BKH 033113 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 March 31, 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 April 30, 2013
 
 
 
Common stock, $1.00 par value
44,442,886

shares






TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms and Abbreviations
 
 
 
 
 
PART I.
FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income - unaudited
 
 
 
   Three Months Ended March 31, 2013 and 2012
 
 
 
 
 
 
Condensed Consolidated Statements of Comprehensive Income - unaudited
 
 
 
   Three Months Ended March 31, 2013 and 2012
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   March 31, 2013, Dec. 31, 2012 and March 31, 2012
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Three Months Ended March 31, 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
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 Mineral
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
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

3



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.
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
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
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
NGL
Natural Gas Liquids. One gallon equals 7 Mcfe
OTC
Over-the-counter
PPA
Power Purchase Agreement
PSCo
Public Service Company of Colorado
Revolving Credit Facility
Our $500 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, 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

4





BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
 
Three Months Ended
March 31,
 
2013
2012
 
(in thousands, except per share amounts)
 
 
 
Revenue
$
380,671

$
365,851

 
 
 
Operating expenses:
 
 
Utilities -
 
 
Fuel, purchased power and cost of gas sold
168,173

157,183

Operations and maintenance
65,690

64,760

Non-regulated energy operations and maintenance
21,329

22,595

Depreciation, depletion and amortization
34,781

38,559

Taxes - property, production and severance
10,380

11,510

Other operating expenses
472

1,196

Total operating expenses
300,825

295,803

 
 
 
Operating income
79,846

70,048

 
 
 
Other income (expense):
 
 
Interest charges -
 
 
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts and realized settlements on interest rate swaps)
(23,672
)
(29,914
)
Allowance for funds used during construction - borrowed
74

518

Capitalized interest
266

161

Unrealized gain (loss) on interest rate swaps, net
7,456

12,045

Interest income
285

437

Allowance for funds used during construction - equity
200

277

Other income (expense), net
405

1,472

Total other income (expense)
(14,986
)
(15,004
)
 
 
 
Income (loss) from continuing operations before earnings (loss) of unconsolidated subsidiaries and income taxes
64,860

55,044

Equity in earnings (loss) of unconsolidated subsidiaries
(86
)
(56
)
Income tax benefit (expense)
(21,577
)
(19,717
)
Income (loss) from continuing operations
43,197

35,271

Income (loss) from discontinued operations, net of tax

(5,484
)
Net income (loss) available for common stock
$
43,197

$
29,787

 
 
 
Earnings (loss) per share, Basic -
 
 
Income (loss) from continuing operations, per share
$
0.98

$
0.81

Income (loss) from discontinued operations, per share

(0.13
)
Total income (loss) per share, Basic
$
0.98

$
0.68

Earnings (loss) per share, Diluted -
 
 
Income (loss) from continuing operations, per share
$
0.97

$
0.80

Income (loss) from discontinued operations, per share

(0.12
)
Total income (loss) per share, Diluted
$
0.97

$
0.68

Weighted average common shares outstanding:
 
 
Basic
44,053

43,731

Diluted
44,312

43,969

 
 
 
Dividends paid per share of common stock
$
0.380

$
0.370


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

5





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

 
Three Months Ended
March 31,
 
2013
2012
 
(in thousands)
 
 
 
Net income (loss) available for common stock
$
43,197

$
29,787

 
 
 
Other comprehensive income (loss), net of tax:
 
 
Fair value adjustment on derivatives designated as cash flow hedges (net of tax (expense) benefit of $1,117 and $55, respectively)
(1,661
)
576

Reclassification adjustments related to defined benefit plan (net of tax of $(175) and $0)
457


Reclassification adjustments of cash flow hedges settled and included in net income (loss) (net of tax (expense) benefit of $(236) and $445, respectively)
468

(742
)
Other comprehensive income (loss), net of tax
(736
)
(166
)
 
 
 
Comprehensive income (loss) available for common stock
$
42,461

$
29,621


See Note 8 for additional disclosures.

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


6



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)

 
As of
 
March 31,
2013
 
Dec. 31, 2012
 
March 31,
2012
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
12,397

 
$
15,462

 
$
56,132

Restricted cash and equivalents
6,846

 
7,916

 
8,960

Accounts receivable, net
168,783

 
163,698

 
143,987

Materials, supplies and fuel
64,189

 
77,643

 
63,236

Derivative assets, current
1,630

 
3,236

 
17,877

Income tax receivable, net

 

 
10,399

Deferred income tax assets, net, current
38,196

 
77,231

 
23,710

Regulatory assets, current
23,422

 
31,125

 
56,282

Other current assets
28,260

 
28,795

 
26,546

Total current assets
343,723

 
405,106

 
407,129

 
 
 
 
 
 
Investments
16,545

 
16,402

 
16,451

 
 
 
 
 
 
Property, plant and equipment
3,977,704

 
3,930,772

 
3,800,011

Less accumulated depreciation and depletion
(1,210,833
)
 
(1,188,023
)
 
(980,944
)
Total property, plant and equipment, net
2,766,871

 
2,742,749

 
2,819,067

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
353,396

 
353,396

 
353,396

Intangible assets, net
3,565

 
3,620

 
3,787

Derivative assets, non-current

 
510

 
881

Regulatory assets, non-current
181,119

 
188,268

 
186,093

Other assets, non-current
21,367

 
19,420

 
21,132

Total other assets, non-current
559,447

 
565,214

 
565,289

 
 
 
 
 
 
TOTAL ASSETS
$
3,686,586

 
$
3,729,471

 
$
3,807,936


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

7



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)


 
As of
 
March 31,
2013
 
Dec. 31, 2012
 
March 31,
2012
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
82,437

 
$
84,422

 
$
59,793

Accrued liabilities
140,230

 
154,389

 
151,130

Derivative liabilities, current
89,112

 
96,541

 
76,389

Accrued income tax, net
1,157

 
4,936

 

Regulatory liabilities, current
19,020

 
13,628

 
35,414

Notes payable
245,000

 
277,000

 
225,000

Current maturities of long-term debt
104,637

 
103,973

 
8,977

Total current liabilities
681,593

 
734,889

 
556,703

 
 
 
 
 
 
Long-term debt, net of current maturities
936,477

 
938,877

 
1,272,016

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, net, non-current
367,502

 
385,908

 
317,369

Derivative liabilities, non-current
15,237

 
16,941

 
43,169

Regulatory liabilities, non-current
126,573

 
127,656

 
112,516

Benefit plan liabilities
172,353

 
167,397

 
157,623

Other deferred credits and other liabilities
125,958

 
125,294

 
123,848

Total deferred credits and other liabilities
807,623

 
823,196

 
754,525

 
 
 
 
 
 
Commitments and contingencies (See Notes 6, 9, 11 and 14)


 

 

 
 
 
 
 
 
Stockholders’ equity:
 
 
 
 
 
Common stock equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 44,482,304; 44,278,189; and 44,151,428 shares, respectively
44,482

 
44,278

 
44,151

Additional paid-in capital
735,000

 
733,095

 
725,512

Retained earnings
519,184

 
492,869

 
490,114

Treasury stock, at cost – 41,606; 71,782; and 65,015 shares, respectively
(1,549
)
 
(2,245
)
 
(2,041
)
Accumulated other comprehensive income (loss)
(36,224
)
 
(35,488
)
 
(33,044
)
Total stockholders’ equity
1,260,893

 
1,232,509

 
1,224,692

 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
3,686,586

 
$
3,729,471

 
$
3,807,936


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

8



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
 
Three Months Ended March 31,
 
2013
2012
 
(in thousands)
Operating activities:
 
 
Net income (loss) available to common stock
$
43,197

$
29,787

(Income) loss from discontinued operations, net of tax

5,484

Income (loss) from continuing operations
43,197

35,271

Adjustments to reconcile income (loss) from continuing operations to net cash provided by operating activities:
 
 
Depreciation, depletion and amortization
34,781

38,559

Deferred financing cost amortization
1,095

2,719

Derivative fair value adjustments
3,673

1,594

Stock compensation
3,778

1,817

Unrealized mark-to-market (gain) loss on interest rate swaps
(7,456
)
(12,045
)
Deferred income taxes
20,541

18,083

Allowance for funds used during construction - equity
(200
)
(277
)
Employee benefit plans
5,548

5,246

Other adjustments, net
3,614

2,243

Changes in certain operating assets and liabilities:
 
 
Materials, supplies and fuel
18,519

20,828

Accounts receivable, unbilled revenues and other current assets
(9,166
)
9,439

Accounts payable and other current liabilities
(13,637
)
(42,368
)
Regulatory assets
9,463

(776
)
Regulatory liabilities
374

18,938

Contributions to defined benefit pension plans

(25,000
)
Other operating activities, net
(4,892
)
610

Net cash provided by operating activities of continuing operations
109,232

74,881

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

21,184

Net cash provided by operating activities
109,232

96,065

 
 
 
Investing activities:
 
 
Property, plant and equipment additions
(63,939
)
(67,652
)
Other investing activities
1,030

1,105

Net cash provided by (used in) investing activities of continuing operations
(62,909
)
(66,547
)
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
(62,909
)
41,466

 
 
 
Financing activities:
 
 
Dividends paid on common stock
(16,882
)
(16,276
)
Common stock issued
1,231

764

Short-term borrowings - issuances
78,500

56,453

Short-term borrowings - repayments
(110,500
)
(176,453
)
Long-term debt - repayments
(1,737
)
(1,897
)
Other financing activities

(2,758
)
Net cash provided by (used in) financing activities of continuing operations
(49,388
)
(140,167
)
Net cash provided by (used in) financing activities of discontinued operations


Net cash provided by (used in) financing activities
(49,388
)
(140,167
)
Net change in cash and cash equivalents
(3,065
)
(2,636
)
Cash and cash equivalents, beginning of period*
15,462

58,768

Cash and cash equivalents, end of period
$
12,397

$
56,132

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

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.

9



BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 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 March 31, 2013, Dec. 31, 2012 and March 31, 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 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 months ended March 31, 2013 and March 31, 2012, and our financial condition as of March 31, 2013, Dec. 31, 2012, and March 31, 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.


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

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) for 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 8.



10



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, 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 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 12.

Recently Issued Accounting Pronouncements and Legislation

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 Aug. 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 rules requires all issuers that file reports with the SEC to report supply chain and sourcing information for companies that use conflict minerals on an annual basis. These new requirements will require due diligence efforts in fiscal 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.


(3)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
 
Three Months Ended
 
March 31, 2013
 
March 31, 2012
 
(in thousands)
Non-cash investing and financing activities from continuing operations—
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
31,780

 
$
31,644

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

 
$
2,826

 
 
 
 
Cash (paid) refunded during the period for continuing operations—
 
 
 
Interest (net of amounts capitalized)
$
(12,768
)
 
$
(16,799
)
Income taxes, net
$
(4,656
)
 
$
(1,838
)



11



(4)    MATERIALS, SUPPLIES AND FUEL

The following amounts by major classification are included in Materials, supplies and fuel in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
March 31, 2013
 
Dec. 31, 2012
 
March 31, 2012
Materials and supplies
$
50,401

 
$
43,397

 
$
44,361

Fuel - Electric Utilities
8,445

 
8,589

 
7,812

Natural gas in storage held for distribution
5,343

 
25,657

 
11,063

Total materials, supplies and fuel
$
64,189

 
$
77,643

 
$
63,236



(5)    ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Following is a summary of Accounts receivable, net included in the accompanying Condensed Consolidated Balance Sheets (in thousands) as of:
 
Accounts
Unbilled
Less Allowance for
Accounts
March 31, 2013
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
47,896

$
21,591

$
(623
)
$
68,864

Gas Utilities
59,024

28,439

(751
)
86,712

Power Generation
3



3

Coal Mining
1,857



1,857

Oil and Gas
10,340


(19
)
10,321

Corporate
1,026



1,026

Total
$
120,146

$
50,030

$
(1,393
)
$
168,783


 
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


 
Accounts
Unbilled
Less Allowance for
Accounts
March 31, 2012
Receivable, Trade
Revenue
 Doubtful Accounts
Receivable, net
Electric Utilities
$
44,356

$
19,381

$
(585
)
$
63,152

Gas Utilities
44,287

18,502

(936
)
61,853

Power Generation
265



265

Coal Mining
2,578



2,578

Oil and Gas
15,014


(105
)
14,909

Corporate
1,230



1,230

Total
$
107,730

$
37,883

$
(1,626
)
$
143,987



12




(6)    NOTES PAYABLE

Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of March 31, 2013, we were in compliance with all of these covenants.

