BKH 063011 10Q


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-Q

x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 
EXCHANGE ACT OF 1934
 
For the quarterly period ended June 30, 2011.
OR
 
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
 
EXCHANGE ACT OF 1934
 
For the transition period from __________ to __________.
 
 
 
Commission File Number 001-31303

Black Hills Corporation
Incorporated in South Dakota
IRS Identification Number 46-0458824
625 Ninth Street
Rapid City, South Dakota 57701
 
 
Registrant's telephone number (605) 721-1700
 
 
Former name, former address, and former fiscal year if changed since last report
NONE

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
 
Yes x
 
No o
 

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).
 
Yes x
 
No o
 

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).
 
Large accelerated filer x
 
Accelerated filer o
 
 
Non-accelerated filer o
 
Smaller reporting company o
 

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
 
Yes o
 
No x
 

Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date.
Class
Outstanding at July 29, 2011
 
 
Common stock, $1.00 par value
39,441,037 shares





TABLE OF CONTENTS
 
 
 
Page
 
Glossary of Terms and Abbreviations and Accounting Standards
 
 
 
 
 
PART I.
FINANCIAL INFORMATION
 
 
 
 
 
Item 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income - unaudited
 
 
 
   Three and Six Months Ended June 30, 2011 and 2010
 
 
 
 
 
 
Condensed Consolidated Balance Sheets - unaudited
 
 
 
   June 30, 2011, December 31, 2010 and June 30, 2010
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows - unaudited
 
 
 
   Six Months Ended June 30, 2011 and 2010
 
 
 
 
 
 
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 5.
Other Information
 
 
 
 
 
Item 6.
Exhibits
 
 
 
 
 
 
Signatures
 
 
 
 
 
 
Exhibit Index
 



2



GLOSSARY OF TERMS AND ABBREVIATIONS
AND ACCOUNTING STANDARDS

The following terms and abbreviations and accounting standards 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)
ASC
Accounting Standards Codification
ASC 220
ASC 220, "Comprehensive Income"
ASC 820
ASC 820, "Fair Value Measurements and Disclosures"
ASU
Accounting Standards Update
Bbl
Barrel
Bcf
Billion cubic feet
Bcfe
Billion cubic feet equivalent
BHC
Black Hills Corporation
BHCRPP
Black Hills Corporation Risk Policies and Procedures
BHEP
Black Hills Exploration and Production, Inc., representing our Oil and Gas segment, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Electric Generation
Black Hills Electric Generation, LLC, representing our Power Generation segment, a direct wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy
The name used to conduct the business activities of Black Hills Utility Holdings
Black Hills Non-regulated Holdings
Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of the Company
Black Hills Power
Black Hills Power, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Service Company
Black Hills Service Company, a direct wholly-owned subsidiary of the Company
Black Hills Utility Holdings
Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of the Company
Black Hills Wyoming
Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Btu
British thermal unit
CFTC
United States Commodities Futures Trading Commission
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of the Company
Colorado Electric
Black Hills Colorado Electric Utility Company, LP, (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado Gas
Black Hills Colorado Gas Utility Company, LP, (doing business as Black Hills Energy), an indirect, wholly-owned subsidiary of Black Hills Utility Holdings
Colorado IPP
Black Hills Colorado IPP, a direct wholly-owned subsidiary of Black Hills Electric Generation
CPCN
Certificate of Public Convenience and Necessity
CPUC
Colorado Public Utilities Commission
CT
Combustion Turbine
 
 

3



De-designated interest rate swaps
The $250 million notional amount interest rate swaps that were originally designated as cash flow hedges under accounting for derivatives and hedges but subsequently de-designated in December 2008
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, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
Forward Agreement
Equity Forward Agreement with J.P. Morgan connected to a public offering of 4,413,519 shares of Black Hills Corporation common stock
GAAP
Generally Accepted Accounting Principles
Global Settlement
Settlement with the utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders
IFRS
International Financial Reporting Standards
Iowa Gas
Black Hills Iowa Gas Utility Company, LLC, (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
IPP
Independent Power Producer
IRS
Internal Revenue Service
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
One thousand standard cubic feet
Mcfe
One thousand standard cubic feet equivalent
MMBtu
One million British thermal units
MSHA
Mine Safety and Health Administration
MW
Megawatt
MWh
Megawatt-hour
Nebraska Gas
Black Hills Nebraska Gas Utility Company, LLC, (doing business as Black Hills Energy), a direct, wholly-owned subsidiary of Black Hills Utility Holdings
NPSC
Nebraska Public Service Commission
NYMEX
New York Mercantile Exchange
OCA
Office of Consumer Advocate
PGA
Purchase Gas Adjustment
PPA
Power Purchase Agreement
PPACA
Patient Protection and Affordability Care Act
Revolving Credit Facility
Our $500 million three-year revolving credit facility which commenced on April 15, 2010 and expires on April 14, 2013
SDPUC
South Dakota Public Utilities Commission
SEC
United States Securities and Exchange Commission
WPSC
Wyoming Public Service Commission
WRDC
Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings


4





BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
2010
 
2011
2010
 
(in thousands, except per share amounts)
Operating revenue:
 
 
 
 
 
Utilities
$
236,053

$
220,168

 
$
610,749

$
608,834

Non-regulated energy
37,072

36,170

 
65,676

74,004

Total operating revenue
273,125

256,338

 
676,425

682,838

 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
Utilities -
 
 
 
 
 
Fuel, purchased power and cost of gas sold
103,827

97,500

 
314,338

333,814

Operations and maintenance
58,689

66,029

 
126,098

131,063

Gain on sale of operating assets


 

(2,683
)
Non-regulated energy operations and maintenance
28,359

25,106

 
57,570

48,066

Depreciation, depletion and amortization
32,334

30,260

 
64,321

58,655

Taxes - property, production and severance
7,242

6,239

 
15,460

12,716

Other operating expenses
52

369

 
303

670

Total operating expenses
230,503

225,503

 
578,090

582,301

 
 
 
 
 
 
Operating income
42,622

30,835

 
98,335

100,537

 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
Interest charges -
 
 
 
 
 
Interest expense (including amortization of debt issuance costs, premium and discount, realized settlements on interest rate swaps)
(28,986
)
(25,994
)
 
(58,721
)
(51,114
)
Allowance for funds used during construction - borrowed
2,991

2,722

 
6,354

5,870

Capitalized interest
2,783

650

 
5,217

856

Interest rate swaps - unrealized (loss) gain
(7,827
)
(24,918
)
 
(2,362
)
(27,953
)
Interest income
475

84

 
1,035

330

Allowance for funds used during construction - equity
192

260

 
487

2,288

Other income, net
506

1,268

 
1,237

1,686

Total other income (expense)
(29,866
)
(45,928
)
 
(46,753
)
(68,037
)
 
 
 
 
 
 
Income (loss) before equity in earnings (loss) of unconsolidated subsidiaries and income taxes
12,756

(15,093
)
 
51,582

32,500

Equity in earnings (loss) of unconsolidated subsidiaries
40

1,291

 
1,033

1,608

Income tax benefit (expense)
(5,044
)
5,143

 
(17,953
)
(11,333
)
 
 
 
 
 
 
Net income (loss)
$
7,752

$
(8,659
)
 
$
34,662

$
22,775

 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
Basic
39,109

38,902

 
39,084

38,875

Diluted
39,823

38,902

 
39,793

39,042

 
 
 
 
 
 
Earnings (loss) per share - basic
$
0.20

$
(0.22
)
 
$
0.89

$
0.59

 
 
 
 
 
 
Earnings (loss) per share - diluted
$
0.19

$
(0.22
)
 
$
0.87

$
0.58

 
 
 
 
 
 
Dividends paid per share of common stock
$
0.365

$
0.360

 
$
0.730

$
0.720


The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.

5



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)

 
June 30,
2011
 
December 31,
2010
 
June 30,
2010
 
(in thousands)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
88,073

 
$
32,438

 
$
64,033

Restricted cash
3,710

 
4,260

 
16,169

Accounts receivable, net
244,829

 
328,811

 
208,185

Materials, supplies and fuel
105,608

 
139,677

 
135,049

Derivative assets, current
53,201

 
56,572

 
54,589

Income tax receivable, net
10,170

 

 

Deferred income tax assets, current
16,894

 
17,113

 
19,956

Regulatory assets, current
37,584

 
66,429

 
41,852

Other current assets
56,819

 
25,571

 
13,339

Total current assets
616,888

 
670,871

 
553,172

 
 
 
 
 
 
Investments
17,302

 
17,780

 
18,261

 
 
 
 
 
 
Property, plant and equipment
3,559,627

 
3,359,762

 
3,141,029

Less accumulated depreciation and depletion
(916,220
)
 
(864,329
)
 
(852,414
)
Total property, plant and equipment, net
2,643,407

 
2,495,433

 
2,288,615

 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
354,831

 
354,831

 
353,734

Intangible assets, net
3,955

 
4,069

 
4,189

Derivative assets, non-current
14,630

 
9,260

 
9,726

Regulatory assets, non-current
139,309

 
138,405

 
121,026

Other assets, non-current
20,442

 
20,860

 
21,559

Total other assets
533,167

 
527,425

 
510,234

 
 
 
 
 
 
TOTAL ASSETS
$
3,810,764

 
$
3,711,509

 
$
3,370,282


The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.

6



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

 
June 30,
2011
 
December 31,
2010
 
June 30,
2010
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
218,356

 
$
279,069

 
$
206,422

Accrued liabilities
140,814

 
170,301

 
130,194

Derivative liabilities, current
92,549

 
79,167

 
91,259

Accrued income taxes, net

 
779

 
13,974

Regulatory liabilities, current
17,220

 
3,943

 
22,447

Notes payable
380,000

 
249,000

 
225,000

Current maturities of long-term debt
3,613

 
5,181

 
4,539

Total current liabilities
852,552

 
787,440

 
693,835

 
 
 
 
 
 
Long-term debt, net of current maturities
1,183,583

 
1,186,050

 
990,130

 
 
 
 
 
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liabilities, non-current
307,549

 
277,136

 
271,684

Derivative liabilities, non-current
19,258

 
21,361

 
18,177

Regulatory liabilities, non-current
83,643

 
84,611

 
50,227

Benefit plan liabilities
131,169

 
124,709

 
148,190

Other deferred credits and other liabilities
124,941

 
129,932

 
115,656

Total deferred credits and other liabilities
666,560

 
637,749

 
603,934

 
 
 
 
 
 
Stockholders' equity:
 
 
 
 
 
Common stockholders' equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; issued 39,462,001, 39,280,048 and 39,204,231 shares, respectively
39,462

 
39,280

 
39,204

Additional paid-in capital
602,961

 
598,805

 
595,219

Retained earnings
491,208

 
486,075

 
468,430

Treasury stock at cost – 23,637, 10,962 and 1,021 shares, respectively
(691
)
 
(309
)
 
(27
)
Accumulated other comprehensive income (loss)
(24,871
)
 
(23,581
)
 
(20,443
)
Total stockholders' equity
1,108,069

 
1,100,270

 
1,082,383

 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
3,810,764

 
$
3,711,509

 
$
3,370,282


The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.

7



BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
 
Six Months Ended
June 30,
 
2011
 
2010
Operating activities:
(in thousands)
 
 
 
 
Net income (loss)
$
34,662

 
$
22,775

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
64,321

 
58,655

Derivative fair value adjustments
(9,939
)
 
(2,445
)
Gain on sale of operating assets

 
(2,683
)
Stock compensation
3,259

 
1,971

Unrealized mark-to-market loss (gain) on interest rate swaps
2,362

 
27,953

Deferred income taxes
31,709

 
(6,078
)
Equity in (earnings) loss of unconsolidated subsidiaries
(1,033
)
 
(1,608
)
Allowance for funds used during construction - equity
(487
)
 
(2,288
)
Employee benefit plans
7,287

 
8,143

Other, net
3,704

 
3,380

 
 
 
 
Changes in certain operating assets and liabilities:
 
 
 
Materials, supplies and fuel
42,547

 
(19,896
)
Accounts receivable and other current assets
44,540

 
93,873

Accounts payable and other current liabilities
(77,826
)
 
(50,011
)
Regulatory assets
32,029

 
(2,806
)
Regulatory liabilities
11,573

 
13,401

 
 
 
 
Contributions to defined pension plans
(550
)
 

Other operating activities
(6,141
)
 
1,654

Net cash provided by operating activities
182,017

 
143,990

 
 
 
 
Investing activities:
 
 
 
Property, plant and equipment additions
(225,863
)
 
(171,115
)
Proceeds from sale of ownership interest in operating assets

 
6,105

Payment for acquisition of assets

 
(2,250
)
Other investing activities
799

 
4,239

Net cash provided by (used in) investing activities
(225,064
)
 
(163,021
)
 
 
 
 
Financing activities:
 
 
 
Dividends paid
(29,530
)
 
(28,202
)
Common stock issued
1,437

 
2,281

Short-term borrowings - issuances
564,000

 
268,500

Short-term borrowings - repayments
(433,000
)
 
(208,000
)
Long-term debt - repayments
(4,052
)
 
(56,488
)
Other financing activities
(173
)
 
(7,928
)
Net cash provided by (used in) financing activities
98,682

 
(29,837
)
 
 
 
 
Net change in cash and cash equivalents
55,635

 
(48,868
)
 
 
 
 
Cash and cash equivalents, beginning of period
32,438

 
112,901

Cash and cash equivalents, end of period
$
88,073

 
$
64,033


See Note 3 for supplemental disclosure of cash flow information.

The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.

