)
457

(736
)
Balance as of March 31, 2013
(16,906
)
(19,318
)
(36,224
)
Other comprehensive income (loss), net of tax
5,079

364

5,443

Ending Balance June 30, 2013
$
(11,827
)
$
(18,954
)
$
(30,781
)


(8)    EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

The components of net periodic benefit cost for the Defined Benefit Pension Plans were as follows (in thousands):

 
Three Months Ended June 30,
Six Months Ended June 30,
 
2013
2012
2013
2012
Service cost
$
1,608

$
1,430

$
3,216

$
2,860

Interest cost
3,825

3,687

7,650

7,374

Expected return on plan assets
(4,654
)
(4,084
)
(9,308
)
(8,168
)
Prior service cost
16

22

32

44

Net loss (gain)
3,062

2,408

6,124

4,816

Net periodic benefit cost
$
3,857

$
3,463

$
7,714

$
6,926



18



Non-pension Defined Benefit Postretirement Healthcare Plans

The components of net periodic benefit cost for the Non-pension Defined Benefit Postretirement Healthcare Plans were as follows (in thousands):
 
Three Months Ended June 30,
Six Months Ended June 30,
 
2013
2012
2013
2012
Service cost
$
419

$
402

$
838

$
804

Interest cost
417

523

834

1,046

Expected return on plan assets
(20
)
(19
)
(40
)
(38
)
Prior service cost (benefit)
(125
)
(125
)
(250
)
(250
)
Net loss (gain)
121

222

242

444

Net periodic benefit cost
$
812

$
1,003

$
1,624

$
2,006


Supplemental Non-qualified Defined Benefit and Defined Contribution Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit and Defined Contribution Plans were as follows (in thousands):
 
Three Months Ended June 30,
Six Months Ended June 30,
 
2013
2012
2013
2012
Service cost
$
348

$
246

$
696

$
492

Interest cost
332

331

664

662

Prior service cost
1

1

2

2

Net loss (gain)
198

202

396

404

Net periodic benefit cost
$
879

$
780

$
1,758

$
1,560



19



Contributions

We anticipate that we will make contributions to the benefit plans during 2013 and 2014. Contributions to the Pension Plans are cash contributions made directly to the Pension Plan Trust accounts. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands):
 
Contributions Made
Contributions Made
Additional
 
 
Three Months Ended June 30, 2013
Six Months Ended June 30, 2013
Contributions Anticipated for 2013
Contributions Anticipated for 2014
Defined Benefit Pension Plans
$

$

$
12,500

$
12,500

Non-pension Defined Benefit Postretirement Healthcare Plans
$
784

$
1,568

$
1,568

$
3,350

Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
$
322

$
644

$
643

$
1,463



(9)    BUSINESS SEGMENT INFORMATION

Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) and Condensed Consolidated Balance Sheets are below.

Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income (Loss) were as follows (in thousands):
Three Months Ended June 30, 2013
 
External
Operating
Revenue
 
Intercompany
Operating
Revenue
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
154,338

 
$
3,694

 
$
10,610

   Gas
 
105,836

 

 
3,192

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,031

 
19,094

 
5,031

   Coal Mining
 
6,807

 
7,511

 
1,973

   Oil and Gas
 
11,814

 

 
(1,964
)
Corporate activities (a)
 

 

 
11,679

Intercompany eliminations
 

 
(30,299
)
 
(3
)
Total
 
$
279,826

 
$

 
$
30,518


20




Three Months Ended June 30, 2012
 
External
Operating
Revenue
 
Intercompany
Operating
Revenue
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
144,560

 
$
5,174

 
$
14,159

   Gas
 
70,386

 

 
1,159

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
759

 
17,975

 
3,926

   Coal Mining
 
6,037

 
7,090

 
1,234

   Oil and Gas (b)
 
20,621

 

 
(19,621
)
Corporate activities (a)
 

 

 
(13,180
)
Intercompany eliminations
 

 
(30,239
)
 

Total
 
$
242,363

 
$

 
$
(12,323
)

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

 
$
7,841

 
$
22,966

   Gas
 
305,648

 

 
21,675

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
2,053

 
38,432

 
10,675

   Coal Mining
 
12,817

 
15,084

 
3,038

   Oil and Gas
 
27,158

 

 
(2,017
)
Corporate (a)
 

 

 
17,378

Intercompany eliminations
 

 
(61,357
)
 