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

 
March 31, 2013
Dec. 31, 2012
March 31, 2012
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$
95,000

$
36,500

$
127,000

$
36,300

$
75,000

$
41,200

Term Loan due June 2013
150,000


150,000


150,000


Total
$
245,000

$
36,500

$
277,000

$
36,300

$
225,000

$
41,200


Debt Covenants

Certain debt obligations require compliance with the following covenants at the end of each quarter (dollars in thousands):

 
As of
 
 
 
March 31, 2013
 
Covenant Requirement
Consolidated Net Worth
$
1,260,893

 
Greater than
$
946,493

Recourse Leverage Ratio
52.2
%
 
Less than
65.0
%


(7)    EARNINGS PER SHARE

A reconciliation of share amounts used to compute Earnings (loss) per share is as follows (in thousands):

 
Three Months Ended
March 31,
 
2013
2012
 
 
 
Income (loss) from continuing operations
$
43,197

$
35,271

 
 
 
Weighted average shares - basic
44,053

43,731

Dilutive effect of:
 
 
Restricted stock
155

147

Stock options
13

18

Other dilutive effects
91

73

Weighted average shares - diluted
44,312

43,969


13




The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):
 
Three Months Ended
March 31,
 
2013
2012
Stock options
6

127

Restricted stock
34

31

Other stock

16

Anti-dilutive shares
40

174



(8)
OTHER COMPREHENSIVE INCOME

The components of the reclassification adjustments for the period, net of tax, included in Other Comprehensive Income were as follows (in thousands):
 
Location on the Condensed Consolidated Statements of Income
Amount Reclassified from AOCI
 
Three Months Ended March 31, 2013
Three Months Ended March 31, 2012
Gains and losses on cash flow hedges:
 
 
 
 
Interest rate swaps
Interest expense
$
1,796

$
1,822

 
Commodity contracts
Revenue
(1,092
)
(3,009
)
 
 
 
704

(1,187
)
 
Income tax
Income tax benefit (expense)
(236
)
445

 
Total reclassification adjustments related to cash flow hedges, net of tax
 
$
468

$
(742
)
 
 
 
 
 
 
Amortization of defined benefit plans:
 
 
 
 
Prior service cost
Utilities - Operations and maintenance
$
(31
)
$

 
 
Non-regulated energy operations and maintenance
(32
)

 
 
 
 
 
 
Actuarial gain (loss)
Utilities - Operations and maintenance
421


 
 
Non-regulated energy operations and maintenance
274


 
 
 
632


 
Income tax
Income tax benefit (expense)
(175
)

 
Total reclassification adjustments related to defined benefit plans, net of tax
 
$
457

$

 


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), net of tax
(166
)

(166
)
Ending Balance March 31, 2012
$
(13,968
)
$
(19,076
)
$
(33,044
)
 
 
 
 
Balance as of December 31, 2012
$
(15,713
)
$
(19,775
)
$
(35,488
)
Other comprehensive income (loss), net of tax
(1,193
)
457

(736
)
Ending Balance March 31, 2013
$
(16,906
)
$
(19,318
)
$
(36,224
)


(9)    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
March 31,
 
2013
2012
Service cost
$
1,608

$
1,430

Interest cost
3,825

3,687

Expected return on plan assets
(4,654
)
(4,084
)
Prior service cost
16

22

Net loss (gain)
3,062

2,408

Net periodic benefit cost
$
3,857

$
3,463


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
March 31,
 
2013
2012
Service cost
$
419

$
402

Interest cost
417

523

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

222

Net periodic benefit cost
$
812

$
1,003



15



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
March 31,
 
2013
2012
Service cost
$
348

$
246

Interest cost
332

331

Prior service cost
1

1

Net loss (gain)
198

202

Net periodic benefit cost
$
879

$
780


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
Additional
 
 
Three Months Ended March 31, 2013
Contributions Anticipated for 2013
Contributions Anticipated for 2014
Defined Benefit Pension Plans
$

$
8,787

$
19,922

Non-pension Defined Benefit Postretirement Healthcare Plans
$
784

$
2,352

$
3,350

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

$
965

$
1,463



(10)    BUSINESS SEGMENT INFORMATION

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

On Feb. 29, 2012, we sold our Energy Marketing segment, Enserco, which resulted in this segment being classified 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 Corporate activity.


16



Segment information and Corporate activities included in the accompanying Condensed Consolidated Statements of Income was as follows (in thousands):
Three Months Ended March 31, 2013
 
External
Operating
Revenue
 
Intercompany
Operating
Revenue
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
158,483

 
$
4,147

 
$
12,356

   Gas
 
199,812

 

 
18,483

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,022

 
19,338

 
5,644

   Coal Mining
 
6,010

 
7,573

 
1,065

   Oil and Gas
 
15,344

 

 
(53
)
Corporate activities (a)
 

 

 
5,699

Intercompany eliminations
 

 
(31,058
)
 
3

Total
 
$
380,671

 
$

 
$
43,197


Three Months Ended March 31, 2012
 
External
Operating
Revenue
 
Intercompany
Operating
Revenue
 
Income (Loss) from Continuing Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
156,133

 
$
3,036

 
$
8,746

   Gas
 
180,522

 

 
15,207

Non-regulated Energy:
 
 
 
 
 
 
   Power Generation
 
1,178

 
18,449

 
6,914

   Coal Mining
 
6,373

 
8,616

 
1,000

   Oil and Gas  
 
21,645

 

 
13

Corporate activities (a)(b)
 

 

 
3,391

Intercompany eliminations
 

 
(30,101
)
 

Total
 
$
365,851

 
$

 
$
35,271

_____________
(a)
Income (loss) from continuing operations includes a $4.8 million and a $7.8 million net after-tax non-cash mark-to-market gain for the three months ended March 31, 2013 and 2012, respectively.
(b)
Certain indirect corporate costs and inter-segment interest expense after-tax totaling $1.6 million for the three months ended March 31, 2012 were included in the Corporate activities in continuing operations and were not reclassified as discontinued operations.
 
 
 
 
 
 
 
 
 
 
 
 
 
 

17



Segment information and Corporate balances included in the accompanying Condensed Consolidated Balance Sheets was as follows (in thousands):
Total Assets (net of inter-company eliminations) as of:
March 31, 2013
 
Dec. 31, 2012
 
March 31, 2012
Utilities:
 
 
 
 
 
   Electric (a)
$
2,367,014

 
$
2,387,458

 
$
2,268,524

   Gas
752,468

 
765,165

 
717,185

Non-regulated Energy:
 
 
 
 
 
   Power Generation (a)
115,708

 
119,170

 
128,225

   Coal Mining
82,839

 
83,810

 
87,139

   Oil and Gas
255,786

 
258,460

 
430,851

Corporate activities
112,771

 
115,408

 
176,012

Total assets
$
3,686,586

 
$
3,729,471

 
$
3,807,936

___________
(a)
The PPA under which the Pueblo Airport Generation site owned by Colorado IPP 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.


(11)    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 with crude oil and natural gas reserves and production and fuel procurement for certain of our gas-fired generation assets; and

Interest rate risk associated with our variable rate credit facility, project financing floating rate debt and our other long-term debt instruments.

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 March 31, 2013, our credit exposure included a $2.3 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 and Condensed Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 12.


18



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.

We had the following derivatives and related balances for our Oil and Gas segment (dollars in thousands) as of:
 
March 31, 2013
 
Dec. 31, 2012
 
March 31, 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)
522,000

10,633,000

 
528,000

8,215,500

 
522,000

5,001,750

Maximum terms in years (b)
0.75

0.5

 
1

0.75

 
1.25

1.5

Derivative assets, current
$
821

$
287

 
$
1,405

$
1,831

 
$
406

$
8,256

Derivative assets, non-current
$

$

 
$
297

$
170

 
$
46

$
808

Derivative liabilities, current
$
250

$
1,188

 
$
847

$
507

 
$
2,904

$

Derivative liabilities, non-current
$

$

 
$

$

 
$
1,084

$

Pre-tax accumulated other comprehensive income (loss)
$
10

$
(2,781
)
 
$
206

$
873

 
$
(3,566
)
$
9,064

Cash collateral receivable (payable) included in derivatives
$
730

$
1,880

 
$
786

$
620

 
$

$

Cash collateral included in Other current assets
$
723

$
2,102

 
$
1,078

$
709

 
$

$

____________
(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 March 31, 2013 market prices, a $0.2 million loss 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.


19



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. 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 or the Condensed Consolidated Statements of Comprehensive Income (Loss) 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 Gas Utilities were as follows, as of:
 
March 31, 2013
 
Dec. 31, 2012
 
March 31, 2012
 
Notional
(MMBtus)
 
Maximum
Term
(months)
 
Notional
(MMBtus)
 
Maximum
Term
(months)
 
Notional
(MMBtus)
 
Maximum
Term
(months)
Natural gas futures purchased
13,180,000

 
80
 
15,350,000

 
83
 
11,550,000

 
81
Natural gas options purchased
440,000

 
5
 
2,430,000

 
2
 
670,000

 
12
Natural gas basis swaps purchased
11,350,000

 
69
 
12,020,000

 
72
 
7,640,000

 
81

We had the following derivative balances related to the hedges in our Utilities (in thousands) as of:
 
March 31, 2013
 
Dec. 31, 2012
 
March 31, 2012
Derivative assets, current
$
522

 
$

 
$
9,215

Derivative assets, non-current
$

 
$
43

 
$
27

Derivative liabilities, non-current
$

 
$

 
$
6,407

Net unrealized (gain) loss included in Regulatory assets or Regulatory liabilities
$
4,315

 
$
9,596

 
$
15,223

 
 
 
 
 
 
Cash collateral receivable (payable) included in derivatives
$
4,487

 
$
8,576

 
$
17,651

Cash collateral included in Other current assets
$
3,295

 
$
4,354

 
$

Option premiums and commissions included in derivatives
$
350

 
$
1,063

 
$
407



20



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:
 
March 31, 2013
 
Dec. 31, 2012
 
March 31, 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
3.75

0.75

 
4.00

1.00

 
4.75

1.75

Derivative liabilities, current
$
6,982

$
80,692

 
$
7,039

$
88,148

 
$
6,777

$
66,708

Derivative liabilities, non-current
$
15,237

$

 
$
16,941

$

 
$
18,441

$
17,237

Pre-tax accumulated other comprehensive income (loss)
$
(22,219
)
$

 
$
(23,980
)
$

 
$
(25,218
)
$

Pre-tax gain (loss)
$

$
7,456

 
$

$
1,882

 
$

$
12,045

Cash collateral receivable (payable) included in derivatives
$

$
5,960

 
$

$
5,960

 
$

$

_____________
(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 6 years and de-designated swaps totaling $150.0 million notional terminate in 16 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 March 31, 2013.

Based on March 31, 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.


(12)    FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

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.


21



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 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 Segment:

The commodity contracts for our 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 since these instruments are not traded on an exchange.

Corporate Activities:

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



22



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 March 31, 2013
 
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
Assets:
 
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 


    Options -- Oil
 
$

$
71

$

 
$
(11
)
$
60

    Basis Swaps -- Oil
 

836


 
(75
)
761

    Options -- Gas
 



 


    Basis Swaps -- Gas
 

435


 
(148
)
287

Commodity derivatives — Utilities
 

1,897


 
(1,375
)
522

Cash equivalents (a)
 
12,397



 

12,397

Total
 
$
12,397

$
3,239

$

 
$
(1,609
)
$
14,027

 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 


    Options -- Oil
 
$

$
396

$

 
$
(204
)
$
192

    Basis Swaps -- Oil
 

670


 
(612
)
58

    Options -- Gas
 



 


    Basis Swaps -- Gas
 

3,216


 
(2,028
)
1,188

Commodity derivatives — Utilities
 

5,862


 
(5,862
)

Interest rate swaps
 

108,871


 
(5,960
)
102,911

Total
 
$

$
119,015

$

 
$
(14,666
)
$
104,349

______________
(a)
Level 1 assets and liabilities are described in Note 13.


23




 
 
As of Dec. 31, 2012
 
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
Assets:
 
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
 
Options -- Oil
 
$

$
378

$

 
$

$
378

Basis Swaps -- Oil
 

1,325


 

1,325

Options -- Gas
 



 


Basis Swaps -- Gas
 

2,000


 

2,000

Commodity derivatives —Utilities
 


43

(b) 

43

Cash equivalents (a)
 
15,462



 

15,462

Total
 
$
15,462

$
3,703

$
43

 
$

$
19,208

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

$
1,131

$

 
$
(336
)
$
795

Basis Swaps -- Oil
 

502


 
(450
)
52

Options -- Gas
 



 


Basis Swaps -- Gas
 

1,127


 
(620
)
507

Commodity derivatives — Utilities
 

10,162


 
(10,162
)

Interest rate swaps
 

118,088


 
(5,960
)
112,128

Total
 
$

$
131,010

$

 
$
(17,528
)
$
113,482

______________
(a)
Level 1 assets and liabilities are described in Note 13.
(b)
The significant unobservable inputs used in the fair value measurement of the long-term OTC contracts are based on the average of price quotes from an independent third party market participant and the OTC contract broker. The unobservable inputs are long-term natural gas prices. Significant changes to these inputs along with the contract term would impact the derivative asset/liability and regulatory asset/liability, but will not impact the results of operations until the contract is settled under the original terms of the contract. The contracts will be classified as Level 2 once settlement is within 60 months of maturity and quoted market prices from a market exchange are available.


24



 
 
As of March 31, 2012
 
 
Level 1
Level 2
Level 3
 
Cash Collateral and Counterparty
Netting
Total
Assets:
 
 
 
 
 
 
 
Commodity derivatives — Oil and Gas
 
 
 
 
 
 
 
Options -- Oil
 
$

$
404

$

 
$

$
404

Basis Swaps -- Oil
 

48


 

48

Options -- Gas
 



 


Basis Swaps -- Gas
 

9,064


 

9,064

Commodity derivatives — Utilities
 

(8,412
)
3

(b) 
17,651

9,242

Cash equivalents (a)
 
55,919



 

55,919

Total
 
$
55,919

$
1,104

$
3

 
$
17,651

$
74,677

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

$
1,347

$

 
$

$
1,347

Basis Swaps -- Oil
 

2,641


 

2,641

Options -- Gas
 



 


Basis Swaps -- Gas
 



 


Commodity derivatives — Utilities
 

6,359

48

(b) 

6,407

Interest rate swaps
 

109,163


 

109,163

Total
 
$

$
119,510

$
48

 
$

$
119,558

______________
(a)
Level 1 assets and liabilities are described in Note 13.
(b)
The significant unobservable inputs used in the fair value measurement of the long-term OTC contracts are based on the average of price quotes from an independent third party market participant and the OTC contract broker. The unobservable inputs are long-term natural gas prices. Significant changes to these inputs along with the contract term would impact the derivative asset/liability and regulatory asset/liability, but will not impact the results of operations until the contract is settled under the original terms of the contract. The contracts will be classified as Level 2 once settlement is within 60 months of maturity and quoted market prices from a market exchange are available.