8



BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company's 2010 Annual Report on Form 10-K)

(1)     MANAGEMENT'S STATEMENT

The condensed consolidated financial statements included herein have been prepared by Black Hills Corporation (the "Company," "us," "we," or "our") without audit, 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 quarterly financial statements should be read in conjunction with the financial statements and the notes thereto, included in our 2010 Annual Report on Form 10-K filed with the SEC.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying condensed quarterly financial statements reflects all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2011, December 31, 2010 and June 30, 2010 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements, as well as changes in market price. In particular, the normal peak usage season for gas utilities is November through March and significant earnings variances can be expected between the Gas Utilities segment's peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months ended June 30, 2011 and June 30, 2010, and our financial condition as of June 30, 2011, December 31, 2010, and June 30, 2010 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.

Certain prior year data presented in the accompanying condensed consolidated financial statements have been reclassified to conform to the current year presentation. Specifically, (a) the Company has reclassified revenue into two categories:  Utilities revenue and Non-regulated energy revenue, (b) the categories of Fuel, purchased power and cost of gas sold and Operations and maintenance included in our Operating expenses have been reclassified into Utilities and Non-regulated energy, and (c) the Taxes - property, production and severance line has been reclassified to show only those taxes. Any taxes other than property, production and severance are now included in the respective Utility or Non-regulated energy operations and maintenance lines. Income taxes remain as a separate line item. These reclassifications had no effect on total assets, net income, cash flows or earnings per share.

Restatement - Subsequent to the issuance of the Company's 2010 consolidated financial statements, the Company's management determined that certain intercompany transactions with our rate regulated operations had not been properly eliminated in consolidation, resulting in an overstatement of Utility and Non-regulated energy revenue and Fuel, purchased power and cost of gas sold of $15.0 million and $30.8 million, in aggregate for the three and six months ended June 30, 2010, respectively.  As such, the condensed consolidated financial statements have been restated for the correction of this error.  The correction did not have an impact on our gross margin, net income, total assets or cash flows.



9



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

Recently Adopted Accounting Standards and Legislation

Fair Value Measurements, ASC 820

In January 2010, the FASB issued guidance related to improving disclosures about fair value measurements. The guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements, disclosure of inputs and techniques used in valuation and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements is required to be presented separately. These disclosures are required for interim and annual reporting periods and were effective for us on January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which were effective on January 1, 2011. The guidance required additional disclosures, but did not impact our financial position, results of operations or cash flows. The additional disclosures are included in Note 13 of these Notes to Condensed Consolidated Financial Statements.

Patient Protection and Affordable Care Act

In March 2010, the President of the United States signed into law comprehensive healthcare reform legislation under the PPACA as amended by the Healthcare and Education Reconciliation Act. The total potential impact on the Company, if any, cannot be determined until regulations are promulgated under the PPACA.  Included among the provisions of the PPACA is a change in the tax treatment of the Medicare Part D subsidy (the "subsidy") which affects our Non-Pension Postretirement Benefit Plan. Internal Revenue Code Section 139A has been amended to eliminate the deduction of the subsidy in reducing income for years beginning after December 31, 2012. The impact of this change in the tax treatment of the subsidy had an immaterial effect on our financial position, results of operations and cash flows. The Company will continue to assess the implications on our financial statements of the PPACA as related regulations and interpretations become available. 

Recently Issued Accounting Standards and Legislation

Other Comprehensive Income, ASU No. 2011-05

FASB issued an accounting standards update amending ASC 220 to improve the comparability, consistency and transparency of reporting of comprehensive income. The update amends existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income. Also, items that are reclassified from other comprehensive income to net income must be presented on the face of the financial statements. ASU No. 2011-05 requires retrospective application, and it is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. We believe the adoption of this update may change the order in which certain financial statements are presented and provide additional detail on those financial statements when applicable, but will not have any other impact on our financial statements.

Fair Value Measurement, ASU No. 2011-04

FASB issued an accounting standards update amending ASC 820 to achieve common fair value measurement and disclosure requirements between U.S. GAAP and IFRS. Additional disclosure requirements in the update include: (1) for Level 3 fair value measurements, quantitative information about unobservable inputs used, a description of the valuation processes used by the entity, and a qualitative discussion about the sensitivity of the measurements to changes in the unobservable inputs; (2) for an entity's use of a non-financial asset that is different from the asset's highest and best use, the reason for the difference; (3) for financial instruments not measured at fair value but for which disclosure of fair value is required, the fair value hierarchy level in which the fair value measurements were determined; and (4) the disclosure of all transfers between Level 1 and Level 2 of the fair value hierarchy. ASU No. 2011-04 is effective for fiscal years, and interim periods within those years, beginning after December 31, 2011, with early adoption permitted. We do not expect this amendment to have an impact on our financial position, results of operations, or cash flows.



10



Dodd-Frank Wall Street Reform and Consumer Protection Act

In July 2010, the President of the United States signed into law comprehensive financial reform legislation under Dodd-Frank. Title VII of Dodd-Frank effectively regulates many derivative transactions in the United States that were previously unregulated, including swap transactions in the over-the-counter market. Among other things, Dodd-Frank (i) mandates the clearing of some swaps through regulated central clearing organizations and the trading of clearing swaps through regulated exchanges or swap execution facilities, in each case subject to certain key exemptions, and (ii) authorizes regulators to establish collateral and margin requirements for certain swap transactions that are not cleared. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users, and includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. Significant rule-making by numerous governmental agencies, particularly the CFTC with respect to non-security commodities, will be required in order to implement the restrictions, limitations, and requirements contemplated by Dodd-Frank. We will continue to evaluate the impact as these rules become available.


(3)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

 
Six Months Ended
 
June 30,
2011
 
June 30,
2010
 
(in thousands)
Non-cash investing activities—
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
34,356

 
$
32,207

Cash (paid) refunded during the period for—
 
 
 
Interest (net of amounts capitalized)
$
(49,909
)
 
$
(26,881
)
Income taxes, net
$
10,638

 
$
(399
)
 

(4)    MATERIALS, SUPPLIES AND FUEL

The amounts of materials, supplies and fuel included in the accompanying Condensed Consolidated Balance Sheets, by major classification, were as follows (in thousands):

 
 
June 30,
2011
 
December 31,
2010
 
June 30,
2010
Materials and supplies
 
$
36,685

 
$
31,749

 
$
32,361

Fuel - Electric Utilities
 
8,808

 
9,687

 
8,913

Natural gas in storage — Gas Utilities
 
15,914

 
21,691

 
15,513

Commodities held by Energy Marketing*
 
44,201

 
76,550

 
78,262

Total materials, supplies and fuel
 
$
105,608

 
$
139,677

 
$
135,049

_____________
* As of June 30, 2011, December 31, 2010 and June 30, 2010, market adjustments related to natural gas held by Energy Marketing and recorded in inventory as part of fair value hedge transactions were $(0.6) million, $(9.1) million and $(8.5) million, respectively (see Note 12 for further discussion of Energy Marketing activities).



11



(5)    ACCOUNTS RECEIVABLE

Trade Accounts Receivable

Our Accounts receivable represents primarily customer trade accounts at our Electric Utilities and Gas Utilities segments and counterparty trade accounts at our Energy Marketing segment. This balance fluctuates primarily due to the seasonality of our Gas Utilities and volume and commodity prices at our Energy Marketing segment. We maintain an allowance for doubtful accounts that reflects our best estimate of probable uncollectible trade receivables. We regularly review our trade receivable allowances by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect our ability to collect.
Following is a summary of receivables (in thousands):

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

$
16,535

$
54,602

$
(685
)
$
53,917

Gas
33,572

11,891

45,463

(1,420
)
44,043

Oil and Gas
7,803


7,803

(161
)
7,642

Coal Mining
1,652


1,652


1,652

Energy Marketing
136,799


136,799

(173
)
136,626

Power Generation
106


106


106

Corporate
843


843


843

Total
$
218,842

$
28,426

$
247,268

$
(2,439
)
$
244,829


As of
Accounts
Unbilled
Total Accounts
Less Allowance for
Accounts
December 31, 2010
Receivable, Trade
Revenue
Receivable
 Doubtful Accounts
Receivable, net
Electric
$
51,005

$
19,572

$
70,577

$
(708
)
$
69,869

Gas
41,970

40,376

82,346

(1,425
)
80,921

Oil and Gas
6,213


6,213

(161
)
6,052

Coal Mining
2,420


2,420


2,420

Energy Marketing
157,064


157,064

(69
)
156,995

Power Generation
307


307


307

Corporate
12,247


12,247


12,247

Total
$
271,226

$
59,948

$
331,174

$
(2,363
)
$
328,811



As of
Accounts
Unbilled
Total Accounts
Less Allowance for
Accounts
June 30, 2010
Receivable, Trade
Revenue
Receivable
 Doubtful Accounts
Receivable, net
Electric
$
38,511

$
16,060

$
54,571

$
(1,051
)
$
53,520

Gas
29,291

10,676

39,967

(2,324
)
37,643

Oil and Gas
4,678


4,678

(176
)
4,502

Coal Mining
2,965


2,965


2,965

Energy Marketing
109,755


109,755

(746
)
109,009

Power Generation
346


346


346

Corporate
200


200


200

Total
$
185,746

$
26,736

$
212,482

$
(4,297
)
$
208,185



12



Income Tax Receivable

Income tax receivable is primarily comprised of estimated payments made at the federal, state and foreign levels. The estimated payments relate to multiple prior tax years and were included in taxes payable at both December 31, 2010 and June 30, 2010. During second quarter of 2011, a refund (including an estimate of after-tax interest income) was received as a result of a settlement reached with the IRS in mid-2010 and finalized in early 2011.


(6)    NOTES PAYABLE

Our credit facilities and debt securities contain certain restrictive covenants including, among others, recourse leverage ratios and consolidated net worth covenants. As of June 30, 2011, we were in compliance with these covenants. Our credit facilities and debt securities do not contain default provisions pertaining to our credit ratings.

We had the following short-term debt outstanding as of the Condensed Consolidated Balance Sheet dates (in thousands):
 
As of June 30, 2011
As of December 31, 2010
As of June 30, 2010
 
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Balance Outstanding
Letters of Credit
Revolving Credit Facility
$
130,000

$
43,000

$
149,000

$
46,900

$
225,000

$
36,500

Enserco Credit Facility

118,700


166,900


141,400

Term Loan due 2011
100,000


100,000




Term Loan due 2012
150,000






Total
$
380,000

$
161,700

$
249,000

$
213,800

$
225,000

$
177,900


Revolving Credit Facility

Our $500.0 million Revolving Credit Facility expiring April 14, 2013 contains an accordion feature which allows us to increase the capacity of the facility to $600.0 million and can be used for the issuance of letters of credit, to fund working capital needs and other corporate purposes. Borrowings are available under a base rate option or a Eurodollar option. The cost of borrowings or letters of credit is determined based upon our credit ratings. At current ratings levels, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 1.75%, 2.75% and 2.75%, respectively at June 30, 2011. The facility contains a commitment fee to be charged on the unused amount of the Facility. Based upon current credit ratings, the fee is 0.5%.

Deferred financing costs are being amortized over the term of the facility. The amortization expense is included in Interest expense on the accompanying Condensed Consolidated Statements of Income as follows (in thousands):

 
Deferred Financing
Amortization Expense
 
Costs Remaining on Balance Sheet as of
Three Months Ended
June 30,
Six Months Ended
June 30,
 
June 30, 2011
2011
2010
2011
2010
Deferred Financing Costs
$2,443
$
473

$
385

$
946

$
385


The Revolving Credit Facility includes the following covenants that we must comply with at the end of each quarter (dollars, in thousands). We were in compliance with these covenants as of June 30, 2011.

 
 
Actual
 
Covenant Requirement
Consolidated Net Worth
 
$
1,108,069

 
$
876,597

Recourse Leverage Ratio
 
59.3
%
 
65.0
%


13



Enserco Credit Facility

Enserco's two-year $250.0 million committed credit facility expiring May 7, 2012 contains an accordion feature which allows, with the consent of the administrative agent, the commitment under the facility to increase to $350.0 million. Maximum borrowings under the facility are subject to a sub-limit of $50.0 million. Borrowings under this facility are available under a base rate option or a Eurodollar option. Margins for base rate borrowings are 1.75% and for Eurodollar borrowings are 2.50%. Enserco Credit Facility covenants include tangible net worth, net working capital and realized net working capital requirements. Enserco was in compliance with these covenants as of June 30, 2011.

Deferred financing costs for the Enserco Credit Facility are being amortized over the term of the Enserco Credit Facility. The amortization expense is included in Interest expense on the accompanying Condensed Consolidated Statements of Income as follows (in thousands):
 
 
 
Amortization Expense
 
Deferred Financing Costs Remaining on Balance Sheet as of
Three Months Ended
June 30,
Six Months Ended
June 30,
 
June 30, 2011
2011
2010
2011
2010
Deferred Financing Costs
$1,117
$
293

$
449

$
561

$
982


Corporate Term Loan

In June 2011, we entered into a one-year $150.0 million unsecured, single draw, term loan with CoBank, the Bank of Nova Scotia and U.S. Bank due on June 24, 2012. The cost of borrowing under the loan is based on a spread of 125 basis points over LIBOR (1.44% at June 30, 2011). The covenants are substantially the same as those included in the Revolving Credit Facility and we were in compliance with these covenants as of June 30, 2011.