Total
 
$
660,497

 
$

 
$
73,715


21




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:
 
 
 
 
 
 
   Power Generation
 
1,937

 
36,424

 
10,840

   Coal Mining
 
12,410

 
15,706

 
2,234

   Oil and Gas (b)
 
42,266

 

 
(19,608
)
Corporate (a)(c)
 

 

 
(9,789
)
Intercompany eliminations
 

 
(60,340
)
 

Total
 
$
608,214

 
$

 
$
22,948

__________
(a)
Income (loss) from continuing operations includes a $12.2 million and a $17.1 million net after-tax non-cash mark-to-market gain on certain interest rate swaps for the three and six months ended June 30, 2013, respectively, and a $10.1 million and a $2.3 million net after-tax non-cash mark-to-market loss for the three and six months ended June 30, 2012, respectively, for those same interest rate swaps.
(b)
Income (loss) from continuing operations includes a $17.3 million non-cash after-tax ceiling test impairment charge. See Note 14 for further information.
(c)
Certain indirect corporate costs and inter-segment interest expense after-tax totaling $1.6 million for the six months ended June 30, 2012, were included in the Corporate activities in continuing operations and were not reclassified as discontinued operations.


22



Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets were as follows (in thousands):
Total Assets (net of inter-company eliminations) as of:
June 30, 2013
 
Dec. 31, 2012
 
June 30, 2012
Utilities:
 
 
 
 
 
   Electric (a)
$
2,417,952

 
$
2,387,458

 
$
2,300,948

   Gas
734,337

 
765,165

 
684,545

Non-regulated Energy:
 
 
 
 
 
   Power Generation (a)
108,515

 
119,170

 
122,856

   Coal Mining
82,553

 
83,810

 
90,021

   Oil and Gas
256,855

 
258,460

 
416,617

Corporate activities
146,302

 
115,408

 
159,293

Total assets
$
3,746,514

 
$
3,729,471

 
$
3,774,280

__________
(a)
The PPA pertaining to the portion of the Pueblo Airport Generation Station owned by Colorado IPP that supports Colorado customers is accounted for as a capital lease. Therefore, assets owned by the Power Generation segment are included in Total assets of Electric Utilities Segment under this accounting for a capital lease.


(10)    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 2012 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 including our project financing floating rate debt and our other long-term debt instruments.


23



Credit Risk

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

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

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

As of June 30, 2013, our credit exposure included a $0.6 million exposure to a non-investment grade energy marketing company. The remainder of our credit exposure was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included 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 within Note 11.

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 over-the-counter 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 on the accompanying Condensed Consolidated Balance Sheets and the ineffective portion, if any, is reported in Revenue on the accompanying Condensed Consolidated Statements of Income (Loss).


24



We had the following derivatives and related balances for our Oil and Gas segment (dollars in thousands) as of:
 
June 30, 2013
 
Dec. 31, 2012
 
June 30, 2012
 
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)
520,500

10,712,500

 
528,000

8,215,500

 
672,000

9,020,500

Maximum terms in years (b)
0.50

0.08

 
1.00

0.75

 
1.50

1.25

Derivative assets, current
$
610

$
293

 
$
1,405

$
1,831

 
$
2,483

$
4,386

Derivative assets, non-current
$

$

 
$
297

$
170

 
$
1,316

$
255

Derivative liabilities, current
$
130

$
276

 
$
847

$
507

 
$
456

$
452

Derivative liabilities, non-current
$

$

 
$

$

 
$
981

$
331

Pre-tax accumulated other comprehensive income (loss)
$
827

$
1,415

 
$
206

$
873

 
$
1,727

$
3,305

Cash collateral receivable (payable) included in derivatives
$
(142
)
$
(1,419
)
 
$
786

$
620

 
$
613

$
553

Cash collateral included in other assets or other liabilities
$
(149
)
$
(1,007
)
 
$
1,078

$
709

 
$
267

$
51

__________
(a)
Crude oil in Bbls, natural gas in MMBtus.
(b)
Refers to the term of the derivative instrument. Assets and liabilities are classified as current/non-current based on the term of the hedged transaction and the corresponding settlement of the derivative instrument.
Based on market prices at June 30, 2013, a $0.7 million gain would be reclassified from AOCI during the next 12 months. Estimated and actual realized gains or losses will change during future periods as market prices fluctuate.