Fair Value Measures By Balance Sheet Classification

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis and reflect the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the amounts do not include net cash collateral on deposit in margin accounts at March 31, 2013, Dec. 31, 2012, and March 31, 2012, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the balances are not indicative of either our actual credit exposure or net economic exposure. Additionally, the amounts below will not agree with the amounts presented on our Condensed Consolidated Balance Sheets, nor will they correspond to the fair value measurements presented in Note 11.


25



The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):
As of March 31, 2013
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
832

$

Commodity derivatives
Derivative assets — non-current
 
206


Commodity derivatives
Derivative liabilities — current
 

3,110

Commodity derivatives
Derivative liabilities — non-current
 

1,114

Interest rate swaps
Derivative liabilities — current
 

6,982

Interest rate swaps
Derivative liabilities — non-current
 

15,237

Total derivatives designated as hedges
 
 
$
1,038

$
26,443

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
2,201

$

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 

58

Commodity derivatives
Derivative liabilities — non-current
 

5,862

Interest rate swaps
Derivative liabilities — current
 

86,652

Interest rate swaps
Derivative liabilities — non-current
 


Total derivatives not designated as hedges
 
 
$
2,201

$
92,572


As of Dec. 31, 2012
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
2,874

$

Commodity derivatives
Derivative assets — non-current
 
510


Commodity derivatives
Derivative liabilities — current
 

1,993

Commodity derivatives
Derivative liabilities — non-current
 

821

Interest rate swaps
Derivative liabilities — current
 

7,038

Interest rate swaps
Derivative liabilities — non-current
 

16,941

Total derivatives designated as hedges
 
 
$
3,384

$
26,793

 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
362

$

Commodity derivatives
Derivative assets — non-current
 


Commodity derivatives
Derivative liabilities — current
 
1,180

4,957

Commodity derivatives
Derivative liabilities — non-current
 
406

5,153

Interest rate swaps
Derivative liabilities — current
 

94,108

Interest rate swaps
Derivative liabilities — non-current
 


Total derivatives not designated as hedges
 
 
$
1,948

$
104,218



26



As of March 31, 2012
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
8,662

$

Commodity derivatives
Derivative assets — non-current
 
854


Commodity derivatives
Derivative liabilities — current
 

2,904

Commodity derivatives
Derivative liabilities — non-current
 

1,084

Interest rate swaps
Derivative liabilities — current
 

6,777

Interest rate swaps
Derivative liabilities — non-current
 

18,441

Total derivatives designated as hedges
 
 
$
9,516

$
29,206

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

$
8,436

Commodity derivatives
Derivative assets — non-current
 

(27
)
Commodity derivatives
Derivative liabilities — current
 


Commodity derivatives
Derivative liabilities — non-current
 

6,407

Interest rate swaps
Derivative liabilities — current
 

66,708

Interest rate swaps
Derivative liabilities — non-current
 

17,237

Total derivatives not designated as hedges
 
 
$

$
98,761


Derivatives Offsetting

It is our policy to offset in our Condensed Consolidated Balance Sheets contracts which provide for legally enforceable netting for our accounts receivable and payable and derivative activities. The tables below do not reflect accounts receivable or accounts payable subject to master netting agreements.

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis and reflect the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under the terms of our master netting agreements. Additionally, the amounts reflect cash collateral on deposit in margin accounts at March 31, 2013, Dec. 31, 2012, and March 31, 2012, to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross balances are not indicative of either our actual credit exposure or net economic exposure.



27



Offsetting of derivative assets and derivative liabilities as of March 31, 2013 (in thousands):
Derivative Assets
Gross Amounts of Derivative Assets
Gross Amounts Offset on Condensed Consolidated Balance Sheets
Cash Collateral included in Derivatives
Net Amount of Total Derivative Assets on Condensed Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:
 
 
 
 
Commodity derivative:
 
 
 
 
Oil and Gas - Crude Basis Swaps
$
75

$

$
(75
)
$

Oil and Gas - Crude Options
11


(11
)

Oil and Gas - Natural Gas Basis Swaps
148


(148
)

Utilities
1,897

(1,375
)

522

Total derivative assets subject to a master netting agreement or similar arrangement
2,131

(1,375
)
(234
)
522

 
 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
 
Commodity derivative:
 
 
 
 
Oil and Gas - Crude Basis Swaps
761



761

Oil and Gas - Crude Options
60



60

Oil and Gas - Natural Gas Basis Swaps
287



287

Utilities




Total derivative assets not subject to a master netting agreement or similar arrangement
1,108



1,108

 
 
 
 
 
Total derivative assets
$
3,239

$
(1,375
)
$
(234
)
$
1,630


Derivative Liabilities
Gross Amounts of Derivative Liabilities
Gross Amounts Offset on Condensed Consolidated Balance Sheets
Cash Collateral included in Derivatives
Net Amount of Total Derivative Liabilities on Condensed Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:
 
 
 
 
Commodity derivative:
 
 
 
 
Oil and Gas - Crude Basis Swaps
$
612

$

$
(612
)
$

Oil and Gas - Crude Options
204


(204
)

Oil and Gas - Natural Gas Basis Swaps
2,028


(2,028
)

Utilities
5,862

(1,375
)
(4,487
)

Interest Rate Swaps




Total derivative liabilities subject to a master netting agreement or similar arrangement
8,706

(1,375
)
(7,331
)

 
 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
 
Commodity derivative:
 
 
 
 
Oil and Gas - Crude Basis Swaps
58



58

Oil and Gas - Crude Options
192



192

Oil and Gas - Natural Gas Basis Swaps
1,188



1,188

Utilities




Interest Rate Swaps
108,871


(5,960
)
102,911

Total derivative liabilities not subject to a master netting agreement or similar arrangement
110,309


(5,960
)
104,349

 
 
 
 
 
Total derivative liabilities
$
119,015

$
(1,375
)
$
(13,291
)
$
104,349



28



Offsetting of derivative assets and derivative liabilities as of Dec. 31, 2012 (in thousands):
Derivative Assets
Gross Amounts of Derivative Assets
Gross Amounts Offset on Condensed Consolidated Balance Sheets
Cash Collateral included in Derivatives
Net Amount of Total Derivative Assets on Condensed Consolidated Balance Sheets
Subject to master netting agreement or similar arrangement:
 
 
 
 
Commodity derivative:
 
 
 
 
Oil and Gas - Crude Basis Swaps
$
76

$

$

$
76

Oil and Gas - Crude Options
93



93

Oil and Gas - Natural Gas Basis Swaps
172



172

Utilities
1,629

(1,586
)

43

Total derivative assets subject to a master netting agreement or similar arrangement
1,970

(1,586
)

384

 
 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
 
Commodity derivative:
 
 
 
 
Oil and Gas - Crude Basis Swaps
1,249



1,249

Oil and Gas - Crude Options
285



285

Oil and Gas - Natural Gas Basis Swaps
1,828



1,828

Utilities




Total derivative assets not subject to a master netting agreement or similar arrangement
3,362



3,362

 
 
 
 
 
Total derivative assets
$
5,332

$
(1,586
)
$

$
3,746


Derivative Liabilities
Gross Amounts of Derivative Liabilities
Gross Amounts Offset on Condensed Consolidated Balance Sheets
Cash Collateral included in Derivatives
Net Amount of Total Derivative Liabilities on Condensed Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement
 
 
 
 
Commodity derivative:
 
 
 
 
Oil and Gas - Crude Basis Swaps
$
449

$

$
(449
)
$

Oil and Gas - Crude Options
337


(337
)

Oil and Gas - Natural Gas Basis Swaps
620


(620
)

Utilities
10,162

(1,586
)
(8,576
)

Interest Rate Swaps




Total derivative liabilities subject to a master netting agreement or similar arrangement
11,568

(1,586
)
(9,982
)

 
 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
 
Commodity derivative:
 
 
 
 
Oil and Gas - Crude Basis Swaps
52



52

Oil and Gas - Crude Options
795



795

Oil and Gas - Natural Gas Basis Swaps
507



507

Utilities




Interest Rate Swaps
118,088


(5,960
)
112,128

Total derivative liabilities not subject to a master netting agreement or similar arrangement
119,442


(5,960
)
113,482

 
 
 
 
 
Total derivative liabilities
$
131,010

$
(1,586
)
$
(15,942
)
$
113,482



29



Offsetting of derivative assets and derivative liabilities as of March 31, 2012 (in thousands):
Derivative Assets
Gross Amounts of Derivative Assets
Gross Amounts Offset on Condensed Consolidated Balance Sheets
Cash Collateral included in Derivatives
Net Amount of Total Derivative Assets on Condensed Consolidated Balance Sheets
Subject to master netting agreements or similar arrangement:
 
 
 
 
Commodity derivative:
 
 
 
 
Oil and Gas - Crude Basis Swaps
$

$

$

$

Oil and Gas - Crude Options




Oil and Gas - Natural Gas Basis Swaps




Utilities
(8,409
)

17,651

9,242

Total derivative assets subject to a master netting agreement or similar arrangement
(8,409
)

17,651

9,242

 
 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
 
Commodity derivative:
 
 
 
 
Oil and Gas - Crude Basis Swaps
48



48

Oil and Gas - Crude Options
404



404

Oil and Gas - Natural Gas Basis Swaps
9,064



9,064

Utilities




Total derivative assets not subject to a master netting agreement or similar arrangement
9,516



9,516

 
 
 
 
 
Total derivative assets
$
1,107

$

$
17,651

$
18,758


Derivative Liabilities
Gross Amounts of Derivative Liabilities
Gross Amounts Offset on Condensed Consolidated Balance Sheets
Cash Collateral included in Derivatives
Net Amount of Total Derivative Liabilities on Condensed Consolidated Balance Sheets
Subject to a master netting agreement or similar arrangement:
 
 
 
 
Commodity derivative:
 
 
 
 
Oil and Gas - Crude Basis Swaps
$

$

$

$

Oil and Gas - Crude Options




Oil and Gas - Natural Gas Basis Swaps




Utilities
6,407



6,407

Interest Rate Swaps




Total derivative liabilities subject to a master netting agreement or similar arrangement
6,407



6,407

 
 
 
 
 
Not subject to a master netting agreement or similar arrangement:
 
 
 
 
Commodity derivative:
 
 
 
 
Oil and Gas - Crude Basis Swaps
2,641



2,641

Oil and Gas - Crude Options
1,347



1,347

Oil and Gas - Natural Gas Basis Swaps




Utilities




Interest Rate Swaps
109,163



109,163

Total derivative liabilities not subject to a master netting agreement or similar arrangement
113,151



113,151

 
 
 
 
 
Total derivative liabilities
$
119,558

$

$

$
119,558



30



Derivative assets and derivative liabilities and collateral held by counterparty as of March 31, 2013 (in thousands):

 
 
 
Gross Amounts Not Offset on Condensed Consolidated Balance Sheets
 
Contract Type
 
Net Amount of Total Derivative Assets
Cash Collateral Received
Net Amount with Counterparty
Asset:
 
 
 
 
Oil and Gas
Counterparty A
$

$

$

Oil and Gas
Counterparty B
1,108


1,108

Utilities
Counterparty A
522


522

 
 
$
1,630

$

$
1,630


 
 
 
Gross Amounts Not Offset on Condensed Consolidated Balance Sheets
 
Contract Type
 
Net Amount of Total Derivative Liabilities
Cash Collateral Paid
Net Amount with Counterparty
Liabilities
 
 
 
 
Oil and Gas
Counterparty A
$

$
(2,825
)
$
(2,825
)
Oil and Gas
Counterparty B
1,438


1,438

Utilities
Counterparty A

(3,295
)
(3,295
)
Interest Rate Swap
Counterparty D
4,266


4,266

Interest Rate Swap
Counterparty E
26,754


26,754

Interest Rate Swap
Counterparty F
11,841


11,841

Interest Rate Swap
Counterparty G
24,905


24,905

Interest Rate Swap
Counterparty H
14,625


14,625

Interest Rate Swap
Counterparty I
20,520


20,520

 
 
$
104,349

$
(6,120
)
$
98,229


Derivative assets and derivative liabilities and collateral held by counterparty as of Dec. 31, 2012 (in thousands):

 
 
 
Gross Amounts Not Offset on Condensed Consolidated Balance Sheets
 
Contract Type
 
Net Amount of Total Derivative Assets
Cash Collateral Received
Net Amount with Counterparty
Assets:
 
 
 
 
Oil and Gas
Counterparty A
$
341

$

$
341

Oil and Gas
Counterparty B
3,362


3,362

Utilities
Counterparty A
43


43

 
 
$
3,746

$

$
3,746



31



 
 
 
Gross Amounts Not Offset on Condensed Consolidated Balance Sheets
 
Contract Type
 
Net Amount of Total Derivative Liabilities
Cash Collateral Paid
Net Amount with Counterparty
Liabilities:
 