(7)    EARNINGS PER SHARE
 
Basic earnings (loss) per share are computed by dividing net income by the weighted-average number of common shares outstanding during the period. Diluted earnings (loss) per share are computed by using all dilutive common shares potentially outstanding during a period. A reconciliation of share amounts, used to compute earnings (loss) per share, is as follows (in thousands):

 
 
Three Months Ended
June 30,
Six Months Ended
June 30,
 
 
2011
2010
2011
2010
 
 
 
 
 
 
Net income (loss)
 
$
7,752

$
(8,659
)
$
34,662

$
22,775

 
 
 
 
 
 
Weighted average shares - basic
 
39,109

38,902

39,084

38,875

Dilutive effect of:
 
 
 
 
 
Restricted stock
 
148


140

99

Stock options
 
20


20

5

Forward equity issuance
 
533


496


Other
 
13


53

63

Weighted average shares - diluted
 
39,823

38,902

39,793

39,042

 

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):

14




 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
Stock options
102

 
137

 
81

 
228

Restricted stock
24

 
108

 
16

 

Other stock
31

 
64

 
15

 

 
157

 
309

 
112

 
228



(8)    COMPREHENSIVE INCOME (LOSS)

The following table presents the components of our comprehensive income (loss) (in thousands):

 
Three Months Ended June 30, 2011
Net income (loss)
 
 
$
7,752

Other comprehensive income (loss), net of tax:
 
 
 
Minimum pension liability adjustments
$

 
 
Taxes

 
 
Minimum pension liability adjustments, net of tax
 
 

 
 
 
 
Fair value adjustment on derivatives designated as cash flow hedges
$
(996
)
 
 
Taxes
231

 
 
Fair value adjustment on derivatives designated as cash flow hedges, net of tax
 
 
(765
)
 
 
 
 
Reclassification adjustments on cash flow hedges settled and included in net income (loss)
$
1,617

 
 
Taxes
(564
)
 
 
Reclassification adjustments on cash flow hedges settled and included in net income (loss), net of tax
 
 
1,053

 
 
 
 
Comprehensive income (loss)
 
 
$
8,040



15



 
Three Months Ended June 30, 2010
Net income (loss)
 
 
$
(8,659
)
Other comprehensive income (loss), net of tax:
 
 
 
Minimum pension liability adjustments
$
(27
)
 
 
Taxes

 
 
Minimum pension liability adjustments, net of tax
 
 
(27
)
 
 
 
 
Fair value adjustment on derivatives designated as cash flow hedges
$
(2,029
)
 
 
Taxes
746

 
 
Fair value adjustment on derivatives designated as cash flow hedges, net of tax
 
 
(1,283
)
 
 
 
 
Reclassification adjustments on cash flow hedges settled and included in net income (loss)
$
(5,117
)
 
 
Taxes
1,843

 
 
Reclassification adjustments on cash flow hedges settled and included in net income (loss), net of tax
 
 
(3,274
)
 
 
 
 
Comprehensive income (loss)
 
 
$
(13,243
)


 
Six Months Ended June 30, 2011
Net income (loss)
 
 
$
34,662

Other comprehensive income (loss), net of tax:
 
 
 
Minimum pension liability adjustments
$

 
 
Taxes

 
 
Minimum pension liability adjustments, net of tax
 
 

 
 
 
 
Fair value adjustment on derivatives designated as cash flow hedges
$
(4,781
)
 
 
Taxes
1,868

 
 
Fair value adjustment on derivatives designated as cash flow hedges, net of tax
 
 
(2,913
)
 
 
 
 
Reclassification adjustments on cash flow hedges settled and included in net income (loss)
$
2,478

 
 
Taxes
(855
)
 
 
Reclassification adjustments on cash flow hedges settled and included in net income (loss), net of tax
 
 
1,623

 
 
 
 
Comprehensive income (loss)
 
 
$
33,372



16



 
Six Months Ended June 30, 2010
Net income (loss)
 
 
$
22,775

Other comprehensive income (loss), net of tax:
 
 
 
Minimum pension liability adjustments
$
(8
)
 
 
Taxes
(7
)
 
 
Minimum pension liability adjustments, net of tax
 
 
(15
)
 
 
 
 
Fair value adjustment on derivatives designated as cash flow hedges
$
(22
)
 
 
Taxes
155

 
 
Fair value adjustment on derivatives designated as cash flow hedges, net of tax
 
 
133

 
 
 
 
Reclassification adjustments on cash flow hedges settled and included in net income (loss)
$
(2,179
)
 
 
Taxes
782

 
 
Reclassification adjustments on cash flow hedges settled and included in net income (loss), net of tax
 
 
(1,397
)
 
 
 
 
Comprehensive income (loss)
 
 
$
21,496


Balances by classification included within Accumulated other comprehensive loss on the accompanying Condensed Consolidated Balance Sheets are as follows (in thousands):

 
June 30,
2011
 
December 31,
2010
 
June 30,
2010
Derivatives designated as cash flow hedges
$
(13,729
)
 
$
(12,437
)
 
$
(10,751
)
Employee benefit plans
(11,142
)
 
(11,142
)
 
(9,651
)
Amount from equity-method investees

 
(2
)
 
(41
)
Total
$
(24,871
)
 
$
(23,581
)
 
$
(20,443
)


(9)     COMMON STOCK

Other than the following transactions, we had no material changes in our common stock during the six months ended June 30, 2011 from the amount reported in Note 11 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

Equity Compensation Plans

We granted 67,389 target performance shares to certain officers and business unit leaders for the January 1, 2011 through December 31, 2013 performance period during the six months ended June 30, 2011. Actual shares are issued after the end of the performance plan period. Performance shares are awarded based on our total stockholder return over the designated performance period as measured against a selected peer group and can range from 0% to 175% of target. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria. The performance awards are paid 50% in the form of cash and 50% in shares of common stock. The grant date fair value was $25.91 per share.

We issued 14,111 shares of common stock under the short-term incentive compensation plan during the six months ended June 30, 2011. Pre-tax compensation cost related to the awards was approximately $0.4 million, which was expensed in 2010.

17




We granted 132,270 shares of restricted common stock and restricted stock units during the six months ended June 30, 2011. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $4.0 million will be recognized over the 3 year vesting period.

We granted 99,000 stock options at a weighted-average exercise price of $32.04 during the six months ended June 30, 2011. The total fair value of approximately $0.6 million will be recognized over the 3 year vesting period.

Stock options totaling 4,500 were exercised during the six months ended June 30, 2011 at a weighted-average exercise price of $31.01 per share provided $0.1 million of proceeds.

Total compensation expense recognized for all equity compensation plans for the three months ended June 30, 2011 and 2010 was $0.9 million and $1.1 million, respectively, and for the six months ended June 30, 2011 and 2010 was $3.3 million and $2.9 million, respectively.

As of June 30, 2011, total unrecognized compensation expense related to non-vested stock awards was $9.9 million and is expected to be recognized over a weighted-average period of 2.1 years.

Dividend Reinvestment and Stock Purchase Plan

We have a Dividend Reinvestment and Stock Purchase Plan ("DRIP") under which stockholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We issued 50,724 new shares at a weighted-average price of $30.98 during the six months ended June 30, 2011. At June 30, 2011, 138,969 shares of unissued common stock were available for future offering under the DRIP Plan.

Dividend Restrictions

Our Revolving Credit Facility contains 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 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 50.0% of aggregate consolidated net income, if positive, since January 1, 2005. As of June 30, 2011, 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 shareholders 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 as of June 30, 2011:

Our utility subsidiaries are generally limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may be subject to further restrictions under the Federal Power Act. As of June 30, 2011, the restricted net assets at our Utilities Group were approximately $207.3 million.

Our Enserco credit facility is a borrowing base credit facility, the structure of which requires certain levels of tangible net worth and net working capital to be maintained for a given borrowing base election level. In order to maintain a borrowing base election level, Enserco may be restricted from making dividend payments to its parent company. Enserco's restricted net assets at June 30, 2011 were $153.1 million.

Pursuant to a covenant in the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has restricted assets of $100.0 million. Black Hills Non-regulated Holdings is the parent of Black Hills Electric Generation which is the parent of Black Hills Wyoming.


18



Forward Equity Instrument

In November 2010, we entered into a Forward Equity Agreement in connection with a public offering of 4,000,000 shares of Black Hills Corporation common stock. In December 2010, the underwriters exercised the over-allotment option to purchase an additional 413,519 shares under the same terms as the original Forward Equity Agreement. We may settle the equity forward instrument at any time up to the maturity date of November 10, 2011. We may also unilaterally elect to cash or net share settle on any date up to maturity, for all or a portion of the equity forward shares. It is our intent to settle the equity forward with the physical delivery of shares in the fourth quarter of 2011.

At June 30, 2011, the equity forward instrument could have been settled with physical delivery of 4,413,519 shares in exchange for $123.2 million. Assuming required notices were given and actions taken, the forward instruments could also have been net settled at June 30, 2011 with delivery of cash of approximately $9.6 million or approximately 331,000 shares of common stock.

Based on the closing Black Hills Corporation common stock price on June 30, 2011, and the forward price on that date of the initial equity forward of $27.92 and over-allotment shares of $27.92, the fair value net cash settlement of the 4,413,519 shares was approximately $9.6 million.


(10)     EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plans

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

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

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
Service cost
$
1,356

 
$
1,533

 
$
2,711

 
$
3,066

Interest cost
3,732

 
3,773

 
7,464

 
7,546

Expected return on plan assets
(4,239
)
 
(3,623
)
 
(8,478
)
 
(7,246
)
Prior service cost
25

 
305

 
50

 
610

Net loss
1,135

 
500

 
2,270

 
1,000

Curtailment expense

 

 

 

Net periodic benefit cost
$
2,009

 
$
2,488

 
$
4,017

 
$
4,976


Non-pension Defined Benefit Postretirement Healthcare Plans

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


19



The components of net periodic benefit cost for the Healthcare Plans were as follows (in thousands):
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
Service cost
$
375

 
$
377

 
$
750

 
$
754

Interest cost
542

 
611

 
1,084

 
1,222

Expected return on plan assets
(41
)
 
(52
)
 
(82
)
 
(104
)
Prior service benefit
(120
)
 
(77
)
 
(240
)
 
(154
)
Net transition obligation

 

 

 

Net loss (gain)
169

 
159

 
338

 
318

Net periodic benefit cost
$
925

 
$
1,018

 
$
1,850

 
$
2,036


It has been determined that our post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy.

Supplemental Non-qualified Defined Benefit Plans

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

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

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
Service cost
$
257

 
$
171

 
$
514

 
$
342

Interest cost
325

 
321

 
649

 
642

Prior service cost
1

 
1

 
2

 
2

Net loss
128

 
71

 
255

 
142

Net periodic benefit cost
$
711

 
$
564

 
$
1,420

 
$
1,128


Contributions

We anticipate that we will make contributions to each of the benefit plans during 2011 and 2012. Contributions to the Healthcare Plans and the Supplemental Plans are expected to be made in the form of benefit payments. Contributions are as follows (in thousands):

 
Contributions Made
Contributions Made
 
 
 
Three Months Ended June 30, 2011
Six Months Ended June 30, 2011
Contributions Remaining for 2011
Contributions Anticipated for 2012
Defined Benefit Pension Plans
$
550

$
550

$
10,000

$
13,431

Non-pension Defined Benefit Postretirement Healthcare Plans
$
882

$
1,764

$
1,765

$
3,765

Supplemental Non-qualified Defined Benefit Plans
$
235

$
470

$
472

$
896




20



(11)     SUMMARY OF INFORMATION RELATING TO SEGMENTS OF OUR BUSINESS

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. As of June 30, 2011, substantially all of our operations and assets were located within the United States.

We conduct our operations through the following six reportable segments:

Utilities Group —

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

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

Non-regulated Energy Group —

Oil and Gas, which produces, explores and operates oil and natural gas interests located in the Rocky Mountain region and other states;

Power Generation, which produces and sells power and capacity to wholesale customers from power plants located in Wyoming. Additionally, in 2009 our Power Generation segment entered into a 20-year PPA to supply Colorado Electric with 200 MW of capacity and energy from power plants under construction in Colorado, which are expected to be placed into service by December 31, 2011. In January 2011, we sold our ownership interests in the partnerships which owned the Idaho facilities;

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

Energy Marketing, which provides natural gas, crude oil, coal, power and environmental marketing and related services in the United States and Canada.