Utilities

The operations of our utilities, including tolling arrangements, 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 accordance with state commission guidelines. Accordingly, the hedging activity is recognized in the Condensed Consolidated Statements of Income (Loss) or the Condensed Consolidated Statements of Comprehensive Income (Loss) when the related costs are recovered through our rates.


25



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, 2013
 
Dec. 31, 2012
 
June 30, 2012
 
Notional
(MMBtus)
 
Maximum
Term
(months)
 
Notional
(MMBtus)
 
Maximum
Term
(months)
 
Notional
(MMBtus)
 
Maximum
Term
(months)
Natural gas futures purchased
13,330,000

 
77
 
15,350,000

 
83
 
12,440,000

 
78
Natural gas options purchased
2,850,000

 
5
 
2,430,000

 
2
 
2,840,000

 
9
Natural gas basis swaps purchased
10,650,000

 
66
 
12,020,000

 
72
 
7,270,000

 
78

We had the following derivative balances related to the hedges in our Utilities (in thousands) as of:
 
June 30, 2013
Dec. 31, 2012
June 30, 2012
Derivative assets, current
$

$

$
9,726

Derivative assets, non-current
$

$
43

$
199

Derivative liabilities, non-current
$

$

$
6,453

Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities
$
8,450

$
9,596

$
13,691

 
 
 
 
Cash collateral receivable (payable) included in derivatives
$
7,203

$
8,576

$
15,925

Cash collateral included in Other current assets or liabilities
$
2,938

$
4,354

$

Option premiums and commissions included in derivatives
$
1,247

$
1,063

$
1,238



26



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, 2013
 
Dec. 31, 2012
 
June 30, 2012
 
Designated 
Interest Rate
Swaps (a)
De-designated
Interest Rate
Swaps (b)
 
Designated 
Interest Rate
Swaps (a)
De-designated
Interest Rate
Swaps (b)
 
Designated 
Interest Rate
Swaps (a)
De-designated
Interest Rate
Swaps (b)
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
3.50

0.50

 
4.00

1.00

 
4.50

1.50

Derivative liabilities, current
$
6,965

$
61,899

 
$
7,039

$
88,148

 
$
6,766

$
78,001

Derivative liabilities, non-current
$
12,384

$

 
$
16,941

$

 
$
18,976

$
15,336

Pre-tax accumulated other comprehensive income (loss)
$
(19,349
)
$

 
$
(23,980
)
$

 
$
(25,742
)
$

Pre-tax gain (loss)
$

$
26,249

 
$

$
1,882

 
$

$
(3,507
)
Cash collateral receivable (payable) included in derivatives
$

$
5,960

 
$

$
5,960

 
$

$
6,160

__________
(a)
These swaps have been designated to $75.0 million of borrowings on our Revolving Credit Facility and $75.0 million of borrowings on our project financing debt at Black Hills Wyoming. The swaps transferred to Black Hills Wyoming such that BHC and Black Hills Wyoming are both jointly and severally liable for the amount of those obligations. These swaps are priced using three-month LIBOR, matching the floating portion of the related swaps.
(b)
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 $100.0 million notional terminate in 5.5 years and de-designated swaps totaling $150.0 million notional terminate in 15.5 years.

Collateral requirements based on our corporate credit rating apply to $50.0 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 $20.0 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. We had $6.0 million cash collateral posted at June 30, 2013.

Based on June 30, 2013 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $7.0 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.

 

27



(11)    FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

The accounting guidance for fair value measurements requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. 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, 3 and 4 included in our 2012 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 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 under 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 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 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.


28



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 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.

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 gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis (in thousands):
 
As of June 30, 2013
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
Assets:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 


    Options -- Oil
$

$
45

$

 
$
(6
)
$
39

    Basis Swaps -- Oil

1,109


 
(538
)
571

    Options -- Gas



 


    Basis Swaps -- Gas

1,882


 
(1,589
)
293

Commodity derivatives — Utilities

1,378


 
(1,378
)

Cash equivalents (a)
30,633



 

30,633

Total
$
30,633

$
4,414

$

 
$
(3,511
)
$
31,536

 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 


    Options -- Oil
$

$
181

$

 
$
(98
)
$
83

    Basis Swaps -- Oil

350


 
(303
)
47

    Options -- Gas



 


    Basis Swaps -- Gas

445


 
(169
)
276

Commodity derivatives — Utilities
</