 
 
 
Oil and Gas
Counterparty A
$

$
(1,787
)
$
(1,787
)
Oil and Gas
Counterparty B
1,354


1,354

Utilities
Counterparty A

(4,354
)
(4,354
)
Interest Rate Swap
Counterparty D
4,588


4,588

Interest Rate Swap
Counterparty E
29,245


29,245

Interest Rate Swap
Counterparty F
12,721


12,721

Interest Rate Swap
Counterparty G
26,520


26,520

Interest Rate Swap
Counterparty H
16,809


16,809

Interest Rate Swap
Counterparty I
22,245


22,245

 
 
$
113,482

$
(6,141
)
$
107,341


Derivative assets and derivative liabilities and collateral held by counterparty as of March 31, 2012 (in thousands):

 
 
 
Gross Amounts Not Offset on Condensed Consolidated Balance Sheets
 
Contract Type
 
Net Amount of Total Derivative Assets
Cash Collateral Received
Net Amount with Counterparty
Assets:
 
 
 
 
Oil and Gas
Counterparty A
$

$

$

Oil and Gas
Counterparty B
9,516


9,516

Utilities
Counterparty A
9,242


9,242

 
 
$
18,758

$

$
18,758


 
 
 
Gross Amounts Not Offset on Condensed Consolidated Balance Sheets
 
Contract Type
 
Net Amount of Total Derivative Liabilities
Cash Collateral Paid
Net Amount with Counterparty
Liabilities:
 
 
 
 
Oil and Gas
Counterparty A
$

$

$

Oil and Gas
Counterparty B
3,988


3,988

Utilities
Counterparty A
6,407


6,407

Interest Rate Swap
Counterparty D
4,810


4,810

Interest Rate Swap
Counterparty E
27,137


27,137

Interest Rate Swap
Counterparty F
13,027


13,027

Interest Rate Swap
Counterparty G
24,617


24,617

Interest Rate Swap
Counterparty H
19,808


19,808

Interest Rate Swap
Counterparty I
19,764


19,764

 
 
$
119,558

$

$
119,558



32



A description of our derivative activities is included in Note 11. The following tables present the impact that derivatives had on our Condensed Consolidated Statements of Income.

Cash Flow Hedges

The impact of cash flow hedges on our Condensed Consolidated Statements of Income was as follows (in thousands):
Three Months Ended March 31, 2013
Derivatives in Cash Flow Hedging Relationships
 
Amount of
Gain/(Loss)
Recognized
in AOCI
Derivative
(Effective
Portion)
 
Location
of Gain/(Loss)
Reclassified
from AOCI
into Income
(Effective
Portion)
 
Amount of
Reclassified
Gain/(Loss)
from AOCI
into Income
(Effective
Portion)
 
Location of
Gain/(Loss)
Recognized
in Income
on Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps
 
$
(19
)
 
Interest expense
 
$
(1,796
)
 
 
 
$

Commodity derivatives
 
(2,759
)
 
Revenue
 
1,092

 
 
 

Total
 
$
(2,778
)
 
 
 
$
(704
)
 
 
 
$


Three Months Ended March 31, 2012
Derivatives in Cash Flow Hedging Relationships
 
Amount of
Gain/(Loss)
Recognized
in AOCI
Derivative
(Effective
Portion)
 
Location
of Gain/(Loss)
Reclassified
from AOCI
into Income
(Effective
Portion)
 
Amount of
Reclassified
Gain/(Loss)
from AOCI
into Income
(Effective
Portion)
 
Location of
Gain/(Loss)
Recognized
in Income
on Derivative
(Ineffective
Portion)
 
Amount of
Gain/(Loss)
Recognized in
Income on
Derivative
(Ineffective
Portion)
Interest rate swaps
 
$
(762
)
 
Interest expense
 
$
(1,822
)
 
 
 
$

Commodity derivatives
 
1,283

 
Revenue
 
3,009

 
 
 

Total
 
$
521

 
 
 
$
1,187

 
 
 
$

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derivatives Not Designated as Hedge Instruments

The impact of derivative instruments that have not been designated as hedge instruments on our Condensed Consolidated Statements of Income was as follows (in thousands):

 
 
 
 
Three Months Ended
 
 
 
 
March 31, 2013
Derivatives Not Designated
 as Hedging Instruments
 
Location of Gain/(Loss)
 on Derivatives
 Recognized in Income
 
Amount of Gain/(Loss)
on Derivatives
Recognized in Income
Interest rate swaps - unrealized
 
Unrealized gain (loss) on interest rate swaps, net
 
$
7,456

Interest rate swaps - realized
 
Interest expense
 
(3,427
)
 
 
 
 
$
4,029


 
 
 
 
Three Months Ended
 
 
 
 
March 31, 2012
Derivatives Not Designated
 as Hedging Instruments
 
Location of Gain/(Loss)
 on Derivatives
 Recognized in Income
 
Amount of Gain/(Loss)
on Derivatives
Recognized in Income
Interest rate swaps - unrealized
 
Unrealized gain (loss) on interest rate swaps, net
 
$
12,045

Interest rate swaps - realized
 
Interest expense
 
(3,205
)
 
 
 
 
$
8,840



33




(13)    FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments are as follows (in thousands) as of:
 
March 31, 2013
 
Dec. 31, 2012
 
March 31, 2012
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
 
Carrying
Amount
Fair Value
Cash and cash equivalents (a)
$
12,397

$
12,397

 
$
15,462

$
15,462

 
$
56,132

$
56,132

Restricted cash and equivalents (a)
$
6,846

$
6,846

 
$
7,916

$
7,916

 
$
8,960

$
8,960

Notes payable (a)
$
245,000

$
245,000

 
$
277,000

$
277,000

 
$
225,000

$
225,000

Long-term debt, including current maturities (b)
$
1,041,114

$
1,208,909

 
$
1,042,850

$
1,231,559

 
$
1,280,993

$
1,439,724

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


(14)    COMMITMENTS AND CONTINGENCIES

Commitments and Contingencies

There have been no significant changes to commitments and contingencies, other than those described below, from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2012 Annual Report on Form 10-K.

The following purchase power and power sales agreements were renewed during the first quarter of 2013:

Cheyenne Light renewed an agreement with Basin Electric whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through Sept. 30, 2014. This agreement is subject to FERC approval which is expected during the second quarter of 2013.

Cheyenne Light renewed an agreement with Basin Electric whereby Cheyenne Light provides 40 megawatts of capacity and energy through Sept. 30, 2014. This agreement is subject to FERC approval which is expected during the second quarter of 2013.

Other Commitments

Construction of Cheyenne Prairie, a 132 megawatt natural gas-fired electric generating facility, by Cheyenne Light and Black Hills Power is expected to cost approximately $222.0 million, exclusive of financing costs. Construction is expected to be completed by Sept. 30, 2014. As of March 31, 2013, committed contracts for equipment purchases and for construction were 28 percent and 13 percent complete, respectively.

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills. Our utility subsidiary, Black Hills Power, subsequently received written damage claims from the State of Wyoming and one landowner seeking recovery for alleged injury to timber, grass, fencing, fire suppression and rehabilitation costs of approximately $8.0 million. On April 16, 2013, thirty-four private landowners filed suit in United States District Court for the District of Wyoming, asserting similar claims, based upon allegations of negligence, common law nuisance and trespass. The suit seeks recovery of both actual and exemplary damages in an unspecified amount. Our investigation into the cause and origin of the fire is pending. We expect to deny and will vigorously defend all claims arising out of the lawsuit, pending the completion of our investigation. Given the uncertainty of litigation, however, a loss related to the fire and the litigation is reasonably possible. We cannot reasonably estimate the amount of a potential loss because our investigation is ongoing. Further claims may be presented by other parties. Although we cannot predict the outcome of our investigation or the viability of alleged claims, based on information currently available, management believes that any such claims, if determined adversely to us, will not have a material adverse effect on our financial condition or results of operation.

34




Sale of Enserco Energy Inc.

In December 2012, we agreed to arbitrate certain claims that we believe are properly characterized as purchase price adjustments related to the sale of Enserco, but objected to the arbitration of additional claims that we believe are not properly characterized as purchase price adjustments. After joint discussions of the parties with the arbitrator in January 2013, the arbitrator advised the parties that it would not arbitrate the claims to which we objected. On April 11, 2013, the buyer filed a petition in the Colorado District Court for the City and County of Denver, Colorado, seeking an order compelling arbitration on all of the disputed claims. We responded by requesting the court to deny the buyer’s petition. The filing of this petition does not alter our characterization or evaluation of the original claim.

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 March 31, 2013, 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 March 31, 2013:

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 March 31, 2013, the restricted net assets at our Utilities Group were approximately $205.9 million.

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

Guarantees

As of Dec. 31, 2012, the Company had provided a guarantee for up to $33.3 million of Colorado Electric’s performance and payment obligations relating to the purchase of wind turbines for the Colorado Electric wind power generation project. The guarantee expired March 29, 2013 upon fulfillment of all contractual obligations.


35



ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

We are an integrated energy company operating principally in the United States with two major business groups — Utilities and Non-regulated Energy. We report our business groups in the following financial segments:

Business Group
Financial Segment
 
 
Utilities
Electric Utilities
 
Gas Utilities
 
 
Non-regulated Energy
Power Generation
 
Coal Mining
 
Oil and Gas

Our Utilities Group consists of our Electric and Gas Utilities segments. Our Electric Utilities segment generates, transmits and distributes electricity to approximately 203,000 customers in South Dakota, Wyoming, Colorado and Montana; and also distributes natural gas to approximately 35,000 Cheyenne Light customers in Wyoming. Our Gas Utilities serve approximately 536,000 natural gas customers in Colorado, Iowa, Kansas and Nebraska. Our Non-regulated Energy Group consists of our Power Generation, Coal Mining and Oil and Gas segments. Our Power Generation segment produces electric power from our generating plants and sells the electric capacity and energy principally to our utilities under long-term contracts. Our Coal Mining segment produces coal at our coal mine near Gillette, Wyo. and sells the coal primarily to on-site, mine-mouth power generation facilities. Our Oil and Gas segment engages in exploration, development and production of crude oil and natural gas, primarily in the Rocky Mountain region.

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 prices. 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, 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 months ended March 31, 2013 and 2012, and our financial condition as of March 31, 2013, Dec. 31, 2012, and March 31, 2012 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.
See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 59.

The following business group and segment information does not include intercompany eliminations. Minor differences in amounts may result due to rounding. All amounts are presented on a pre-tax basis unless otherwise indicated. As a result of the sale of Enserco on Feb. 29, 2012, the reportable segment previously reported as Energy Marketing is classified as discontinued operations.


36



Results of Operations

Executive Summary, Significant Events and Overview

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012. Income from continuing operations for the three months ended March 31, 2013 was $43.2 million, or $0.97 per share, compared to Income from continuing operations of $35.3 million, or $0.80 per share, reported for the same period in 2012. The 2013 Income from continuing operations included a $4.8 million after-tax non-cash unrealized mark-to-market gain on certain interest rate swaps. The 2012 Income from continuing operations included a $7.8 million after-tax non-cash unrealized mark-to-market gain on the same interest rate swaps and an after-tax write-off of $1.0 million of deferred financing costs related to the previous Revolving Credit Facility.

Net income for the three months ended March 31, 2013 was $43.2 million, or $0.97 per share, compared to Net income of $29.8 million, or $0.68 per share, for the same period in 2012. Net income for the three months ended March 31, 2013 and 2012 include the same significant items discussed above.

 
Three Months Ended
March 31,
 
2013
2012
Variance
 
(in thousands)
Revenue
 
 
 
Utilities
$
362,442

$
339,691

$
22,751

Non-regulated Energy
49,287

56,261

(6,974
)
Intercompany eliminations
(31,058
)
(30,101
)
(957
)
 
$
380,671

$
365,851

$
14,820

 
 
 
 
Net income (loss)
 
 
 
Electric Utilities
$
12,356

$
8,746

$
3,610

Gas Utilities
18,483

15,207

3,276

Utilities
30,839

23,953

6,886

 
 
 
 
Power Generation
5,644

6,914

(1,270
)
Coal Mining
1,065

1,000

65

Oil and Gas
(53
)
13

(66
)
Non-regulated Energy
6,656

7,927

(1,271
)
 
 
 
 
Corporate activities and eliminations (a)(b)
5,702

3,391

2,311

 
 
 
 
Income (loss) from continuing operations
43,197

35,271

7,926

 
 
 
 
Income (loss) from discontinued operations, net of tax

(5,484
)
5,484

Net income (loss)
$
43,197

$
29,787

$
13,410

______________
(a)
Corporate activities include a $4.8 million and a $7.8 million net after-tax non-cash mark-to-market gain on interest rate swaps for the three months ended March 31, 2013 and 2012, respectively.
(b)
Certain indirect corporate costs and inter-segment interest expenses after-tax totaling $1.6 million for the three months ended March 31, 2012 were included in the Corporate activities in continuing operations and were not reclassified as discontinued operations.



37



Business Group highlights for 2013 include:

Utilities Group

Quarter-to-date utility results were favorably impacted by colder weather, particularly at the Gas Utilities. Heating degree days for the quarter were 30 percent higher compared to the same quarter in 2012. Heating degree days for the quarter were 6 percent higher than normal for 2013 compared to 19 percent lower than normal for 2012.