Segment information follows the accounting policies described in Note 1 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

Segment information included in the accompanying Condensed Consolidated Statements of Income and Condensed Consolidated Balance Sheets was as follows (in thousands):

Three Months Ended June 30, 2011
 
External
Operating
Revenue
 
Inter-segment
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
136,131

 
$
3,410

 
$
8,614

   Gas
 
99,922

 

 
4,440

Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas
 
18,838

 

 
(79
)
   Power Generation
 
891

 
6,889

 
548

   Coal Mining
 
6,266

 
9,274

 
(381
)
   Energy Marketing
 
11,077

 
1,399

 
3,695

Corporate (a)
 

 

 
(9,092
)
Inter-segment eliminations
 

 
(20,972
)
 
7

Total
 
$
273,125

 
$

 
$
7,752

    

21



Three Months Ended June 30, 2010
 
External
Operating
Revenue
 
Inter-segment
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
131,944

 
$
4,321

 
$
7,196

   Gas
 
87,115

 

 
(886
)
Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas  
 
18,658

 

 
221

   Power Generation
 
808

 
5,871

 
(416
)
   Coal Mining
 
7,805

 
7,244

 
3,074

   Energy Marketing
 
8,881

 
14

 
1,327

Corporate (a)
 

 

 
(19,161
)
Inter-segment eliminations
 

 
(16,323
)
 
(14
)
Total
 
$
255,211

 
$
1,127

 
$
(8,659
)
    
Six Months Ended June 30, 2011
 
External
Operating
Revenue
 
Inter-segment
Operating
Revenue
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
280,561

 
$
7,249

 
$
18,863

   Gas
 
330,188

 

 
23,703

Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas
 
36,744

 

 
(794
)
   Power Generation
 
1,739

 
13,661

 
1,734

   Coal Mining
 
13,880

 
17,155

 
(1,679
)
   Energy Marketing
 
13,313

 
1,628

 
1,054

Corporate (a)
 

 

 
(8,158
)
Inter-segment eliminations
 

 
(39,693
)
 
(61
)
Total
 
$
676,425

 
$

 
$
34,662

    
Six Months Ended June 30, 2010
 
External
Operating
Revenue
 
Inter-segment
Operating
Revenue (c)
 
Net Income (Loss)
Utilities:
 
 
 
 
 
 
   Electric
 
$
276,331

 
$
8,743

 
$
17,048

   Gas (b)
 
330,285

 

 
18,612

Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas 
 
38,401

 

 
2,569

   Power Generation
 
2,142

 
12,605

 
664

   Coal Mining
 
14,687

 
14,342

 
4,420

   Energy Marketing
 
18,737

 
(70
)
 
3,520

Corporate (a)
 

 

 
(24,128
)
Inter-segment eliminations
 

 
(33,365
)
 
70

Total
 
$
680,583

 
$
2,255

 
$
22,775

____________
(a) Net income (loss) includes a $5.1 million and a $1.5 million net after-tax mark-to-market loss on interest rate swaps for the three and six months ended June 30, 2011 and a $16.2 million and $18.2 million net after-tax loss on interest rate swaps for the three and six months ended June 30, 2010, respectively.
(b) 2010 Net income (loss) includes a $1.7 million after-tax gain on sale of operating assets in the Gas Utilities at Nebraska Gas.
(c) Total operating revenue has been restated to reflect elimination of intercompany activities previously not eliminated. See Note 1 for further discussion.

22





Total assets
June 30,
2011
 
December 31,
2010
 
June 30,
2010
Utilities:
 
 
 
 
 
   Electric (a)
$
1,900,806

 
$
1,834,019

 
$
1,736,413

   Gas
659,349

 
722,287

 
622,585

Non-regulated Energy:
 
 
 
 
 
   Oil and Gas
366,270

 
349,991

 
348,509

   Power Generation (a)
353,794

 
293,334

 
197,545

   Coal Mining
89,627

 
96,962

 
87,474

   Energy Marketing
352,525

 
314,930

 
294,043

Corporate
88,393

 
99,986

 
83,713

Total
$
3,810,764

 
$
3,711,509

 
$
3,370,282

____________
(a) Includes construction of a 180 MW power generation facility by our Colorado Electric utility and a 200 MW power generation facility by our Power Generation segment; both facilities are currently under construction and are expected to be completed by December 31, 2011.

(12)     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 counterparty risk. We have developed policies, processes, systems, and controls to manage and mitigate these risks.

Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks:

Commodity price risk associated with our marketing businesses, our natural long position with crude oil, natural gas and coal reserves and production, fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our Gas Utilities segment and from commodity price changes;

Interest rate risk associated with variable rate credit facilities and changes in forward interest rates used to determine the mark-to-market adjustment on our interest rate swaps; and

Foreign currency exchange risk associated with natural gas marketing transacted in Canadian dollars.

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

We actively manage our exposure to certain market risks as described in Note 3 of the Notes to our Consolidated Financial Statements in our 2010 Annual Report on Form 10-K. Our derivative and hedging activities included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income are detailed below and in Note 13.

Trading Activities

Our Energy Marketing segment is engaged in marketing of natural gas, crude oil, coal, power and environmental products, specializing in producer services, end-use origination and wholesale marketing in the United States and Canada.


23



Contracts and other activities at our Energy Marketing operations are accounted for under the accounting standards for energy trading contracts. As such, all of the contracts and other activities at our marketing operations that meet the definition of a derivative are accounted for at fair value. The fair values are recorded as either Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. The net gains or losses are recorded as Operating revenue in the accompanying Condensed Consolidated Statements of Income. Accounting for energy trading contracts precludes mark-to-market accounting for energy trading contracts that are not defined as derivatives pursuant to accounting standards for derivatives. As part of our marketing operations, we often employ strategies that include derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of our producer services, end-use origination and wholesale marketing groups. Except in limited circumstances when we are able to designate transportation, storage or inventory positions as part of a fair value hedge, accounting for derivatives and hedging generally does not allow us to mark inventory, transportation or storage positions to market. The result is that while a significant majority of our natural gas, crude oil and coal marketing positions are economically hedged, we are required to mark some parts of our overall strategies (the derivatives) to market value, but are generally precluded from marking the rest of our economic hedges (transportation, inventory or storage) to market. Volatility in reported earnings and derivative positions results from these accounting requirements.

To effectively manage our portfolios, we enter into forward physical commodity contracts, financial derivative instruments including over-the-counter swaps and options, and storage and transportation agreements. The business activities of our Energy Marketing segment are conducted within the parameters as defined and allowed in the BHCRPP and further delineated in the Energy Marketing Risk Management Policies and Procedures as approved by our Executive Risk Committee.

We use a number of quantitative tools to measure, monitor and limit our exposure to market risk in our marketing portfolio. We limit and monitor our market risk through established limits on the nominal size of positions based on type of trade, location and duration. Such limits include those on fixed price, basis, index, storage, transportation and foreign exchange positions.

Daily risk management activities include reviewing positions in relation to established position limits, assessing changes in daily mark-to-market and other non-statistical risk management techniques.

The contract or notional amounts and terms of our marketing activities and derivative commodity instruments were as follows. Coal marketing activity began June 1, 2010, Power marketing began late in the third quarter of 2010, and Environmental marketing began late in the third quarter of 2010 with no significant activity until the second quarter of 2011:

 
Outstanding at
 
Outstanding at
 
Outstanding at
 
June 30, 2011
 
December 31, 2010
 
June 30, 2010
 
Notional
Amounts
 
Latest
Expiration
(months)
 
Notional
Amounts
 
Latest
Expiration
(months)
 
Notional
Amounts
 
Latest
Expiration
(months)
(in thousands of MMBtus)
 
 
 
 
 
 
 
 
 
 
 
Natural gas basis swaps purchased
607,228

 
45

 
399,128

 
22

 
238,853

 
21

Natural gas basis swaps sold
627,858

 
45

 
426,903

 
22

 
252,060

 
21

Natural gas fixed-for-float swaps purchased
216,067

 
27

 
135,005

 
33

 
67,103

 
39

Natural gas fixed-for-float swaps sold
213,106

 
30

 
150,803

 
22

 
86,200

 
19

Natural gas physical purchases
135,429

 
30

 
144,948

 
36

 
122,687

 
21

Natural gas physical sales
136,409

 
75

 
143,021

 
36

 
123,629

 
39

Natural gas futures purchased
18,270

 
10

 

 

 

 

Natural gas futures sold
31,630

 
10

 

 

 

 

Natural gas options purchased

 

 

 

 

 

Natural gas options sold

 

 

 

 

 



24



 
Outstanding at
 
Outstanding at
 
Outstanding at
 
June 30, 2011
 
December 31, 2010
 
June 30, 2010
 
Notional
Amounts
 
Latest
Expiration
(months)
 
Notional
Amounts
 
Latest
Expiration
(months)
 
Notional
Amounts
 
Latest
Expiration
(months)
(in thousands of Bbls)
 
 
 
 
 
 
 
 
 
 
 
Crude oil physical purchases
5,765

 
10

 
5,628

 
16

 
4,673

 
6

Crude oil physical sales
5,680

 
10

 
6,921

 
16

 
4,754

 
6

Crude oil fixed-for-float swaps purchased
230

 
1

 
20

 
3

 

 

Crude oil fixed-for-float swaps sold
420

 
3

 
240

 
4

 
140

 
4


 
Outstanding at
 
Outstanding at
 
Outstanding at
 
June 30, 2011
 
December 31, 2010
 
June 30, 2010
 
Notional
Amounts
Latest
Expiration
(months)
 
Notional
Amounts
Latest
Expiration
(months)
 
Notional
Amounts
Latest
Expiration
(months)
(in thousands of tons)
 
 
 
 
 
 
 
 
Coal fixed-for-float swaps purchased
6,040

30

 
4,060

36

 
6,910

29

Coal fixed-for-float swaps sold
7,025

30

 
3,720

36

 
4,985

30

Coal physical purchases
27,761

42

 
24,634

48

 
24,925

54

Coal physical sales
11,584

30

 
9,046

36

 
6,472

38

Coal options purchased
4,278

54

 
2,835

48

 
334

42

Coal options sold
602

6

 
270

12

 
1,804

30


 
Outstanding at
 
Outstanding at
 
Outstanding at
 
June 30, 2011
 
December 31, 2010
 
June 30, 2010
(in thousands of MWh):
Notional
Amounts
Latest
Expiration
(months)
 
Notional
Amounts
Latest
Expiration
(months)
 
Notional
Amounts
Latest
Expiration
(months)
Power physical purchases


 


 


Power physical sales
157

57
 


 


Power fixed-for-float swaps purchased
6,568

30
 


 


Power fixed-for-float swaps sold
6,848

30
 


 



 
Outstanding at
 
Outstanding at
 
Outstanding at
 
June 30, 2011
 
December 31, 2010
 
June 30, 2010
(in thousands of MWh):
Notional
Amounts
Latest
Expiration
(months)
 
Notional
Amounts
Latest
Expiration
(months)
 
Notional
Amounts
Latest
Expiration
(months)
Environmental products physical purchases
70

15

 


 


Environmental products physical sales
157

57

 


 





25



Derivatives and certain other marketing transactions were marked to fair value at June 30, 2011, December 31, 2010 and June 30, 2010, and the related gains and/or losses recognized in earnings. The amounts included in the accompanying Condensed Consolidated Balance Sheets and Condensed Consolidated Statements of Income were as follows (in thousands):

 
June 30,
2011
 
December 31,
2010
 
June 30,
2010
Current derivative assets
$
43,657

 
$
43,862

 
$
41,576

Non-current derivative assets
$
13,907

 
$
6,635

 
$
5,888

Current derivative liabilities
$
26,922

 
$
14,550

 
$
15,912

Non-current derivative liabilities
$
1,977

 
$
3,464

 
$
(168
)
Cash collateral (receivable)/payable included in derivative assets/liabilities
$
1,250

 
$
3,958

 
$

Unrealized gain
$
27,415

 
$
28,525

 
$
31,720

Credit risk-related contingent features that require us to maintain a specific credit rating.
$

 
$

 
$

    
In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in fair value hedge transactions. These volumes include market adjustments based on published industry quotations. Market adjustments are recorded in Materials, supplies and fuel on the accompanying Condensed Consolidated Balance Sheets and the related unrealized gain or loss on the Condensed Consolidated Statements of Income, effectively offsetting the earnings impact of the unrealized gain or loss recognized on the associated derivative asset or liability described above. As of June 30, 2011, December 31, 2010 and June 30, 2010, the market adjustments recorded in inventory were $(0.6) million, $(9.1) million and $(8.5) million, respectively.

Activities Other Than Trading

Oil and Gas Exploration and Production

We produce natural gas and crude oil through our exploration and production activities. Our natural "long" positions, or unhedged open positions, result in commodity price risk and variability to our cash flows. We employ risk management methods to mitigate this commodity price risk and preserve our cash flows and we have adopted guidelines covering hedging for our natural gas and crude oil production. These guidelines have been approved by our Executive Risk Committee, and are routinely reviewed by our Board of Directors.

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

The derivatives were marked to fair value and are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. The effective portion of the gain or loss on these derivatives is reported in Accumulated other comprehensive income (loss) and the ineffective portion, if any, is reported in earnings.


26



We had the following derivatives and related balances (dollars in thousands):

 
June 30, 2011
 
December 31, 2010
 
June 30, 2010
 
Crude Oil
Swaps/
Options
 
Natural Gas
Swaps
 
Crude Oil
Swaps/
Options
 
Natural Gas
Swaps
 
Crude Oil
Swaps/
Options
 
Natural Gas
Swaps
Notional*
463,500

 
5,969,250

 
424,500

 
6,821,800

 
520,500

 
9,397,800

Maximum terms in years **
1.00

 
0.25

 
0.25

 
0.25

 
0.25

 
0.50

Derivative assets, current
$
449

 
$
6,160

 
$
248

 
$
7,675

 
$
2,040

 
$
6,855

Derivative assets, non-current
$
214

 
$
456

 
$
19

 
$
2,606

 
$
855

 
$
2,983

Derivative liabilities, current
$
2,385

 
$

 
$
3,814

 
$

 
$
2,170

 
$
44

Derivative liabilities, non-current
$
1,201

 
$
117

 
$
1,301

 
$

 
$
178

 
$
4

Pre-tax accumulated other comprehensive income (loss) included in Condensed Consolidated Balance Sheets
$
3,173

 
$
6,499

 
$
(5,313
)
 
$
10,281

 
$
(161
)
 
$
9,790

Earnings
$
250

 
$

 
$
465

 
$

 
$
708

 
$

____________
* Crude oil in Bbls, gas in MMBtus
** Refers to the term of the derivative instrument. Assets and liabilities are classified as current or non-current based on the timing of the hedged transaction and the corresponding settlement of the derivative instruments.
Based on June 30, 2011 market prices, a $3.9 million gain would be realized and reported in pre-tax earnings during the next 12 months related to hedges of production. Estimated and actual realized gains will likely change during the next 12 months as market prices change.

Gas Utilities - Gas Hedges

Our Gas Utilities segment distributes natural gas in four states. During the winter heating season, our gas customers are exposed to the effect of volatile natural gas prices; therefore, as allowed or required by state utility commissions, we have entered into certain exchange traded natural gas futures, options and basis swaps to reduce our customers' underlying exposure to these fluctuations. These transactions are considered derivatives in accordance with accounting standards for derivatives and mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets. Gains and losses, as well as option premiums upon settlement, on these transactions are recorded as Regulatory assets or Regulatory liabilities in accordance with accounting standards for regulated operations. Accordingly, the earnings impact is recognized in the Condensed Consolidated Statements of Income as a component of PGA costs when the related costs are recovered through our rates as part of PGA costs in operating revenue.

The contract or notional amounts and terms of our natural gas derivative commodity instruments held at our Gas Utilities were as follows:

 
Outstanding at
 
Outstanding at
 
Outstanding at
 
June 30, 2011
 
December 31, 2010
 
June 30, 2010
 
Notional
Amounts (MMBtus)
 
Latest
Expiration
(months)
 
Notional
Amounts (MMBtus)
 
Latest
Expiration
(months)
 
Notional
Amounts (MMBtus)
 
Latest
Expiration
(months)
Natural gas futures purchased
7,820,000

 
21

 
6,670,000

 
15

 
8,230,000

 
21

Natural gas options purchased
1,560,000

 
9

 
1,730,000

 
3

 
1,520,000

 
9

Natural gas basis swaps purchased

 

 

 

 

 



27



We had the following derivative balances related to the hedges in our gas utilities (in thousands):

 
June 30,
2011
 
December 31,
2010
 
June 30,
2010
Current derivative assets
$
2,935

 
$
4,787

 
$
3,806

Non-current derivative assets
$
53

 
$

 
$

Non-current derivative liabilities
$
175

 
$
1,620

 
$
612

Net unrealized gain (loss) included in regulatory assets or regulatory liabilities
$
(4,229
)
 
$
8,030

 
$
7,150

Cash collateral (receivable) payable included in derivative assets/liabilities
$
(6,254
)
 
$
(10,355
)
 
$
(9,551
)
Option premium included in Derivative assets, current
$
760

 
$
842

 
$
792


Financing Activities

We are exposed to interest rate risk associated with fluctuations in the interest rate on our variable interest rate debt. To manage this risk, we have entered into floating-to-fixed interest rate swap agreements with the intention to convert the debt's variable interest rate to a fixed rate.

Our interest rate swaps and related balances were as follows (dollars in thousands):

 
June 30, 2011
 
December 31, 2010
 
June 30, 2010
 
Designated 
Interest Rate
Swaps
 
Dedesignated
Interest Rate
Swaps*
 
Designated
Interest Rate
Swaps
 
Dedesignated
Interest Rate
Swaps*
 
Designated
Interest Rate
Swaps
 
Dedesignated
Interest Rate
Swaps*
Current notional amount
$
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
5.50

 
0.50

 
6.00

 
1.00

 
6.50

 
0.50

Derivative liabilities, current
$
6,900

 
$
56,342

 
$
6,823

 
$
53,980

 
$
6,393

 
$
66,740

Derivative liabilities, non-current
$
15,788

 
$

 
$
14,976

 
$

 
$
17,551

 
$

Pre-tax accumulated other comprehensive loss included in Condensed Consolidated Balance Sheets
$
(22,688
)
 
$

 
$
(21,799
)
 
$

 
$
(23,944
)
 
$

Pre-tax (loss) gain included in Condensed Consolidated Statements of Income
$

 
$
(2,362
)
 
$

 
$
(15,193
)
 
$

 
$
(27,953
)
Cash collateral (receivable) payable included in accounts receivable
$

 
$

 
$

 
$

 
$

 
$

_____________
*     Maximum terms in years reflect the amended mandatory early termination dates. If the mandatory 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 million terminate in 7.5 years and de-designated swaps totaling $150 million terminate in 17.5 years.

Based on June 30, 2011 market interest rates and balances related to our designated interest rate swaps, a loss of approximately $6.9 million would be realized and reported in pre-tax earnings during the next 12 months. Estimated and realized losses will likely change during the next 12 months as market interest rates change. Note 13 provides further information related to the swaps that are not designated as hedges for accounting purposes.

Foreign Exchange Contracts

Our Energy Marketing segment conducts its gas marketing in the United States and Canada. Transactions in Canada are generally transacted in Canadian dollars and create exchange rate risk for us. To mitigate this risk, we enter into forward currency exchange contracts to offset earnings volatility from changes in exchange rates between the Canadian and United States dollar.


28



We had the following outstanding forward contracts included in Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets as follows (dollars in thousands):

 
As of June 30, 2011
 
As of December 31, 2010
 
As of June 30, 2010
 
Outstanding Notional Amounts
Latest Expiration (Months)
 
Outstanding Notional Amounts
Latest Expiration (Months)
 
Outstanding Notional Amounts
Latest Expiration (Months)
Canadian dollars purchased
$


 
$
15,000

1

 
$
5,000

1

Canadian dollars sold
$


 
$


 
$



Our outstanding foreign exchange contracts had a fair value as follows (in thousands):

 
As of June 30, 2011
As of December 31, 2010
As of June 30, 2010
Fair Value
$

$
(143
)
$


We recognized the following gains and losses in Operating revenue on the accompanying Condensed Consolidated Statements of Income (in thousands):

 
Three Months Ended
June 30,
Six Months Ended
June 30,
 
2011
2010
2011
2010
Unrealized foreign exchange gain (loss)
$
90

$
(48
)
$
(162
)
$
84

Realized foreign exchange gain (loss)
$
100

$
(450
)
$
438

$
(591
)


(13)     FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

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

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

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

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

Recurring Fair Value Measures

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.


29



The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis (in thousands):

 
 
As of June 30, 2011
 
 
Level 1
 
Level 2
 
Level 3
 
Counterparty
Netting

 
Cash Collateral
 
Total
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives — Energy Marketing
 
$

 
$
200,447

 
$
14,536

 
$
(156,755
)
 
$
(664
)
 
$
57,564

Commodity derivatives — Oil and Gas
 

 
7,168

 
111

 

 

 
7,279

Commodity derivatives — Regulated Utilities Group
 

 
(3,266
)
 

 

 
6,254

 
2,988

Money market funds
 
6,006

 

 

 

 

 
6,006

Total
 
$
6,006

 
$
204,349

 
$
14,647

 
$
(156,755
)
 
$
5,590

 
$
73,837

 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives — Energy Marketing
 
$

 
$
179,348

 
$
8,220

 
$
(156,755
)
 
$
(1,914
)
 
$
28,899

Commodity derivatives — Oil and Gas
 

 
3,703

 

 

 

 
3,703

Commodity derivatives — Regulated Utilities Group
 

 
175

 

 

 

 
175

Foreign currency derivatives
 

 

 

 

 

 

Interest rate swaps
 

 
79,030

 

 

 

 
79,030

Total
 
$

 
$
262,256

 
$
8,220

 
$
(156,755
)
 
$
(1,914
)
 
$
111,807

 
 
 
As of December 31, 2010
 
 
Level 1
 
Level 2
 
Level 3
 
Counterparty
Netting
 
Cash Collateral
 
Total
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives — Energy Marketing
 
$

 
$
166,405

 
$
7,976

 
$
(124,049
)
 
$

 
$
50,332

Commodity derivatives — Oil and Gas
 

 
10,281

 
266

 

 

 
10,547

Commodity derivatives — Regulated Utilities Group
 

 
(5,568
)
 

 

 
10,355

 
4,787

Money market funds
 
8,050

 

 

 

 

 
8,050

Foreign currency derivatives
 

 
166

 

 

 

 
166

Total
 
$
8,050

 
$
171,284

 
$
8,242

 
$
(124,049
)
 
$
10,355

 
$
73,882

 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives — Energy Marketing
 
$

 
$
143,537

 
$
2,463

 
$
(131,965
)
 
$
3,958

 
$
17,993

Commodity derivatives — Oil and Gas
 

 
5,115

 

 

 

 
5,115

Commodity derivatives — Regulated Utilities Group
 

 
1,620

 

 

 

 
1,620

Foreign currency derivatives
 

 
21

 

 

 

 
21

Interest rate swaps
 

 
75,779

 

 

 

 
75,779

Total
 
$

 
$
226,072

 
$
2,463

 
$
(131,965
)
 
$
3,958

 
$
100,528

 

30



 
 
As of June 30, 2010
 
 
Level 1
 
Level 2
 
Level 3
 
Counterparty
Netting

 
Cash Collateral
 
Total
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives — Energy Marketing
 
$

 
$
173,008

 
$
3,411

 
$
(128,909
)
 
$

 
$
47,510

Commodity derivatives — Oil and Gas
 

 
11,422

 
1,265

 

 

 
12,687

Commodity derivatives — Regulated Utilities Group
 

 
(5,433
)
 

 

 
9,551

 
4,118

Money market funds
 
9,006

 

 

 

 

 
9,006

Foreign currency derivatives
 

 

 

 

 

 

 
 
$
9,006

 
$
178,997

 
$
4,676

 
$
(128,909
)
 
$
9,551

 
$
73,321

 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivatives — Energy Marketing
 
$

 
$
142,184

 
$
2,500

 
$
(128,908
)
 
$

 
$
15,776

Commodity derivatives — Oil and Gas
 

 
2,349

 

 

 

 
2,349

Commodity derivatives — Regulated Utilities Group
 

 
612

 

 

 

 
612

Foreign currency derivatives
 

 
15

 

 

 

 
15

Interest rate swaps
 

 
90,684

 

 

 

 
90,684

Total
 
$

 
$
235,844

 
$
2,500

 
$
(128,908
)
 
$

 
$
109,436


The following tables present the changes in level 3 recurring fair value for the three and six months ended June 30, 2011 and 2010, respectively (in thousands):

 
Three Months Ended June 30, 2011
 
Six Months Ended June 30, 2011
 
Commodity
Derivatives
 
Commodity
Derivatives
Balance as of beginning of period
$
4,413

 
$
5,779

Unrealized losses
3,577

 
(2,622
)
Unrealized gains
(648
)
 
5,553

Purchases

 

Issuances

 

Settlements
261

 
(1,958
)
Transfers into level 3 (a)
(1,074
)
 
(254
)
Transfers out of level 3(b)
(102
)
 
(71
)
Balances at end of period
$
6,427

 
$
6,427

 
 
 
 
Changes in unrealized gains relating to instruments still held as of period-end
$
1,267

 
$
240



31



 
Three Months Ended June 30, 2010
 
Six Months Ended June 30, 2010
 
Commodity
 Derivatives
 
Commodity
 Derivatives
Balance as of beginning of period
$
1,295

 
$
(556
)
Unrealized losses
(952
)
 
(2,167
)
Unrealized gains
2,345

 
3,726

Settlements
(498
)
 
(805
)
Transfers into level 3 (a)
(16
)
 
(16
)
Transfers out of level 3(b)
2

 
1,994

Balances at end of period
$
2,176

 
$
2,176

 
 
 
 
Changes in unrealized losses relating to instruments still held as of period-end
$
66

 
$
1,811

____________
(a)
Transfers into level 3 represent assets and liabilities that were previously categorized as a higher level for which the inputs became unobservable.
(b)
Transfers out of level 3 represent assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.

Gains and losses (realized and unrealized) for level 3 commodity derivatives totaling $3.0 million and $3.0 million for the three and six months ended June 30, 2011, respectively, are included in Operating revenue on the accompanying Condensed Consolidated Statements of Income while $(0.1) million and $(0.1) million was recorded through Accumulated other comprehensive income (loss) on the accompanying Condensed Consolidated Balance Sheets for the three and six months ended June 30, 2011, respectively. Commodity derivatives classified as level 3, may be economically hedged as part of a total portfolio of instruments that may be classified in level 1 or 2, or with instruments that may not be accounted for at fair value. Accordingly, gains and losses associated with level 3 balances may not necessarily reflect trends occurring in the underlying business. Further, unrealized gains and losses for the period from level 3 items may be offset by unrealized gains and losses in positions classified in level 1 or 2, as well as positions that have been realized during the quarter.

Fair Value Measures

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis and do not reflect the netting of asset and liability positions. Further, the amounts do not include net cash collateral of $7.5 million, $14.3 million and $9.6 million on deposit in margin accounts at June 30, 2011, December 31, 2010, and June 30, 2010, respectively, to collateralize certain financial instruments, which are included in Derivative assets - current, Derivative assets - non-current, Derivative liabilities - current and/or Derivative liabilities - non-current. Therefore, the gross 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 12.