Construction and infrastructure work for Cheyenne Prairie, a natural gas-fired electric generating facility to serve Cheyenne Light and Black Hills Power customers began in April 2013. The 132 megawatt generation project is expected to cost approximately $222 million, with up to $15 million of construction financing costs, for a total of $237 million. Through March 31, 2013, $52.7 million was expended, and the project is on schedule to be placed into service in the fourth quarter of 2014.

On Jan. 17, 2013, the SDPUC approved a stipulation for interim rates effective April 1, 2013, subject to refund, for the use of a construction financing rider for the South Dakota portion of costs for Cheyenne Prairie in lieu of the traditional allowance for funds used during construction. Public hearings with the SDPUC are scheduled in the third quarter of 2013. The WPSC approved a similar construction financing rider for our Wyoming customers during 2012 and the Electric Utilities recorded additional gross margins of approximately $0.6 million for the three months ended March 31, 2013 relating to this rider.

On Dec. 17, 2012, Black Hills Power filed a request with the SDPUC seeking a $13.7 million increase in annual electric revenues. Public hearings with the SDPUC are scheduled in the fourth quarter of 2013. We expect to implement interim rates, subject to refund, in June 2013.

On April 30, 2013, Colorado Electric filed its electric resource plan with the CPUC, addressing its projected resource requirements through 2019. The resource plan identifies a 40 megawatt, simple-cycle, natural gas-fired turbine as the replacement capacity for the retirement of the coal-fired, 42 megawatt W.N. Clark power plant, consistent with the requirements of the Colorado Clean Air - Clean Jobs Act. A CPCN has been submitted to the CPUC requesting approval for the new generating capacity. If approved, this plant is expected to be constructed at the Pueblo Airport Generation Station and placed into service in the first quarter of 2017. The resource plan also recommends the retirement of Pueblo Units 5 and 6 as of Dec. 31, 2013. A CPCN has been submitted to the CPUC seeking approval to retire these plants, which were placed in service in the 1940s.

On April 23, 2013, Colorado Electric issued a request for proposals for up to 30 megawatts of wind energy delivered to its electric system in southern Colorado. Adding another 30 megawatts of wind generation will assist Colorado Electric towards meeting Colorado's renewable energy standard as mandated by state law, which requires each publicly owned utilities to deliver 30 percent of its energy as renewable energy by 2020. The request seeks to allow bidders to take advantage of the recent extension of the federal production tax credits for qualifying renewable technologies.

Non-regulated Energy Group

Oil and Gas reported a 27 percent reduction in total volumes sold, reflecting the 2012 sale of the Williston Basin oil and gas assets. Results benefited from a 15 percent increase in average hedge price received for crude oil during the first quarter of 2013 compared to the first quarter of 2012, partially offset by an 18 percent decrease in average hedge price received for natural gas.

Oil and Gas is drilling the first of two wells in the Mancos Shale formation in the Piceance Basin. The wells are part of a transaction through which we will earn up to approximately 20,000 net acres of additional Mancos Shale leaseholds in the Piceance Basin in exchange for drilling and completing the wells.
Corporate Activities

Consolidated interest expense decreased by approximately $6.2 million for the three months ended March 31, 2013 due primarily to the repayment of approximately $225 million of debt in 2012.

We recognized a non-cash unrealized mark-to-market gain related to certain interest rate swaps of $7.5 million and $12.0 million for the three months ended March 31, 2013 and 2012, respectively.

38





Utilities Group

We report two segments within the Utilities Group: Electric Utilities and Gas Utilities. The Electric Utilities segment includes the electric operations of Black Hills Power, Colorado Electric and the electric and natural gas operations of Cheyenne Light. The Gas Utilities segment includes the regulated natural gas utility operations of Black Hills Energy in Colorado, Iowa, Kansas and Nebraska.


Electric Utilities
 
Three Months Ended March 31,
 
2013
2012
Variance
 
(in thousands)
Revenue — electric
$
150,373

$
146,281

$
4,092

Revenue — gas
12,257

12,888

(631
)
Total revenue
162,630

159,169

3,461

 
 
 
 
Fuel, purchased power and cost of gas — electric
65,689

65,598

91

Purchased gas — gas
6,438

8,118

(1,680
)
Total fuel, purchased power and cost of gas
72,127

73,716

(1,589
)
 
 
 
 
Gross margin — electric
84,684

80,683

4,001

Gross margin — gas
5,819

4,770

1,049

Total gross margin
90,503

85,453

5,050

 
 
 
 
Operations and maintenance
38,835

39,230

(395
)
Depreciation and amortization
19,161

18,932

229

Total operating expenses
57,996

58,162

(166
)
 
 
 
 
Operating income
32,507

27,291

5,216

 
 
 
 
Interest expense, net
(14,397
)
(13,220
)
(1,177
)
Other income (expense), net
285

718

(433
)
Income tax benefit (expense)
(6,039
)
(6,043
)
4

Income (loss) from continuing operations
$
12,356

$
8,746

$
3,610



39



The following tables summarize revenue, quantities generated and purchased, quantities sold, degree days and power plant availability for our Electric Utilities:
 
Three Months Ended
March 31,
Revenue - Electric (in thousands)
2013
 
2012
Residential:
 
 
 
Black Hills Power
$
16,442

 
$
15,476

Cheyenne Light
9,330

 
8,470

Colorado Electric
24,121

 
22,616

Total Residential
49,893

 
46,562

 
 
 
 
Commercial:
 
 
 
Black Hills Power
17,484

 
16,808

Cheyenne Light
12,767

 
13,957

Colorado Electric
21,151

 
19,127

Total Commercial
51,402

 
49,892

 
 
 
 
Industrial:
 
 
 
Black Hills Power
6,010

 
6,020

Cheyenne Light
4,855

 
3,069

Colorado Electric
9,637

 
9,232

Total Industrial
20,502

 
18,321

 
 
 
 
Municipal:
 
 
 
Black Hills Power
714

 
698

Cheyenne Light
458

 
426

Colorado Electric
2,547

 
2,664

Total Municipal
3,719

 
3,788

 
 
 
 
Total Retail Revenue - Electric
125,516

 
118,563

 
 
 
 
Contract Wholesale:
 
 
 
Total Contract Wholesale - Black Hills Power
5,767

 
4,905

 
 
 
 
Off-system Wholesale:
 
 
 
Black Hills Power
6,250

 
11,273

Cheyenne Light
2,682

 
2,513

Colorado Electric
1,107

 
233

Total Off-system Wholesale
10,039

 
14,019

 
 
 
 
Other Revenue:
 
 
 
Black Hills Power
7,150

 
7,090

Cheyenne Light
566

 
612

Colorado Electric
1,335

 
1,092

Total Other Revenue
9,051

 
8,794

 
 
 
 
Total Revenue - Electric
$
150,373

 
$
146,281



40



 
Three Months Ended
March 31,
Quantities Generated and Purchased (in MWh)
2013
 
2012
Generated —
 
 
 
Coal-fired:
 
 
 
Black Hills Power (a)
427,015

 
499,792

Cheyenne Light
172,312

 
127,153

Colorado Electric (b)

 
57,307

Total Coal-fired
599,327

 
684,252

 
 
 
 
Gas, Oil and Wind:
 
 
 
Black Hills Power
3,120

 
363

Cheyenne Light

 

Colorado Electric (c)
42,227

 
1,632

Total Gas, Oil and Wind
45,347

 
1,995

 
 
 
 
Total Generated:
 
 
 
Black Hills Power
430,135

 
500,155

Cheyenne Light
172,312

 
127,153

Colorado Electric
42,227

 
58,939

Total Generated
644,674

 
686,247

 
 
 
 
Purchased —
 
 
 
Black Hills Power
388,199

 
514,534

Cheyenne Light
201,845

 
231,619

Colorado Electric
455,138

 
401,127

Total Purchased
1,045,182

 
1,147,280

 
 
 
 
Total Generated and Purchased:
 
 
 
Black Hills Power
818,334

 
1,014,689

Cheyenne Light
374,157

 
358,772

Colorado Electric
497,365

 
460,066

Total Generated and Purchased
1,689,856

 
1,833,527

_________
(a)
Decrease is primarily the result of the suspension of operations at Ben French as of Dec. 31, 2012.
(b)
Decrease is primarily a result of the suspension of operations at W.N. Clark as of Dec. 31, 2012.
(c)
Increase is primarily due to higher usage of our gas-fired generation at the Pueblo Airport Generating Facility as a result of the suspension of operations at W.N. Clark and a decrease in available economy energy, and energy from the Busch Ranch wind project which was placed into commercial operation in the fourth quarter of 2012.

41



 
Three Months Ended
March 31,
Quantity Sold (in MWh)
2013
 
2012
Residential:
 
 
 
Black Hills Power
160,970

 
150,428

Cheyenne Light
75,456

 
71,837

Colorado Electric
155,436

 
154,052

Total Residential
391,862

 
376,317

 
 
 
 
Commercial:
 
 
 
Black Hills Power
175,617

 
170,093

Cheyenne Light
129,429

 
149,939

Colorado Electric
170,705

 
165,391

Total Commercial
475,751

 
485,423

 
 
 
 
Industrial:
 
 
 
Black Hills Power
91,632

 
95,735

Cheyenne Light
69,952

 
44,774

Colorado Electric
78,549

 
81,242

Total Industrial
240,133

 
221,751

 
 
 
 
Municipal:
 
 
 
Black Hills Power
7,783

 
7,568

Cheyenne Light
2,595

 
2,582

Colorado Electric
18,046

 
25,169

Total Municipal
28,424

 
35,319

 
 
 
 
Total Retail Quantity Sold
1,136,170

 
1,118,810

 
 
 
 
Contract Wholesale:
 
 
 
Total Contract Wholesale - Black Hills Power
103,784

 
89,048

 
 
 
 
Off-system Wholesale:
 
 
 
Black Hills Power
238,447

 
458,230

Cheyenne Light
70,308

 
66,709

Colorado Electric
31,777

 
2,608

Total Off-system Wholesale
340,532

 
527,547

 
 
 
 
Total Quantity Sold:
 
 
 
Black Hills Power
778,233

 
971,102

Cheyenne Light
347,740

 
335,841

Colorado Electric
454,513

 
428,462

Total Quantity Sold
1,580,486

 
1,735,405

 
 
 
 
Losses and Company Use:
 
 
 
Black Hills Power
40,101

 
43,587

Cheyenne Light
26,417

 
22,930

Colorado Electric
42,852

 
31,605

Total Losses and Company Use
109,370

 
98,122

 
 
 
 
Total Quantity Sold
1,689,856

 
1,833,527



42



 
Three Months Ended
March 31,
Degree Days
2013
 
2012
Heating Degree Days:
Actual
 
Variance from
30-Year Average
 
Actual
 
Variance from
30-Year Average
 
 
 
 
 
 
 
 
Black Hills Power
3,210

 
%
 
2,711

 
(16
)%
Cheyenne Light
3,162

 
5
%
 
2,761

 
(8
)%
Colorado Electric
2,750

 
5
%
 
2,294

 
(13
)%
 
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Black Hills Power

 
%
 

 
 %
Cheyenne Light

 
%
 

 
 %
Colorado Electric

 
%
 

 
 %

 
 
 
 
 
 
 
 
Electric Utilities Power Plant Availability
Three Months Ended
March 31,
 
2013
2012
Coal-fired plants (a)
96.9
%
 
90.8
%
 
Other plants
98.6
%
 
95.0
%
 
Total availability
97.8
%
 
92.9
%
 
_________________________
(a)
2012 includes planned overhauls at Wygen II.

43




Cheyenne Light Natural Gas Distribution

Included in the Electric Utilities is Cheyenne Light’s natural gas distribution system. The following table summarizes certain operating information for these natural gas distribution operations:
 
Three Months Ended
March 31,
 
2013
 
2012
Revenue - Gas (in thousands):
 
 
 
Residential
$
7,532

 
$
7,630

Commercial
3,608

 
3,810

Industrial
898

 
1,237

Other Sales Revenue
219

 
211

Total Revenue - Gas
$
12,257

 
$
12,888

 
 
 
 
Gross Margin (in thousands):
 
 
 
Residential
$
3,960

 
$
3,226

Commercial
1,492

 
1,173

Industrial
148

 
164

Other Gross Margin
219

 
207

Total Gross Margin
$
5,819

 
$
4,770

 
 
 
 
Volumes Sold (Dth):
 
 
 
Residential
1,093,000

 
969,678

Commercial
625,937

 
580,940

Industrial
226,947

 
237,140

Total Volumes Sold
1,945,884

 
1,787,758



44



Results of Operations for the Electric Utilities for the Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012: Income from continuing operations for the Electric Utilities was $12.4 million for the three months ended March 31, 2013 compared to $8.7 million for the three months ended March 31, 2012 as a result of:

Gross margin increased primarily due to a $1.6 million increase related to electric rate adjustments, a $0.6 million increase related to gas rate adjustments, $1.3 million from stronger retail and wholesale demand, a $0.6 million increase related to the newly approved Wyoming construction financing rider, and $0.4 million from increased gas usage as a result of colder weather.

Operations and maintenance decreased primarily due to reduced costs resulting from plant suspensions, the timing of repairs and maintenance costs, partially offset by employee compensation and benefit costs compared to the same period in the prior year.

Depreciation and amortization was comparable to the same period in the prior year.

Interest expense, net increased primarily due to increase in corporate allocations related to debt costs and lower AFUDC as compared to the same period in the prior year.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The effective tax rate decreased due to a favorable benefit from research and development tax credits, including the retroactive effect of the full year 2012 estimated benefit.