32



The following tables present the fair value and balance sheet classification of our derivative instruments (in thousands):

As of June 30, 2011
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
 
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
849

 
$
74

Commodity derivatives
Derivative assets — non-current
 

 

Commodity derivatives
Derivative liabilities — current
 

 
79

Commodity derivatives
Derivative liabilities — non-current
 

 

Interest rate swaps
Derivative liabilities — current
 

 
6,900

Interest rate swaps
Derivative liabilities — non-current
 

 
15,788

Total derivatives designated as hedges
 
 
$
849

 
$
22,841

 
 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
198,892

 
$
152,056

Commodity derivatives
Derivative assets — non-current
 
40,249

 
25,619

Commodity derivatives
Derivative liabilities — current
 
27,819

 
59,070

Commodity derivatives
Derivative liabilities — non-current
 
686

 
4,047

Foreign currency derivatives
Derivative liabilities — current
 

 

Interest rate swaps
Derivative liabilities — current
 

 
56,342

Total derivatives not designated as hedges
 
 
$
267,646

 
$
297,134



As of December 31, 2010
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
 
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
10,952

 
$
1,452

Commodity derivatives
Derivative assets — non-current
 
48

 
71

Commodity derivatives
Derivative liabilities — current
 

 
45

Commodity derivatives
Derivative liabilities — non-current
 

 

Interest rate swaps
Derivative liabilities — current
 

 
6,823

Interest rate swaps
Derivative liabilities — non-current
 

 
14,976

Total derivatives designated as hedges
 
 
$
11,000

 
$
23,367

 
 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
149,936

 
$
113,364

Commodity derivatives
Derivative assets — non-current
 
12,382

 
3,099

Commodity derivatives
Derivative liabilities — current
 
20,588

 
42,865

Commodity derivatives
Derivative liabilities — non-current
 
978

 
7,363

Foreign currency derivatives
Derivative assets — current
 
166

 
21

Interest rate swaps
Derivative liabilities — current
 

 
53,980

Total derivatives not designated as hedges
 
 
$
184,050

 
$
220,692




33



As of June 30, 2010
 
Balance Sheet Location
 
Fair Value
of Asset
Derivatives
 
Fair Value
of Liability
Derivatives
Derivatives designated as hedges:
 
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
9,790

 
$
1,369

Commodity derivatives
Derivative assets — non-current
 
6

 

Commodity derivatives
Derivative liabilities — current
 
16

 
8

Commodity derivatives
Derivative liabilities — non-current
 

 
8

Interest rate swaps
Derivative liabilities — current
 

 
6,393

Interest rate swaps
Derivative liabilities — non-current
 

 
17,551

Total derivatives designated as hedges
 
 
$
9,812

 
$
25,329

 
 
 
 
 
 
Derivatives not designated as hedges:
 
 
 
 
 
Commodity derivatives
Derivative assets — current
 
$
151,994

 
$
115,377

Commodity derivatives
Derivative assets — non-current
 
20,657

 
10,937

Commodity derivatives
Derivative liabilities — current
 
13,891

 
32,010

Commodity derivatives
Derivative liabilities — non-current
 

 
618

Interest rate swaps
Derivative liabilities — current
 

 
66,740

Interest rate swaps
Derivative liabilities — non-current
 

 

Foreign currency derivatives
Derivative asset — current
 

 
15

Foreign currency derivatives
Derivative liabilities — current
 

 

Total derivatives not designated as hedges
 
 
$
186,542

 
$
225,697


Our derivative activities are discussed in Note 12. The following tables present the impact that derivatives had on our Condensed Consolidated Statements of Income for the three and six months ended June 30, 2011.

Fair Value Hedges

The impact of commodity contracts designated as fair value hedges and the related hedged items on our accompanying Condensed Consolidated Statements of Income was as follows (in thousands):

 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
 
 
June 30, 2011
 
June 30, 2011
Derivatives
in Fair Value
 Hedging Relationships
 
Location of Gain/(Loss)
 on Derivatives
 Recognized in Income
 
Amount of Gain/(Loss)
on Derivatives
Recognized in Income
 
Amount of Gain/(Loss)
on Derivatives
 Recognized in Income

 
 
 
 
 
 
 
Commodity derivatives
 
Operating revenue
 
$
980

 
$
(8,737
)
Fair value adjustment for natural gas inventory designated as the hedged item
 
Operating revenue
 
(903
)
 
8,479

 
 
 
 
$
77

 
$
(258
)

 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
 
 
June 30, 2010
 
June 30, 2010
Derivatives
in Fair Value
 Hedging Relationships
 
Location of Gain/(Loss)
 on Derivatives
 Recognized in Income
 
Amount of Gain/(Loss)
on Derivatives
Recognized in Income
 
Amount of Gain/(Loss)
on Derivatives
 Recognized in Income

 
 
 
 
 
 
 
Commodity derivatives
 
Operating revenue
 
$
(3,199
)
 
$
8,009

Fair value adjustment for natural gas inventory designated as the hedged item
 
Operating revenue
 
2,569

 
(8,178
)
 
 
 
 
$
(630
)
 
$
(169
)


34



Cash Flow Hedges

The impact of cash flow hedges on our Condensed Consolidated Statements of Income was as follows (in thousands):

Three Months Ended June 30, 2011
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
 
$
(4,768
)
 
Interest expense
 
$
(1,919
)
 
 
 
$

Commodity derivatives
 
3,772

 
Operating revenue
 
302

 
Operating revenue
 

Total
 
$
(996
)
 
 
 
$
(1,617
)
 
 
 
$


Three Months Ended June 30, 2010
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
 
$
(9,812
)
 
Interest expense
 
$
(3,519
)
 
 
 
$

Commodity derivatives
 
(491
)
 
Operating revenue
 
(5,191
)
 
Operating revenue
 
(154
)
Total
 
$
(10,303
)
 
 
 
$
(8,710
)
 
 
 
$
(154
)

Six Months Ended June 30, 2011
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
Gain/(Loss)
Reclassified
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
 
$
(4,470
)
 
Interest expense
 
$
(3,811
)
 
 
 
$

Commodity derivatives
 
(311
)
 
Operating revenue
 
1,333

 
Operating revenue
 

Total
 
$
(4,781
)
 
 
 
$
(2,478
)
 
 
 
$


Six Months Ended June 30, 2010
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
Gain/(Loss)
Reclassified
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
 
$
(11,886
)
 
Interest expense
 
$
(3,824
)
 
 
 
$

Commodity derivatives
 
6,090

 
Operating revenue
 
(1,948
)
 
Operating revenue
 
(317
)
Total
 
$
(5,796
)
 
 
 
$
(5,772
)
 
 
 
$
(317
)


35



Derivatives Not Designated as Hedge Instruments

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

 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
 
 
June 30, 2011
 
June 30, 2011
Derivatives Not Designated
 as Hedging Instruments
 
Location of Gain/(Loss)
 on Derivatives
 Recognized in Income
 
Amount of Gain/(Loss)
on Derivatives
Recognized in Income
 
Amount of Gain/(Loss)
 on Derivatives
 Recognized in Income
Commodity derivatives
 
Operating revenue
 
$
8,438

 
$
4,208

Interest rate swaps - unrealized
 
Interest rate swaps — unrealized (loss) gain
 
(7,827
)
 
(2,362
)
Interest rate swaps - realized
 
Interest expense
 
(3,352
)
 
(6,704
)
Foreign currency contracts
 
Operating revenue
 
106

 
(143
)
 
 
 
 
$
(2,635
)
 
$
(5,001
)

 
 
 
 
Three Months Ended
 
Six Months Ended
 
 
 
 
June 30, 2010
 
June 30, 2010
Derivatives Not Designated
 as Hedging Instruments
 
Location of Gain/(Loss)
 on Derivatives
 Recognized in Income
 
Amount of Gain/(Loss)
on Derivatives
Recognized in Income
 
Amount of Gain/(Loss)
 on Derivatives
 Recognized in Income
Commodity derivatives
 
Operating revenue
 
$
6,868

 
$
4,209

Interest rate swaps - unrealized
 
Interest rate swaps — unrealized (loss) gain
 
(24,918
)
 
(27,953
)
Interest rate swaps - realized
 
Interest expense
 
(2,863
)
 
(6,180
)
Foreign currency contracts
 
Operating revenue
 
(15
)
 
(15
)
 
 
 
 
$
(20,928
)
 
$
(29,939
)


(14)     FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair value of our financial instruments is as follows (in thousands):

 
 
June 30, 2011
 
December 31, 2010
 
June 30, 2010
 
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
 
Carrying
Amount
 
Fair Value
Cash and cash equivalents
 
$
88,073

 
$
88,073

 
$
32,438

 
$
32,438

 
$
64,033

 
$
64,033

Restricted cash
 
$
3,710

 
$
3,710

 
$
4,260

 
$
4,260

 
$
16,169

 
$
16,169

Derivative financial instruments - assets
 
$
67,831

 
$
67,831

 
$
65,832

 
$
65,832

 
$
64,315

 
$
64,315

Derivative financial instruments - liabilities
 
$
111,807

 
$
111,807

 
$
100,528

 
$
100,528

 
$
109,436

 
$
109,436

Notes payable
 
$
380,000

 
$
380,000

 
$
249,000

 
$
249,000

 
$
225,000

 
$
225,000

Long-term debt, including current maturities
 
$
1,187,196

 
$
1,313,052

 
$
1,191,231

 
$
1,290,519

 
$
994,669

 
$
1,101,903


The following methods and assumptions were used to estimate the fair value of each class of our financial instruments.

Cash, Cash Equivalents

The carrying amount approximates fair value due to the short maturity of these instruments.


36



Restricted Cash

Restricted cash is primarily related to cash held in escrow required by Black Hills Wyoming project financing agreements. Some of these funds are held in 30-day guaranteed investment certificates.

Derivative Financial Instruments

Derivative financial instruments are carried at fair value. Our fair value measurements are developed using a variety of inputs by our risk management group, which is independent of the trading function. These inputs include unadjusted quoted prices where available; prices published by various third-party providers; and, when necessary, internally developed adjustments. In many cases, the internally developed prices are corroborated with external sources. Some of our transactions take place in markets with limited liquidity and limited price visibility. Additionally, descriptions of the various instruments we use and the valuation method employed are included in Notes 12 and 13.

Notes Payable

The carrying amount approximates fair value due to the variable interest rates with short reset periods.

Long-Term Debt

The fair value of our long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings. The first mortgage bonds issued by Black Hills Power and Cheyenne Light are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefits if we were to call these bonds.


(15)     COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We are subject to various legal proceedings, claims and litigation as described in Note 19 of the Notes to our Consolidated Financial Statements in our 2010 Annual Report on Form 10-K. There are no material proceedings that have developed, no material developments with respect to existing legal proceedings and no material proceedings have terminated during the first six months of 2011.

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations.  We believe the amounts provided in our consolidated financial statements are adequate in light of the probable and estimable contingencies.  However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our consolidated financial statements.  As such, costs, if any, that may be incurred in excess of those amounts provided as of June 30, 2011, cannot be reasonably determined and could have a material adverse effect on our results of operations or financial position.

Guarantees

The construction of the office building in Papillion, Nebraska was completed and the guarantee for $6.0 million was terminated upon purchase of the building on April 1, 2011.

We had provided a guarantee for up to $7.0 million of Enserco's obligations under an agency agreement. During the first quarter of 2011 the guarantee expired upon fulfillment of all obligations under the contract.

In June 2011, a guarantee to Colorado Interstate Gas was amended. It was increased to $10.0 million and the expiration date was extended to July 31, 2012. All other terms remained the same.

In June 2011, we issued a guarantee to Cross Timbers Energy Services for the performance and payment obligations of Black Hills Utility Holdings for natural gas supply purchases up to $7.5 million. The guarantee expires on June 30, 2012 or upon 30 days written notice to the counterpart.


37



Other Commitments

Construction of a 180 MW power generation facility by our Colorado Electric utility and a 200 MW power generation facility by our Power Generation segment is progressing. Cost of construction is expected to be approximately $227.0 million for Colorado Electric and approximately $260.0 million for the Power Generation segment. Construction is expected to be completed at both facilities by December 31, 2011. As our plans progress, we are in the process of procuring or have procured contracts for the turbines, building construction and labor. As of June 30, 2011, committed contracts for equipment purchases and for construction were 100% and 95% complete, respectively, for the Colorado Electric utility and 100% and 94% complete, respectively, for the Power Generation segment.

PPA Extension

In June 2011, FERC approved an extension of the PPA between Black Hills Wyoming and Cheyenne Light which was due to expire in August 2011. This agreement, now extended through August 2014, provides 40 MW of energy and capacity to Cheyenne Light from Black Hills Wyoming's Gillette CT.



(16)     SUBSEQUENT EVENT

In July 2011, we issued a guarantee to Vestas-American Wind Technology, Inc. for the performance and payment obligations of Colorado Electric for $33.3 million relating to the purchase of wind turbines for a Colorado Electric wind power generation project. This guarantee will remain in effect until satisfaction of Colorado Electric's contractual obligations. We expect the guarantee to expire on or about January 15, 2013.


38



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

We are a diversified 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 reportable operating segments:

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

Our Utilities Group consists of our Electric and Gas Utilities segments. Our Electric Utilities generate, transmit and distribute electricity to approximately 201,000 customers in South Dakota, Wyoming, Colorado and Montana. In addition, Cheyenne Light, which is also reported within the Electric Utilities segment, provides natural gas to approximately 34,500 customers in Wyoming. Our Gas Utilities serve approximately 527,000 natural gas customers in Colorado, Nebraska, Iowa and Kansas. Our Non-regulated Energy Group engages in the production of coal, natural gas and crude oil primarily in the Rocky Mountain region; the production of electric power from our generating plants and the sale of electric power and capacity primarily under long-term contracts; and the marketing of natural gas, crude oil, coal, power, environmental products and related services in the United States and Canada.

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 gas utilities is November through March and significant earnings variances can be expected between the Gas Utilities segment's peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months ended June 30, 2011, and our financial condition as of June 30, 2011, December 31, 2010, and June 30, 2010 and are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.
See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 70.

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.


Results of Operations

Executive Summary, Significant Events and Overview

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010. Net income for the three months ended June 30, 2011 was $7.8 million, or $0.19 per share, compared to Net loss of $8.7 million, or $0.22 per share, reported for the same period in 2010. The 2011 Net income includes a $5.1 million non-cash after-tax unrealized mark-to-market loss on certain interest rate swaps. The 2010 Net loss included a $16.2 million after-tax unrealized mark-to-market loss on these same interest rate swaps.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010. Net income for the six months ended June 30, 2011 was $34.7 million, or $0.87 per share, compared to $22.8 million, or $0.58 per share, reported for the same period in 2010. The 2011 Net income includes a $1.5 million non-cash after-tax unrealized mark-to-market loss on certain interest rate swaps. The 2010 Net income included an $18.2 million after-tax mark-to-market loss on these same interest rate swaps and a $1.7 million after-tax gain on the sale of assets of Nebraska Gas.


39



 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
2010
Increase (Decrease)
 
2011
2010
Increase (Decrease)
Operating Revenue *
 
 
 
 
 
 
 
Utilities
$
239,463

$
223,380

$
16,083

 
$
617,998

$
615,359

$
2,639

Non-regulated Energy
54,634

49,281

5,353

 
98,120

100,844

(2,724
)
Intercompany eliminations
(20,972
)
(16,323
)
(4,649
)
 
(39,693
)
(33,365
)
(6,328
)
 
$
273,125

$
256,338

$
16,787

 
$
676,425

$
682,838

$
(6,413
)
 
 
 
 
 
 
 
 
Net income (loss)
 
 
 
 
 
 
 
Electric Utilities
$
8,614

$
7,196

1,418

 
$
18,863

$
17,048

$
1,815

Gas Utilities
4,440

(886
)
5,326

 
23,703

18,612

5,091

Utilities
13,054

6,310

6,744

 
42,566

35,660

6,906

 
 
 
 
 
 
 
 
Oil and Gas
(79
)
221

(300
)
 
(794
)
2,569

(3,363
)
Power Generation
548

(416
)
964

 
1,734

664

1,070

Coal Mining
(381
)
3,074

(3,455
)
 
(1,679
)
4,420

(6,099
)
Energy Marketing
3,695

1,327

2,368

 
1,054

3,520

(2,466
)
Non-regulated Energy
3,783

4,206

(423
)
 
315

11,173

(10,858
)
 
 
 
 
 
 
 
 
Corporate
(9,092
)
(19,161
)
10,069

 
(8,158
)
(24,128
)
15,970

 
 
 
 
 
 
 
 
Inter-company eliminations
7

(14
)
21

 
(61
)
70

(131
)
 
$
7,752

$
(8,659
)
$
16,411

 
$
34,662

$
22,775

$
11,887

______________
*    2010 Operating Revenue has been restated to eliminate certain inter-company revenue previously not eliminated. This change did not have an impact on our gross margin or net income. See Note 1 of the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q

Business Group highlights are as follows:

Utilities Group

Our return on investments made in the utilities was positively impacted by new and interim rates and tariffs implemented in five utility jurisdictions during 2010 and early 2011. Consequently, revenues have been positively impacted for rates that were not in effect in the prior periods.

Utility
State
Effective Date
Annual Revenue Increase (in millions)
Black Hills Power
SD
4/2010
$
15.2

 
Black Hills Power
SD
6/2010
$
3.1

 
Colorado Electric
CO
8/2010
$
17.9

 
Nebraska Gas
NE
3/2010
$
8.3

 
Iowa Gas
IA
6/2010
$
3.4

 
 
 
 
$
47.9

 

Construction of gas-fired generation to serve Colorado Electric customers is continuing to progress and is on schedule to begin providing energy on or before January 1, 2012. The 180 MW generation project is expected to cost approximately $227 million, of which $204 million has been expended through June 30, 2011;

40




On August 1, 2011, Cheyenne Light filed a CPCN with the WPSC requesting approval to construct and operate a new $158 million 120 MW electric generation facility. The new generation will include three simple-cycle, gas-fired combustion turbines each with a capacity of 40 MW. Pending WPSC approval, commercial operation would commence in 2014;

On June 13, 2011, the SDPUC dismissed Black Hills Power's request for declaratory ruling to confirm that a proposed 20 MW wind farm site near Belle Fourche, SD is reasonable and cost effective. The dismissal resulted in a decision by Black Hills Power not to proceed with this project;

In June 2011, the SDPUC approved an Environmental Improvement Adjustment tariff for Black Hills Power. The Environmental Improvement Adjustment, which was implemented to recover Black Hill Power's investment of $25 million for pollution control equipment at the PacifiCorp-operated Wyodak plant, went into effect on June 1, 2011 with an annual revenue of $3.1 million;

On April 28, 2011, Colorado Electric filed a request with the CPUC for a revenue increase of $40.2 million to recover costs and a return associated with the 180 MW generation project and other utility infrastructure assets and expenses, including PPA costs associated with the 200 MW Colorado IPP generation facility. The proposed rate increase would go into effect on January 1, 2012 to coincide with the expiration of the PPA with PSCo that is being replaced with the new 380 MW of gas-fired generation. A hearing on the rate case with the CPUC has been scheduled for late October 2011;

On March 24, 2011, Colorado Electric filed a proposal with the CPUC to rate base 50% ownership in a 29 MW wind turbine project as part of its plan to meet Colorado's Renewable Energy Standard. Our share of this project is expected to cost approximately $26.5 million and is expected to begin serving Colorado Electric customers no later than December 31, 2012. A settlement has been reached and a decision by the CPUC is pending; and

On March 14, 2011, Colorado Electric filed a request for a CPCN to construct a third utility-owned natural gas-fired turbine with an approximate cost of $102.0 million, excluding transmission. This CPCN request was filed in accordance with a December 2010 CPUC order. This order approved the retirement of the W.N. Clark coal-fired power plant under the Colorado Clean Air-Clean Jobs Act and granted a presumption of need for a third turbine. The CPCN approval is pending.
 
Non-regulated Energy Group

Construction of gas-fired generation at Colorado IPP to serve a 20-year PPA with Colorado Electric is continuing to progress and is on schedule to begin providing energy on January 1, 2012. The 200 MW project is expected to cost approximately $260 million, of which $226 million has been expended through June 30, 2011; and

In January 2011, we sold our ownership interests in the partnerships that owned the Idaho generating facilities for $0.8 million and recorded a gain of $0.8 million.

Corporate

We recognized a non-cash unrealized mark-to-market loss related to certain interest rate swaps of $2.4 million for the six months ended June 30, 2011 compared to a $28.0 million unrealized mark-to-market loss on these swaps for the same period in 2010; and

In June 2011, we entered into a $150 million one year, unsecured, single draw, term loan. The cost of borrowing under this term loan is based on a spread of 125 basis points over LIBOR.

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, Nebraska, Iowa and Kansas.



41



Electric Utilities

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
 
(in thousands)
Revenue — electric
$
132,978

 
$
128,408

 
$
267,848

 
$
261,176

Revenue — gas
6,563

 
7,857

 
19,962

 
23,898

Total revenue
139,541

 
136,265

 
287,810

 
285,074

 
 
 
 
 
 
 
 
Fuel and purchased power — electric
66,254

 
64,794

 
131,932

 
138,305

Purchased gas
3,484

 
4,581

 
11,880

 
15,772

Total fuel and purchased power
69,738

 
69,375

 
143,812

 
154,077

 
 
 
 
 
 
 
 
Gross margin — electric
66,724

 
63,614

 
135,916

 
122,871

Gross margin — gas
3,079

 
3,276

 
8,082

 
8,126

Total gross margin
69,803

 
66,890

 
143,998

 
130,997

 
 
 
 
 
 
 
 
Operations and maintenance
34,156

 
35,956

 
71,270

 
68,724

Gain on sale of operating assets

 

 

 

Depreciation and amortization
13,006

 
11,897

 
25,830

 
23,086

Total operating expenses
47,162

 
47,853

 
97,100

 
91,810

 
 
 
 
 
 
 
 
Operating income
22,641

 
19,037

 
46,898

 
39,187

 
 
 
 
 
 
 
 
Interest expense, net
(10,107
)
 
(8,448
)
 
(20,051
)
 
(16,702
)
Other income (expense)
(53
)
 
315

 
356

 
2,440

Income tax expense
(3,867
)
 
(3,708
)
 
(8,340
)
 
(7,877
)
 
 
 
 
 
 
 
 
Net income
$
8,614

 
$
7,196

 
$
18,863

 
$
17,048



42



The following tables summarize revenue, quantities generated and purchased, quantities sold, degree days and plant availability for our Electric Utilities segment:

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Revenue - electric (in thousands)
2011
 
2010
 
2011
 
2010
Residential:
 
 
 
 
 
 
 
Black Hills Power
$
12,773

 
$
11,546

 
$
29,943

 
$
26,025

Cheyenne Light
7,026

 
6,785

 
15,097

 
14,710

Colorado Electric
19,155

 
16,607

 
39,591

 
36,023

Total Residential
38,954

 
34,938

 
84,631

 
76,758

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Black Hills Power
17,759

 
16,104

 
35,073

 
30,643

Cheyenne Light
13,495

 
13,416

 
26,038

 
25,872

Colorado Electric
18,373

 
16,005

 
34,958

 
31,695

Total Commercial
49,627

 
45,525

 
96,069

 
88,210

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Black Hills Power
6,464

 
6,204

 
12,228

 
10,841

Cheyenne Light
2,944

 
2,882

 
5,556

 
5,412

Colorado Electric
8,567

 
6,841

 
16,434

 
13,785

Total Industrial
17,975

 
15,927

 
34,218

 
30,038

 
 
 
 
 
 
 
 
Municipal:
 
 
 
 
 
 
 
Black Hills Power
783

 
748

 
1,517

 
1,401

Cheyenne Light
455

 
237

 
846

 
468

Colorado Electric
3,186

 
2,871

 
6,122

 
4,558

Total Municipal
4,424

 
3,856

 
8,485

 
6,427

 
 
 
 
 
 
 
 
Contract Wholesale:
 
 
 
 
 
 
 
Black Hills Power
4,370

 
7,078

 
8,990

 
13,796

 
 
 
 
 
 
 
 
Off-system Wholesale:
 
 
 
 
 
 
 
Black Hills Power
7,442

 
8,539

 
14,395

 
17,255

Cheyenne Light
2,580

 
2,119

 
5,467

 
4,710

Colorado Electric (a)

 
2,903

 

 
10,236

Total Off-system Wholesale
10,022

 
13,561

 
19,862

 
32,201

 
 
 
 
 
 
 
 
Other:
 
 
 
 
 
 
 
Black Hills Power
6,507

 
6,219

 
13,146

 
10,966

Cheyenne Light
567

 
789

 
1,256

 
1,701

Colorado Electric
532

 
515

 
1,191

 
1,079

Total Other
7,606

 
7,523

 
15,593

 
13,746

 
 
 
 
 
 
 
 
Total Revenue - electric
$
132,978

 
$
128,408

 
$
267,848

 
$
261,176


(a) In August 2010, Colorado Electric agreed with the CPUC to defer off-system operating income until a sharing mechanism is settled upon. As a result Colorado Electric deferred $3.5 million and $6.4 million in off-system revenue during the three and six months ended June 30, 2011, respectively.

43



 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Quantities Generated and Purchased (in MWh)
2011
 
2010
 
2011
 
2010
Generated —
 
 
 
 
 
 
 
Coal-fired:
 
 
 
 
 
 
 
Black Hills Power
386,006

 
559,258

 
823,844

 
989,831

Cheyenne Light
169,195

 
181,475

 
340,566

 
357,899

Colorado Electric
71,236

 
55,993

 
127,911

 
126,244

Total Coal
626,437

 
796,726

 
1,292,321

 
1,473,974

 
 
 
 
 
 
 
 
Gas and Oil-fired:
 
 
 
 
 
 
 
Black Hills Power
1,147

 
1,106

 
2,171

 
3,944

Cheyenne Light

 

 

 

Colorado Electric
30

 
93

 
30

 
93

Total Gas and Oil-fired
1,177

 
1,199

 
2,201

 
4,037

 
 
 
 
 
 
 
 
Total Generated:
 
 
 
 
 
 
 
Black Hills Power
387,153

 
560,364

 
826,015

 
993,775

Cheyenne Light
169,195

 
181,475

 
340,566

 
357,899

Colorado Electric
71,266

 
56,086

 
127,941

 
126,337

Total Generated
627,614

 
797,925

 
1,294,522

 
1,478,011

 
 
 
 
 
 
 
 
Purchased —
 
 
 
 
 
 
 
Black Hills Power
401,218

 
290,518

 
776,830

 
720,200

Cheyenne Light
179,079

 
151,570

 
376,248

 
344,427

Colorado Electric
486,052

 
487,956

 
968,837

 
1,029,158

Total Purchased
1,066,349

 
930,044

 
2,121,915

 
2,093,785

 
 
 
 
 
 
 
 
Total Generated and Purchased:
 
 
 
 
 
 
 
Black Hills Power
788,371

 
850,882

 
1,602,845

 
1,713,975

Cheyenne Light
348,274

 
333,045

 
716,814

 
702,326

Colorado Electric
557,318

 
544,042

 
1,096,778

 
1,155,495

Total Generated and Purchased
1,693,963

 
1,727,969

 
3,416,437

 
3,571,796



44



 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
Quantity Sold (in MWh)
2011
 
2010
 
2011
 
2010
Residential:
 
 
 
 
 
 
 
Black Hills Power
107,683

 
113,903

 
282,083

 
288,438

Cheyenne Light
58,532

 
59,152

 
131,410

 
133,972

Colorado Electric
138,644

 
137,581

 
295,999

 
304,610

Total Residential
304,859

 
310,636

 
709,492

 
727,020

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Black Hills Power
167,649

 
164,863

 
345,886

 
349,301

Cheyenne Light
143,645

 
143,915

 
289,244

 
289,124

Colorado Electric
180,168

 
181,641

 
345,902

 
352,595

Total Commercial
491,462

 
490,419

 
981,032

 
991,020

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Black Hills Power
105,861

 
101,425

 
194,610

 
188,088

Cheyenne Light
42,642

 
43,671

 
83,470

 
84,430

Colorado Electric
91,188

 
85,484

 
175,097

 
169,994

Total Industrial
239,691

 
230,580

 
453,177

 
442,512

 
 