Gas Utilities
 
Three Months Ended March 31,
 
2013
2012
Variance
 
(in thousands)
Natural gas — regulated
$
191,951

$
172,169

$
19,782

Other — non-regulated services
7,861

8,353

(492
)
Total revenue
199,812

180,522

19,290

 
 
 
 
Natural gas — regulated
120,380

108,116

12,264

Other — non-regulated services
3,717

3,869

(152
)
Total cost of sales
124,097

111,985

12,112

 
 
 
 
Gross margin
75,715

68,537

7,178

 
 
 
 
Operations and maintenance
33,226

31,299

1,927

Depreciation and amortization
6,503

6,157

346

Total operating expenses
39,729

37,456

2,273

 
 
 
 
Operating income (loss)
35,986

31,081

4,905

 
 
 
 
Interest expense, net
(6,277
)
(6,540
)
263

Other income (expense), net
12

11

1

Income tax benefit (expense)
(11,238
)
(9,345
)
(1,893
)
Income (loss) from continuing operations
$
18,483

$
15,207

$
3,276



45



The following tables include revenue, gross margin, volumes sold and degree days for our Gas Utilities:

Revenue (in thousands)
Three Months Ended
March 31,
 
2013
 
2012
Residential:
 
 
 
Colorado
$
19,794

 
$
22,018

Nebraska
48,852

 
40,924

Iowa
38,751

 
34,570

Kansas
25,765

 
21,421

Total Residential
133,162

 
118,933

 
 
 
 
Commercial:
 
 
 
Colorado
3,660

 
4,194

Nebraska
16,247

 
14,100

Iowa
17,775

 
15,773

Kansas
8,789

 
6,735

Total Commercial
46,471

 
40,802

 
 
 
 
Industrial:
 
 
 
Colorado
48

 
52

Nebraska
205

 
289

Iowa
745

 
745

Kansas
932

 
922

Total Industrial
1,930

 
2,008

 
 
 
 
Transportation:
 
 
 
Colorado
401

 
346

Nebraska
4,716

 
3,799

Iowa
1,539

 
1,250

Kansas
2,049

 
1,868

Total Transportation
8,705

 
7,263

 
 
 
 
Other Sales Revenue:
 
 
 
Colorado
(74
)
 
29

Nebraska
614

 
575

Iowa
112

 
123

Kansas
1,031

 
2,436

Total Other Sales Revenue
1,683

 
3,163

 
 
 
 
Total Regulated Revenue
191,951

 
172,169

 
 
 
 
Non-regulated Services
7,861

 
8,353

 
 
 
 
Total Revenue
$
199,812

 
$
180,522



46



Gross Margin (in thousands)
Three Months Ended
March 31,
 
2013
 
2012
Residential:
 
 
 
Colorado
$
6,238

 
$
5,686

Nebraska
18,311

 
15,591

Iowa
13,589

 
12,195

Kansas
10,204

 
9,120

Total Residential
48,342

 
42,592

 
 
 
 
Commercial:
 
 
 
Colorado
989

 
916

Nebraska
4,635

 
3,883

Iowa
4,452

 
3,797

Kansas
2,644

 
2,170

Total Commercial
12,720

 
10,766

 
 
 
 
Industrial:
 
 
 
Colorado
30

 
30

Nebraska
54

 
61

Iowa
82

 
71

Kansas
224

 
222

Total Industrial
390

 
384

 
 
 
 
Transportation:
 
 
 
Colorado
401

 
347

Nebraska
4,716

 
3,799

Iowa
1,539

 
1,250

Kansas
2,049

 
1,868

Total Transportation
8,705

 
7,264

 
 
 
 
Other Sales Margins:
 
 
 
Colorado
(74
)
 
29

Nebraska
614

 
575

Iowa
112

 
123

Kansas
761

 
2,321

Total Other Sales Margins
1,413

 
3,048

 
 
 
 
Total Regulated Gross Margin
71,570

 
64,054

 
 
 
 
Non-regulated Services
4,145

 
4,483

 
 
 
 
Total Gross Margin
$
75,715

 
$
68,537



47



Volumes Sold (in Dth)
Three Months Ended
March 31,
 
2013
 
2012
Residential:
 
 
 
Colorado
2,921,335

 
2,603,401

Nebraska
5,737,673

 
4,352,817

Iowa
5,290,366

 
4,151,466

Kansas
3,216,306

 
2,659,674

Total Residential
17,165,680

 
13,767,358

 
 
 
 
Commercial:
 
 
 
Colorado
576,276

 
526,794

Nebraska
2,198,798

 
1,780,631

Iowa
2,805,673

 
2,227,795

Kansas
1,277,134

 
993,005

Total Commercial
6,857,881

 
5,528,225

 
 
 
 
Industrial:
 
 
 
Colorado
9,737

 
10,552

Nebraska
30,680

 
40,901

Iowa
142,324

 
129,142

Kansas
188,821

 
188,897

Total Industrial
371,562

 
369,492

 
 
 
 
Total Volumes Sold
24,395,123

 
19,665,075

 
 
 
 
Transportation:
 
 
 
Colorado
412,709

 
361,873

Nebraska
8,682,315

 
8,140,894

Iowa
5,679,157

 
5,187,496

Kansas
4,052,018

 
4,359,921

Total Transportation
18,826,199

 
18,050,184

 
 
 
 
Other Volumes:
 
 
 
Colorado

 

Nebraska

 

Iowa

 

Kansas (a)
55,010

 
24,450

Total Other Volumes
55,010

 
24,450

 
 
 
 
Total Volumes and Transportation Sold
43,276,332

 
37,739,709

___________
(a)
Other volumes represent wholesale customers.


48



 
Three Months Ended
March 31,
 
2013
 
2012
Heating Degree Days:
Actual
 
Variance
From
 Normal
 
Actual
 
Variance
From
 Normal
Colorado
2,872

 
3%
 
2,350

 
(16)%
Nebraska
3,129

 
3%
 
2,400

 
(21)%
Iowa
3,743

 
11%
 
2,799

 
(20)%
Kansas (a)
2,550

 
3%
 
2,040

 
(18)%
Combined (b) 
3,306

 
6%
 
2,536

 
(20)%
 
 
 
 
 
 
 
 
_______________
(a)
Kansas Gas has an approved weather normalization mechanism within its rate structure, which minimizes weather impact on gross margins.
(b)
The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism.

Our Gas Utilities are highly seasonal, and sales volumes vary considerably with weather and seasonal heating and industrial loads. Over 70 percent of our Gas Utilities’ revenue and margins are expected in the first and fourth quarters of each year. Therefore, revenue for and certain expenses of these operations fluctuate significantly among quarters. Depending upon the state in which our Gas Utilities operate, the winter heating season begins around Nov. 1 and ends around March 31.

Results of Operations for the Gas Utilities for the Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012: Income from continuing operations for the Gas Utilities was $18.5 million for the three months ended March 31, 2013 compared to Income from continuing operations of $15.2 million for the three months ended March 31, 2012 as a result of:

Gross margin increased primarily due to colder weather than in the same period during the prior year. Heating degree days were 30 percent higher for the three months ended March 31, 2013 compared to the same period in the prior year and 6 percent higher than normal.

Operations and maintenance increased primarily due to an increase in employee compensation and benefit costs and uncollectible accounts receivable compared to the same period in the prior year.

Depreciation and amortization was comparable to the same period in the prior year.

Interest expense, net decreased primarily due to lower debt, partially offset by an increase in corporate allocations related to debt costs.

Other income (expense), net was comparable to the same period in the prior year.

Income tax benefit (expense): The effective tax rate was comparable to the same period in the prior year.


49



Regulatory Matters — Utilities Group

The following summarizes our recent state and federal rate case and initial surcharge orders (dollars in millions):
 
Type of Service
Date Requested
Revenue Amount Requested
Iowa Gas (a)
Gas
12/2012
$
0.9

Black Hills Power (b)
Electric
12/2012
$
13.7

Black Hills Power (c)
Electric
12/2012
$
9.2

________________
(a)
On March 15, 2013, the IUB approved the Capital Infrastructure Automatic Adjustment Mechanism filed by Iowa Gas in December 2012. Approval was obtained for recovery of our 2012 capital investments. The mechanism will be effective in April 2013 and will result in a revenue increase of approximately $0.2 million in 2013.

(b)
As described in our 2012 Annual Report on Form 10-K, in December 2012 Black Hills Power filed a rate case with the SDPUC. We expect to implement interim rates, subject to refund, on June 16, 2013. Public hearings with the SDPUC are scheduled to commence Oct. 8, 2013.

(c) On Jan. 17, 2013, the SDPUC approved a stipulation for interim rates effective April 1, 2013, subject to refund, for the use of a construction financing rider for the South Dakota portion of costs for the Cheyenne Prairie in lieu of the traditional allowance for funds used during construction. Public hearings with the SDPUC are scheduled to commence Sept. 16, 2013.
 

Non-regulated Energy Group

We report three segments within our Non-regulated Energy Group: Power Generation, Coal Mining and Oil and Gas.

Power Generation
 
Three Months Ended March 31,
 
2013
2012
Variance
 
(in thousands)
Revenue
$
20,360

$
19,627

$
733

 
 
 
 
Operations and maintenance
7,791

7,132

659

Depreciation and amortization
1,226

1,114

112

Total operating expense
9,017

8,246

771

 
 
 
 
Operating income
11,343

11,381

(38
)
 
 
 
 
Interest expense, net
(2,674
)
(4,743
)
2,069

Other (expense) income
1

5

(4
)
Income tax (expense) benefit
(3,026
)
271

(3,297
)
 
 
 
 
Income (loss) from continuing operations
$
5,644

$
6,914

$
(1,270
)

The following table provides certain operating statistics for our plants within the Power Generation segment:

 
Three Months Ended
March 31,
 
2013
 
2012
Contracted power plant fleet availability:
 
 
 
Coal-fired plant
100.0
%
 
100.0
%
Natural gas-fired plants
98.6
%
 
99.6
%
Total availability
98.9
%
 
99.7
%


50



Results of Operations for Power Generation for the Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012: Income from continuing operations for the Power Generation segment was $5.6 million for the three months ended March 31, 2013 compared to Income from continuing operations of $6.9 million for the same period in 2012 as a result of:

Revenue increased due to an increase in megawatt hours delivered at a higher price.

Operations and maintenance increased primarily due to increased repairs and maintenance costs and employee compensation and benefit costs.

Depreciation and amortization was comparable to the same period in the prior year. The generating facility located in Pueblo, Colo. is accounted for as a capital lease under GAAP; as such, depreciation expense for the facility is recorded at Colorado Electric for segment reporting purposes.

Interest expense, net decreased due to lower debt balances at lower interest rates partially offset by an increase in corporate allocations related to debt costs.

Other (expense) income, net was comparable to the same period in the prior year.

Income tax (expense) benefit: The effective tax rate increased compared to the same period in the prior year primarily due to a favorable state tax true-up in 2012.

Coal Mining
 
Three Months Ended March 31,
 
2013
2012
Variance
 
(in thousands)
Revenue
$
13,583

$
14,989

$
(1,406
)
 
 
 
 
Operations and maintenance
10,151

11,478

(1,327
)
Depreciation, depletion and amortization
2,865

3,696

(831
)
Total operating expenses
13,016

15,174

(2,158
)
 
 
 


Operating income (loss)
567

(185
)
752

 
 
 
 
Interest (expense) income, net
(131
)
755

(886
)
Other income
613

881

(268
)
Income tax benefit (expense)
16

(451
)
467

 
 
 
 
Income (loss) from continuing operations
$
1,065

$
1,000

$
65


The following table provides certain operating statistics for our Coal Mining segment (in thousands):

 
Three Months Ended March 31,
 
2013
 
2012
Tons of coal sold
1,053

 
1,103

Cubic yards of overburden moved
1,059

 
2,642



51



Results of Operations for Coal Mining for the Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012: Income from continuing operations for the Coal Mining segment was $1.1 million for the three months ended March 31, 2013 compared to Income from continuing operations of $1.0 million for the same period in 2012 as a result of:

Revenue decreased primarily due to lower average price per ton and lower tons sold as a result of customer power plant suspensions and outages. Approximately 50 percent of our coal production is sold under contracts that include price adjustments based on actual mining costs. Our mining costs have trended down due to lower operating costs, thereby decreasing our price per ton for these customers. Most of our remaining production is sold under contracts where the sales price escalates periodically based on published indices.

Operations and maintenance decreased primarily from mining in areas with lower overburden due to a revised mine plan, including decreased fuel costs and headcount reductions.

Depreciation, depletion and amortization decreased primarily due to lower depreciation of mine reclamation asset retirement costs.

Interest (expense) income, net reflects decreased interest income primarily due to a decrease in an inter-company notes receivable upon payment of a dividend to our parent.

Other income was comparable to the same period in the prior year.
 
Income tax benefit (expense): The effective tax rate decreased primarily due to the impact of percentage depletion and a net favorable benefit from research and development credits, including the retroactive effect of the full year 2012 estimated benefit.

Oil and Gas
 
Three Months Ended March 31,
 
2013
2012
Variance
 
(in thousands)
Revenue
$
15,344

$
21,645

$
(6,301
)
 
 
 
 
Operations and maintenance
10,255

10,834

(579
)
Depreciation, depletion and amortization
5,367

9,323

(3,956
)
Total operating expenses
15,622

20,157

(4,535
)
 
 
 
 
Operating income (loss)
(278
)
1,488

(1,766
)
 
 
 
 
Interest income (expense), net
79

(1,605
)
1,684

Other income (expense), net
(77
)
29

(106
)
Income tax benefit (expense)
223

101

122

 
 
 
 
Income (loss) from continuing operations
$
(53
)
$
13

$
(66
)


The following tables provide certain operating statistics for our Oil and Gas segment:

 
Three Months Ended
March 31,
 
2013
 
2012
Production:
 
 
 
Bbls of oil sold
96,803

 
145,477

Mcf of natural gas sold
1,732,950

 
2,388,475

Gallons of NGL sold
945,814

 
814,585

Mcf equivalent sales
2,448,884

 
3,377,706



52



 
Three Months Ended
March 31,
 
2013
 
2012
Average price received: (a)
 
 
 
Oil/Bbl
$
89.73

 
$
77.99

Gas/Mcf  
$
2.96

 
$
3.61

NGL/gallon
$
0.94

 
$
0.95

 
 
 
 
Depletion expense/Mcfe
$
1.78

 
$
2.47

____________
(a)
Net of hedge settlement gains and losses.

The following is a summary of certain average operating expenses per Mcfe:

 
Three Months Ended March 31, 2013
 
Three Months Ended March 31, 2012
Producing Basin
LOE
Gathering,
 Compression
 and Processing
Production Taxes
Total
 
LOE
Gathering,
 Compression
and Processing
Production Taxes
Total
San Juan
$
1.29

$
0.34

$
0.42

$
2.05

 
$
0.97

$
0.32

$
0.36

$
1.65

Piceance
0.65

0.65

0.33

1.63

 
(0.03
)
0.49

0.15

0.61

Powder River
1.26


1.24

2.50

 
1.38


1.31

2.69

Williston
0.83


1.07

1.90

 
0.71


1.25

1.96

All other properties
0.70


0.38

1.08

 
1.68


0.08

1.76

Total weighted average
$
1.08

$
0.23

$
0.65

$
1.96

 
$
0.89

$
0.21

$
0.60

$
1.70

 
 
 
 
 
 
 
 
 
 
  
Results of Operations for Oil and Gas for the Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012: Loss from continuing operations for the Oil and Gas segment was $0.1 million for the three months ended March 31, 2013 compared to Income from continuing operations of $0.0 million for the same period in 2012 as a result of:

Revenue decreased primarily due to a 27 percent decrease in volumes sold as a result of our Williston Basin asset sale in 2012, a natural production decline in our Mancos formation wells and an 18 percent decrease in the average price received for natural gas sold, partially offset by a 15 percent increase in the average price received for crude oil sold.

Operations and maintenance decreased primarily due to lower non-operated costs and lower production and ad valorem taxes on lower revenues.

Depreciation, depletion and amortization decreased primarily due to a lower depletion rate per Mcfe and lower volumes. The decreased depletion rate is primarily driven by the sale of our Williston Basin assets in 2012.

Interest income (expense), net reflects lower interest expense primarily due to decreased debt as a result of proceeds from the 2012 sale of the Williston Basin assets.

Other income (expense), net was comparable to the same period in the prior year.

Income tax (expense) benefit: Each period presented reflects a tax benefit that was favorably impacted by the tax effect of essentially the same amount of estimated percentage depletion deduction.



53



Corporate Activity

Results of Operations for Corporate activities for the Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012: Income from continuing operations for Corporate was $5.7 million for the three months ended March 31, 2013 compared to Income from continuing operations of $3.4 million for the three months ended March 31, 2012. The variance from the prior year was primarily due to market interest rate changes impacting unrealized, non-cash mark-to-market gains on certain interest rate swaps; the allocation of debt related costs included in Corporate activities for the three months ended March 31, 2012 now allocated to our segments for the three months ended March 31, 2013 in order to better align the capital structure of our operating segments; and costs originally allocated to our Energy Marketing segment, which could not be reclassified to discontinued operations in accordance with GAAP, which were included in Corporate activities for the three months ended March 31, 2012.


Discontinued Operations

Results of Operations for Discontinued Operations for the Three Months Ended March 31, 2013, Compared to Three Months Ended March 31, 2012:

On Feb. 29, 2012, we sold the outstanding stock of Enserco, our Energy Marketing segment. Loss from discontinued operations, net of tax, for the three months ended March 31, 2012 was $5.5 million relating to additional operating costs to discontinue the operations, including an after-tax loss on sale of $1.6 million including transaction related costs, net of tax benefit, of $2.2 million.


Critical Accounting Policies

There have been no material changes in our critical accounting policies from those reported in our 2012 Annual Report on Form 10-K filed with the SEC. For more information on our critical accounting policies, see Part II, Item 7 of our 2012 Annual Report on Form 10-K.


Liquidity and Capital Resources

OVERVIEW

BHC and its subsidiaries require cash to support and grow our business. Our predominant source of cash is supplied by our operations and supplemented with corporate borrowings. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations and redemption of outstanding debt and equity securities when required or financially appropriate.

The most significant items impacting cash are our capital expenditures, the purchase of natural gas for our Gas Utilities and our Power Generation segment, and the payment of dividends to our shareholders. We could experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption and during periods of high natural gas prices.

We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.

Significant Factors Affecting Liquidity

Although we believe we have sufficient resources to fund our cash requirements, there are many factors with the potential to influence our cash flow position, including seasonality, commodity prices, significant capital projects, requirements imposed by state and federal agencies, and economic market conditions. We have implemented risk mitigation programs, where possible, to stabilize cash flow; however, the potential for unforeseen events affecting cash needs will continue to exist.

All amounts are presented on a pre-tax basis unless otherwise indicated.


54



Cash Flow Activities

The following table summarizes our cash flows for the three months ended March 31, 2013 and 2012 (in thousands):

Cash provided by (used in):
2013
2012
Increase (Decrease)
Operating activities
$
109,232

$
96,065

$
13,167

Investing activities
$
(62,909
)
$
41,466

$
(104,375
)
Financing activities
$
(49,388
)
$
(140,167
)
$
90,779


Year-to-Date 2013 Compared to Year-to-Date 2012

Operating Activities

Net cash provided by operating activities was $13.2 million higher for the three months ended March 31, 2013 than for the same period in 2012 primarily attributable to:

Cash earnings (net income plus non-cash adjustments) were $15.4 million higher for the three months ended March 31, 2013 than for the same period in the prior year.

Net inflows from operating assets and liabilities were $5.6 million for the three months ended March 31, 2013, a decrease of $0.5 million from the same period in the prior year. Changes are normal working capital changes influenced by variable weather, declines in natural gas prices for the Utilities Group, expiration of the PPA with PSCo, and receipt of $8.4 million from a government grant relating to the Busch Ranch wind project.

No cash contributions to the defined benefit pension plan were made in the first quarter of 2013 compared to $25.0 million in 2012.

A $21.2 million decrease in net cash inflows from discontinued operations in 2013 compared to 2012.

Investing Activities

Net cash used by investing activities was $62.9 million for the three months ended March 31, 2013 compared to net cash provided by investing activities of $41.5 million for the same period in 2012 for a variance of $104.4 million.

The variance was driven by cash proceeds received from the 2012 sale of Enserco of $108.8 million.

Financing Activities

Net cash used in financing activities for the three months ended March 31, 2013 was $49.4 million compared to net cash used in financing activities for the same period in 2012 of $140.2 million for a variance of $90.8 million.

The variance was primarily driven by the proceeds from the sale of Enserco which was used to pay down short-term borrowings on the Revolving Credit Facility of approximately $110 million in 2012.


Dividends

Dividends paid on our common stock totaled $16.9 million for the three months ended March 31, 2013, or $0.38 per share. On April 22, 2013, our board of directors declared a quarterly dividend of $0.38 per share payable June 1, 2013, which is equivalent to an annual dividend rate of $1.52 per share. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility and our future business prospects.



55



Debt

Financing Transactions and Short-Term Liquidity

Our principal sources to meet day-to-day operating cash requirements are cash from operations and our corporate Revolving Credit Facility.

Revolving Credit Facility

We have a $500 million revolving corporate credit facility which matures on Feb. 1, 2017 that has an accordion feature which allows us, with the consent of the administrative agent and issuing agents, to increase the capacity of the facility to $750 million. Borrowings are available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings under the agreement are determined based upon our credit ratings. At our current credit rating of BBB-, the margins for base rate borrowings, Eurodollar borrowings and letters of credit are 0.50 percent, 1.50 percent and 1.50 percent, respectively. A commitment fee is charged on the unused amount of the Revolving Credit Facility which is 0.25 percent based on current credit ratings.

Our Revolving Credit Facility at March 31, 2013 had the following borrowings, outstanding letters of credit and available capacity (in millions):
 
 
Current
Borrowings at
Letters of Credit at
Available Capacity at
Credit Facility
Expiration
Capacity
March 31, 2013
March 31, 2013
March 31, 2013
Revolving Credit Facility
Feb. 1, 2017
$
500.0

$
95.0

$
36.5

$
368.5


The Revolving Credit Facility contains customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions, and maintaining certain minimum net worth amounts and recourse leverage ratio. Under the Revolving Credit Facility, our recourse leverage ratio is the ratio of our recourse debt, letters of credit and guarantees issued over our total capital which includes the balance in the numerator plus our net worth. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with these covenants as of March 31, 2013.

The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.

Future Financing Plans

During the next three years, BHC plans to consider completion of the following financing activities to take advantage of the low interest rate environment:

Extend our $150 million and $100 million term loans;
Analyze early refinancing of our $250 million, 9 percent senior unsecured bonds that mature in May 2014; and
Review long-term financing options for the estimated $222 million Cheyenne Prairie capital project.


56



Hedges and Derivatives

Interest Rate Swaps

We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations.

We have interest rate swaps with a notional amount of $250 million that are not designated as hedge instruments. Accordingly, mark-to-market changes in value on these swaps are recorded within the Condensed Consolidated Statements of Income. For the three months ended March 31, 2013, we recorded $7.5 million pre-tax unrealized non-cash mark-to-market gain on the swaps. The mark-to-market value on these swaps was a liability of $80.7 million at March 31, 2013. Subsequent mark-to-market adjustments could have a significant impact on our results of operations. A one basis point move in the interest rate curves divided by the term of the swaps would have a pre-tax impact of approximately $0.3 million. These swaps are for terms of 6 years and 16 years and have early termination dates ranging from Dec. 15, 2013 to Dec. 31, 2013. We anticipate extending these agreements upon their early termination dates and have continued to maintain these swaps in anticipation of our upcoming financing needs. Alternatively, we may choose to cash settle these swaps at fair value prior to the early termination dates, or unless these dates are extended we will cash settle these swaps for an amount equal to their fair values on the early termination dates.

In addition, we have $150 million notional amount floating-to-fixed interest rate swaps with a maximum remaining term of 3.75 years. These swaps have been designated as cash flow hedges, and accordingly their mark-to-market adjustments are recorded in Accumulated other comprehensive income (loss) on the accompanying Condensed Consolidated Balance Sheets. The mark-to-market value of these swaps was a liability of $22.2 million at March 31, 2013.

Dividend Restrictions

As a utility holding company which owns several regulated utilities, we are subject to various regulations that could influence our liquidity. For example, the issuance of debt by our utility subsidiaries (including the ability of Black Hills Utility Holdings to issue debt) and the use of our utility assets as collateral generally requires the prior approval of the state regulators in the state in which the utility assets are located. As a result of our holding company structure, our right as a common shareholder to receive assets of any of our direct or indirect subsidiaries upon a subsidiary’s liquidation or reorganization is junior to the claims against the assets of such subsidiaries by their creditors. Therefore, our holding company debt obligations are effectively subordinated to all existing and future claims of the creditors of our subsidiaries, including trade creditors, debt holders, secured creditors, taxing authorities, and guarantee holders.
Our credit facilities and other debt obligations contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be deemed to have occurred if we did not meet certain financial covenants. The most restrictive financial covenants of our Revolving Credit Facility include the following: a recourse leverage ratio not to exceed 0.65 to 1.00 and a minimum consolidated net worth of $625 million plus 50 percent of aggregate consolidated net income since Jan. 1, 2005. As of March 31, 2013, we were in compliance with these covenants.

Covenants within Cheyenne Light’s financing agreements require Cheyenne Light to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. Our utilities in Colorado, Iowa, Kansas and Nebraska have regulatory agreements in which they cannot pay dividends if they have issued debt to third parties and the payment of a dividend would reduce their equity ratio to below 40 percent of their total capitalization; and neither Black Hills Utility Holdings nor its utility subsidiaries can extend credit to the Company except in the ordinary course of business and upon reasonable terms consistent with market terms. Additionally, our utility subsidiaries may generally be limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act. As of March 31, 2013, the restricted net assets at our Electric Utilities and Gas Utilities were approximately $205.9 million.

As required by a covenant of the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings, the parent of Black Hills Electric Generation which is the parent of Black Hills Wyoming, has restricted shareholders’ equity of at least $100.0 million. In addition, Black Hills Wyoming holds $6.8 million of restricted cash associated with the project financing requirements.

There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2012 Annual Report on Form 10-K filed with the SEC.


57



Credit Ratings

Financing for operational needs and capital expenditure requirements not satisfied by operating cash flows depends upon the cost and availability of external funds through both short and long-term financing. The inability to raise capital on favorable terms could negatively affect our ability to maintain or expand our businesses. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the company’s credit ratings, cash flows from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and credit ratings of the company, management believes that we will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. Credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.

The following table represents the credit ratings, outlook and risk profile of Black Hills Corporation’s Senior Unsecured Debt at March 31, 2013:
Rating Agency
Rating
Outlook
S&P
BBB-
Positive
Moody’s
Baa3
Positive
Fitch
BBB-
Stable

The following table represents the credit ratings of Black Hills Power’s First Mortgage Bonds at March 31, 2013:

Rating Agency
Rating
S&P
BBB+
Moody’s
A3
Fitch
A-


Capital Requirements

Actual and forecasted capital requirements are as follows (in thousands):
 
Expenditures for the
 
Total
 
Total
 
Total
 
Three Months Ended March 31, 2013
 
2013 Planned
Expenditures
 
2014 Planned
Expenditures
 
2015 Planned
Expenditures
Utilities:
 
 
 
 
 
 
 
Electric Utilities
$
43,460

 
$
284,200

 
$
230,500

 
$
127,600

Gas Utilities
8,680

 
59,800

 
58,000

 
43,000

Non-regulated Energy:
 
 
 
 
 
 
 
Power Generation
705

 
3,200

 
4,800

 
2,400

Coal Mining
2,166

 
7,100

 
6,000

 
5,100

Oil and Gas
4,298

 
98,300

 
84,300

 
109,100

Corporate
856

 
7,500

 
6,500

 
5,700

 
$
60,165

 
$
460,100

 
$
390,100

 
$
292,900


We continue to evaluate potential future acquisitions and other growth opportunities which are dependent upon the availability of economic opportunities; as a result, capital expenditures may vary significantly from the estimates identified above.



58



Contractual Obligations

Except as noted below, there have been no significant changes in the contractual obligations from those previously disclosed in Note 19 of our Notes to the Consolidated Financial Statements in our 2012 Annual Report on Form 10-K.

Purchase Power and Power Sales Agreements

The following purchase power and power sales agreements were renewed during first quarter of 2013:

Cheyenne Light renewed an agreement with Basin Electric whereby Cheyenne Light will receive 40 megawatts of capacity and energy from Basin Electric through Sept. 30, 2014. This agreement is subject to FERC approval which is expected during the second quarter of 2013.

Cheyenne Light renewed an agreement with Basin Electric whereby Cheyenne Light provides 40 megawatts of capacity and energy through Sept. 30, 2014. This agreement is subject to FERC approval which is expected during the second quarter of 2013.

Construction Commitments

Construction of Cheyenne Prairie, a 132 megawatt natural gas-fired electric generating facility, by Cheyenne Light and Black Hills Power is expected to cost approximately $222 million, with up to $15 million of construction financing costs, for a total of $237 million. Construction is expected to be completed by Sept. 30, 2014. As of March 31, 2013, contracts for equipment purchases and for construction were 28 percent and 13 percent committed, respectively.

Sale of Enserco Energy Inc.

In December 2012, we agreed to arbitrate certain claims that we believe are properly characterized as purchase price adjustments related to the sale of Enserco, but objected to the arbitration of additional claims that we believe are not properly characterized as purchase price adjustments. After joint discussions of the parties with the arbitrator in January 2013, the arbitrator advised the parties that it would not arbitrate the claims to which we objected. On April 11, 2013, the buyer filed a petition in the Colorado District Court for the City and County of Denver, Colorado, seeking an order compelling arbitration on all of the disputed claims. We responded by requesting the court to deny the buyer’s petition. The filing of this petition does not alter our characterization or evaluation of the original claim.


Guarantees

Except as noted below, there have been no significant changes to guarantees from those previously disclosed in Note 20 of our Notes to the Consolidated Financial Statements in our 2012 Annual Report on Form 10-K.

As of Dec. 31, 2012, the Company had provided a guarantee for up to $33.3 million of Colorado Electric’s performance and payment obligations relating to the purchase of wind turbines for the Colorado Electric wind power generation project. The guarantee expired March 29, 2013 upon fulfillment of all contractual obligations.


New Accounting Pronouncements

Other than the pronouncements reported in our 2012 Annual Report on Form 10-K filed with the SEC and those discussed in Note 2 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that are expected to have a material effect on our financial statements.



59



FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 2 - Management’s Discussion & Analysis of Financial Condition and Results of Operations.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in our 2012 Annual Report on Form 10-K including statements contained within Item 1A - Risk Factors of our 2012 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q and other reports that we file with the SEC from time to time.


ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


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 commission approved hedging programs utilizing natural gas futures, options and basis swaps to reduce our customers’ underlying exposure to these fluctuations. The fair value of our Utilities Group’s derivative contracts is summarized below (in thousands) as of:
 
March 31, 2013
 
Dec. 31, 2012
 
March 31, 2012
Net derivative (liabilities) assets
$
(3,965
)
 
$
(8,533
)
 
$
(14,816
)
Cash collateral
7,782

 
12,930

 
17,651

 
$
3,817

 
$
4,397

 
$
2,835




60



Oil and Gas Activities

We have entered into agreements to hedge a portion of our estimated 2013, 2014 and 2015 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place at March 31, 2013 were as follows:

Natural Gas

 
For the Three Months Ended
 
March 31,
June 30,
Sept. 30,
Dec. 31,
Total Year
2013
 
 
 
 
 
Swaps - MMBtu

1,233,000

1,246,000

1,154,000

3,633,000

Weighted Average Price per MMBtu
$

$
3.55

$
3.33

$
3.50

$
3.46

 
 
 
 
 
 
2014
 
 
 
 
 
Swaps - MMBtu
1,040,000

1,495,000

1,735,000

1,735,000

6,005,000

Weighted Average Price per MMBtu
$
3.74

$
3.72

$
3.98

$
3.99

$
3.88

 
 
 
 
 
 
2015
 
 
 
 
 
Swaps - MMBtu
630,000

365,000



995,000

Weighted Average Price per MMBtu
$
4.27

$
4.00

$

$

$
4.17



61



Crude Oil

 
For the Three Months Ended
 
March 31,
June 30,
Sept. 30,
Dec. 31,
Total Year
2013
 
 
 
 
 
Swaps - Bbls

21,000

15,000

15,000

51,000

Weighted Average Price per Bbl
$

$
108.96

$
110.20

$
101.75

$
107.20

 
 
 
 
 
 
Puts - Bbls

36,000

39,000

36,000

111,000

Weighted Average Price per Bbl
$

$
78.96

$
79.81

$
80.63

$
79.80

 
 
 
 
 
 
Calls - Bbls

36,000

39,000

36,000

111,000

Weighted Average Price per Bbl
$

$
97.17

$
97.08

$
97.25

$
97.16

 
 
 
 
 
 
2014
 
 
 
 
 
Swaps - Bbls
51,000

60,000

57,000

45,000

213,000

Weighted Average Price per Bbl
$
94.50

$
90.65

$
90.55

$
90.75

$
91.57

 
 
 
 
 
 
Puts - Bbls





Weighted Average Price per Bbl
$

$

$

$

$

 
 
 
 
 
 
Calls - Bbls





Weighted Average Price per Bbl
$

$

$

$

$

 
 
 
 
 
 
2015
 
 
 
 
 
Swaps - Bbls
36,000




36,000

Weighted Average Price per Bbl
$
90.27

$

$

$

$
90.27




62



Financing Activities

We engage in activities to manage risks associated with changes in interest rates. 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. Further details of the swap agreements are set forth in Note 3 of our 2012 Annual Report on Form 10-K and in Note 11 of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

Our interest rate swaps and related balances were as follows (dollars in thousands) as of:
 
March 31, 2013
 
Dec. 31, 2012
 
March 31, 2012
 
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
3.75

 
0.75

 
4.00

 
1.00

 
4.75

 
1.75

Derivative liabilities, current
$
6,982

 
$
80,692

 
$
7,039

 
$
88,148

 
$
6,777

 
$
66,708

Derivative liabilities, non-current
$
15,237

 
$

 
$
16,941

 
$

 
$
18,441

 
$
17,237

Pre-tax accumulated other comprehensive income (loss)
$
(22,219
)
 
$

 
$
(23,980
)
 
$

 
$
(25,218
)
 
$

Pre-tax gain (loss)
$

 
$
7,456

 
$

 
$
1,882

 
$

 
$
12,045

Cash collateral receivable (payable) included in derivatives
$

 
$
5,960

 
$

 
$
5,960

 
$

 
$

__________
*
Maximum terms in years for our de-designated interest rate swaps 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. When extended annually, de-designated swaps totaling $100.0 million terminate in 6 years and de-designated swaps totaling $150.0 million terminate in 16 years.

Based on March 31, 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.

ITEM 4.    CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of March 31, 2013. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

During the quarter ended March 31, 2013, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.


63



BLACK HILLS CORPORATION

Part II — Other Information

ITEM 1.
Legal Proceedings

For information regarding legal proceedings, see Note 19 in Item 8 of our 2012 Annual Report on Form 10-K and Note 14 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 14 is incorporated by reference into this item.

ITEM 1A.
Risk Factors

There are no material changes to the Risk Factors previously disclosed in Item 1A of Part I in our Annual Report on Form 10-K for the year ended Dec. 31, 2012.

ITEM 2.
Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

Period
 
Total
Number
of
Shares
Purchased(1)
 
Average
Price Paid
per Share
 
Total Number
of Shares
Purchased as
Part of Publicly
Announced
Plans for Programs
 
Maximum Number (or
Approximate Dollar
Value) of Shares
That May Yet Be
Purchased Under
the Plans or Programs
Jan. 1, 2013 -
 
 
 
 
 
 
 
 
Jan. 31, 2013
 
3,051

 
$
36.34

 

 

 
 
 
 
 
 
 
 
 
Feb. 1, 2013 -
 
 
 
 
 
 
 
 
Feb. 28, 2013
 
33,631

 
$
40.90

 

 

 
 
 
 
 
 
 
 
 
March 1, 2013 -
 
 
 
 
 
 
 
 
March 31, 2013
 
2,636

 
$
42.25

 

 

 
 
 
 
 
 
 
 
 
Total
 
39,318

 
$
40.63

 

 

____________
(1)
Shares were acquired from certain officers and key employees under the share withholding provisions of the Omnibus Incentive Plan for the payment of taxes associated with the vesting of shares of restricted stock.


ITEM 4.
Mine Safety Disclosures

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included in Exhibit 95 of this Quarterly Report on Form 10-Q.

ITEM 5.
Other Information

None.

64



ITEM 6.
Exhibits

Exhibit Number
Description
 
 
Exhibit 2.1*
Stock Purchase Agreement by and between Twin Eagle Resource Management, LLC and Black Hills Non-Regulated Holdings LLC for the purchase of capital stock of Enserco Energy Inc., dated January 18, 2012 (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2012).
 
 
Exhibit 2.2*
Purchase and Sale Agreement, dated as of August 23, 2012, by and among Black Hills Exploration and Production, Inc. and other sellers and QEP Energy Company, as Purchaser (excluding exhibits and certain schedules, which the Registrant agrees to furnish supplementally to the Securities and Exchange Commission upon request) (filed as Exhibit 2 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2012).
 
 
Exhibit 3.1*
Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 10-K for 2004).
 
 
Exhibit 3.2*
Amended and Restated Bylaws of the Registrant dated January 28, 2010 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 3, 2010).
 
 
Exhibit 4.1*
Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009). Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant’s Form 8-K filed on July 15, 2010).
 
 
Exhibit 4.2*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S‑3 (No. 333‑150669)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
 
 
Exhibit 4.3*
Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).
 
 
Exhibit 31.1
Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
 
 
Exhibit 31.2
Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
 
 
Exhibit 32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
 
 
Exhibit 32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
 
 
Exhibit 95
Mine Safety and Health Administration Safety Data
 
 
Exhibit 101
Financial Statements for XBRL Format
________________________
*
Previously filed as part of the filing indicated and incorporated by reference herein.


65



SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BLACK HILLS CORPORATION
 
 
/s/ David R. Emery
 
 
David R. Emery, Chairman, President and
 
 
  Chief Executive Officer
 
 
 
 
 
/s/ Anthony S. Cleberg
 
 
Anthony S. Cleberg, Executive Vice President and
 
 
  Chief Financial Officer
 
 
 
Dated:
May 3, 2013
 


66



INDEX TO EXHIBITS


Exhibit Number
Description
Exhibit 2.1*
Stock Purchase Agreement by and between Twin Eagle Resource Management, LLC and Black Hills Non-Regulated Holdings LLC for the purchase of capital stock of Enserco Energy Inc., dated January 18, 2012 (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2012).
 
 
Exhibit 2.2*
Purchase and Sale Agreement, dated as of August 23, 2012, by and among Black Hills Exploration and Production, Inc. and other sellers and QEP Energy Company, as Purchaser (excluding exhibits and certain schedules, which the Registrant agrees to furnish supplementally to the Securities and Exchange Commission upon request) (filed as Exhibit 2 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2012).
 
 
Exhibit 3.1*
Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 10-K for 2004).
 
 
Exhibit 3.2*
Amended and Restated Bylaws of the Registrant dated January 28, 2010 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 3, 2010).
 
 
Exhibit 4.1*
Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009). Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on July 15, 2010).
 
 
Exhibit 4.2*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S‑3 (No. 333‑150669)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
 
 
Exhibit 4.3*
Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000).
 
 
Exhibit 31.1
Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
 
 
Exhibit 31.2
Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
 
 
Exhibit 32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
 
 
Exhibit 32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
 
 
Exhibit 95
Mine Safety and Health Administration Safety Data
 
 
Exhibit 101
Financial Statements for XBRL Format
__________________________
*
Previously filed as part of the filing indicated and incorporated by reference herein.

67