 
 
 
 
 
 
Municipal:
 
 
 
 
 
 
 
Black Hills Power
7,739

 
7,577

 
16,041

 
15,803

Cheyenne Light
2,150

 
679

 
4,594

 
1,613

Colorado Electric
32,079

 
33,638

 
59,826

 
49,416

Total Municipal
41,968

 
41,894

 
80,461

 
66,832

 
 
 
 
 
 
 
 
Contract Wholesale:
 
 
 
 
 
 
 
Black Hills Power (a)
82,253

 
120,258

 
172,212

 
288,723

 
 
 
 
 
 
 
 
Off-system Wholesale:
 
 
 
 
 
 
 
Black Hills Power
278,086

 
299,064

 
520,242

 
530,111

Cheyenne Light
79,741

 
63,995

 
163,926

 
148,262

Colorado Electric (b)
94,945

 
73,513

 
173,448

 
233,288

Total Off-system Wholesale
452,772

 
436,572

 
857,616

 
911,661

 
 
 
 
 
 
 
 
Total Quantity Sold:
 
 
 
 
 
 
 
Black Hills Power
749,271

 
807,090

 
1,531,074

 
1,660,464

Cheyenne Light
326,710

 
311,412

 
672,644

 
657,401

Colorado Electric
537,024

 
511,857

 
1,050,272

 
1,109,903

Total Quantity Sold
1,613,005

 
1,630,359

 
3,253,990

 
3,427,768

 
 
 
 
 
 
 
 
Losses and Company Use:
 
 
 
 
 
 
 
Black Hills Power
39,100

 
43,792

 
71,771

 
53,511

Cheyenne Light
21,564

 
21,633

 
44,170

 
44,925

Colorado Electric
20,294

 
32,185

 
46,506

 
45,592

Total Losses and Company Use
80,958

 
97,610

 
162,447

 
144,028

 
 
 
 
 
 
 
 
Total Energy
1,693,963

 
1,727,969

 
3,416,437

 
3,571,796

(a) Decrease in 2011 MWh is due to the termination of a wholesale contract with a previous wholesale power customer who acquired ownership interest in the Wygen III facility.
(b) In August 2010, Colorado Electric agreed with the CPUC to defer off-system operating income until a sharing determined. In accordance with this agreement, operating income for off-system MWh sold at Colorado Electric totaling $0.1 million and $0.2 million have been deferred in accordance with an agreement with the CPUC for the three and six months ended June 30, 2011. Operating income of $1.1 million has been deferred since the rate case was approved in August 2010.

45



 
Three Months Ended
June 30,
Degree Days
2011
 
2010
Heating Degree Days:
Actual
 
Variance
 from
 Normal
 
Actual
 
Variance
 from
 Normal
Actual —
 
 
 
 
 
 
 
Black Hills Power
1,190

 
19
 %
 
904

 
9
 %
Cheyenne Light
1,354

 
10
 %
 
1,308

 
6
 %
Colorado Electric
638

 
(1
)%
 
647

 
1
 %
 
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
 
Actual —
 
 
 
 
 
 
 
Black Hills Power
56

 
(45
)%
 
65

 
(37
)%
Cheyenne Light
30

 
(29
)%
 
35

 
(17
)%
Colorado Electric
294

 
36
 %
 
280

 
30
 %

 
Six Months Ended
June 30,
Degree Days
2011
 
2010
Heating Degree Days:
Actual
 
Variance
 from
 Normal
 
Actual
 
Variance
 from
 Normal
Actual —
 
 
 
 
 
 
 
Black Hills Power
4,897

 
14
 %
 
4,296

 
4
 %
Cheyenne Light
4,477

 
2
 %
 
4,418

 
1
 %
Colorado Electric
3,419

 
4
 %
 
3,424

 
4
 %
 
 
 
 
 
 
 
 
Cooling Degree Days:
 
 
 
 
 
 
 
Actual —
 
 
 
 
 
 
 
Black Hills Power
56

 
(45
)%
 
65

 
(37
)%
Cheyenne Light
30

 
(29
)%
 
35

 
(17
)%
Colorado Electric
294

 
36
 %
 
280

 
30
 %
 
Electric Utilities Power Plant Availability
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2011
 
2010
 
2011
 
2010
 
Coal-fired plants
88.6
%
(a)
90.0
%
(b)
89.9
%
(a)
91.3
%
(b)
Other plants
89.9
%
(c)
97.4
%
 
94.3
%
 
98.6
%
 
Total availability
89.0
%
 
92.6
%
 
91.5
%
 
93.9
%
 
____________
(a) Reflects a planned major outage at the PacifiCorp-operated Wyodak plant.
(b) Reflects an unplanned outage at the PacifiCorp-operated Wyodak plant.
(c) Reflects a planned major overhaul at Neil Simpson CT.


46



Cheyenne Light Natural Gas Distribution

Included in the Electric Utilities segment is Cheyenne Light's natural gas distribution system. The following table summarizes certain operating information for these natural gas distribution operations:

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
Revenue (in thousands):
 
 
 
 
 
 
 
Residential
$
4,053

 
$
4,770

 
$
12,031

 
$
14,283

Commercial
1,739

 
2,222

 
5,546

 
7,055

Industrial
580

 
663

 
1,856

 
2,121

Other
191

 
202

 
529

 
439

Total Revenue
$
6,563

 
$
7,857

 
$
19,962

 
$
23,898

 
 
 
 
 
 
 
 
Gross Margin (in thousands):
 
 
 
 
 
 
 
Residential
$
2,332

 
$
2,298

 
$
5,720

 
$
5,550

Commercial
694

 
752

 
1,906

 
1,969

Industrial
98

 
60

 
275

 
227

Other
(45
)
 
166

 
181

 
380

Total Gross Margin
$
3,079

 
$
3,276

 
$
8,082

 
$
8,126

 
 
 
 
 
 
 
 
Volumes Sold (Dth):
 
 
 
 
 
 
 
Residential
497,250

 
555,636

 
1,565,711

 
1,695,179

Commercial
302,543

 
331,723

 
926,266

 
992,841

Industrial
140,135

 
135,370

 
396,656

 
377,545

Total Volumes Sold
939,928

 
1,022,729

 
2,888,633

 
3,065,565



47



Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010. Net income for the Electric Utilities segment was $8.6 million for the three months ended June 30, 2011 compared to $7.2 million for the three months ended June 30, 2010 as a result of:

Gross margin increased $2.9 million primarily due to recently approved rate adjustments that include a return on significant capital investments, partially offset by lower margins resulting from the termination of power sales contracts upon a customer's purchase of an ownership interest in Wygen III in 2010.

Operations and maintenance decreased $1.8 million primarily due to unplanned maintenance expenditures at the PacifiCorp-operated Wyodak plant in 2010 partially offset by increased allocation of corporate costs.

Depreciation and amortization increased $1.1 million primarily due to higher asset base.

Interest expense, net increased $1.7 million due to higher debt balances associated with recent capital investments.

Other income was comparable to the same period in the prior year.

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

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010. Net income for the Electric Utilities segment was $18.9 million for the six months ended June 30, 2011 compared to $17.0 million for the six months ended June 30, 2010 as a result of:

Gross margin increased $13.0 million primarily due to recently approved rate adjustments that include a return on significant capital investments, partially offset by lower volumes resulting from the termination of power sales contracts upon a customer's purchase of an ownership interest in Wygen III in 2010.

Operations and maintenance increased $2.5 million primarily due to an increase in labor and employee benefit costs and increased allocation of corporate costs.

Depreciation and amortization increased $2.7 million primarily due to depreciation commencing on Wygen III and a higher asset base.

Interest expense, net increased $3.3 million due to due to higher debt balances associated with recent capital investments.

Other income decreased $2.1 million primarily due to decreased AFUDC-equity which ceased with the commencement of commercial operation of our Wygen III facility.

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



48



Gas Utilities

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
 
(in thousands)
Revenue:
 
 
 
 
 
 
 
Natural gas — regulated
$
93,598

 
$
79,727

 
$
316,630

 
$
315,182

Other — non-regulated services
6,324

 
7,388

 
13,558

 
15,103

Total revenue
99,922

 
87,115

 
330,188

 
330,285

 
 
 
 
 
 
 
 
Cost of sales:
 
 
 
 
 
 
 
Natural gas — regulated
49,956

 
39,324

 
199,459

 
202,751

Other — non-regulated services
3,154

 
3,754

 
6,780

 
7,772

Total cost of sales
53,110

 
43,078

 
206,239

 
210,523

 
 
 
 
 
 
 
 
Gross margin
46,812

 
44,037

 
123,949

 
119,762

 
 
 
 
 
 
 
 
Operations and maintenance
28,249

 
32,091

 
62,809

 
66,449

Gain on sale of operating assets

 

 

 
(2,683
)
Depreciation and amortization
5,947

 
6,774

 
11,968

 
13,819

Total operating expenses
34,196

 
38,865

 
74,777

 
77,585

 
 
 
 
 
 
 
 
Operating income (loss)
12,616

 
5,172

 
49,172

 
42,177

 
 
 
 
 
 
 
 
Interest expense, net
(6,339
)
 
(6,824
)
 
(13,311
)
 
(13,009
)
Other expense
124

 
260

 
149

 
49

Income tax benefit (expense)
(1,961
)
 
506

 
(12,307
)
 
(10,605
)
Net income (loss)
$
4,440

 
$
(886
)
 
$
23,703

 
$
18,612



49



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

Revenue (in thousands)
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
Residential:
 
 
 
 
 
 
 
Colorado
$
10,749

 
$
10,597

 
$
33,735

 
$
33,449

Nebraska
20,663

 
16,676

 
79,062

 
73,770

Iowa
18,593

 
14,896

 
66,024

 
63,575

Kansas
10,568

 
10,585

 
38,521

 
43,929

Total Residential
60,573

 
52,754

 
217,342

 
214,723

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Colorado
2,182

 
2,239

 
6,815

 
7,228

Nebraska
6,385

 
5,250

 
26,303

 
26,660

Iowa
7,802

 
6,224

 
28,685

 
29,013

Kansas
2,944

 
3,054

 
12,240

 
14,304

Total Commercial
19,313

 
16,767

 
74,043

 
77,205

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Colorado
583

 
249

 
698

 
293

Nebraska
163

 
636

 
336

 
2,141

Iowa
407

 
272

 
1,144

 
1,183

Kansas
6,849

 
3,548

 
7,969

 
4,335

Total Industrial
8,002

 
4,705

 
10,147

 
7,952

 
 
 
 
 
 
 
 
Transportation:
 
 
 
 
 
 
 
Colorado
179

 
170

 
507

 
451

Nebraska
2,072

 
1,924

 
6,431

 
6,573

Iowa
827

 
758

 
2,152

 
1,958

Kansas
1,125

 
1,046

 
3,192

 
2,984

Total Transportation
4,203

 
3,898

 
12,282

 
11,966

 
 
 
 
 
 
 
 
Other:
 
 
 
 
 
 
 
Colorado
25

 
29

 
56

 
56

Nebraska
511

 
484

 
1,119

 
1,096

Iowa
193

 
138

 
319

 
582

Kansas
778

 
952

 
1,322

 
1,602

Total Other
1,507

 
1,603

 
2,816

 
3,336

 
 
 
 
 
 
 
 
Total Regulated
93,598

 
79,727

 
316,630

 
315,182

 
 
 
 
 
 
 
 
Other - non-regulated Services
6,324

 
7,388

 
13,558

 
15,103

 
 
 
 
 
 
 
 
Total Revenue
$
99,922

 
$
87,115

 
$
330,188

 
$
330,285




50



Gross Margin (in thousands)
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
Residential:
 
 
 
 
 
 
 
Colorado
$
3,760

 
$
3,965

 
$
9,880

 
$
10,555

Nebraska
10,464

 
9,714

 
29,381

 
26,050

Iowa
10,313

 
8,620

 
26,594

 
24,075

Kansas
6,120

 
6,075

 
16,198

 
16,292

Total Residential
30,657

 
28,374

 
82,053

 
76,972

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Colorado
613

 
693

 
1,645

 
1,910

Nebraska
2,136

 
2,039

 
6,976

 
7,178

Iowa
2,433

 
2,016

 
6,596

 
6,629

Kansas
1,189

 
1,200

 
3,725

 
3,780

Total Commercial
6,371

 
5,948

 
18,942

 
19,497

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Colorado
127

 
68

 
163

 
91

Nebraska
41

 
71

 
91

 
234

Iowa
48

 
33

 
138

 
118

Kansas
761

 
480

 
992

 
663

Total Industrial
977

 
652

 
1,384

 
1,106

 
 
 
 
 
 
 
 
Transportation:
 
 
 
 
 
 
 
Colorado
178

 
170

 
506

 
451

Nebraska
2,072

 
1,924

 
6,431

 
6,573

Iowa
827

 
758

 
2,152

 
1,958

Kansas
1,125

 
1,046

 
3,192

 
2,997

Total Transportation
4,202

 
3,898

 
12,281

 
11,979

 
 
 
 
 
 
 
 
Other:
 
 
 
 
 
 
 
Colorado
25

 
29

 
56

 
56

Nebraska
511

 
483

 
1,119

 
1,095

Iowa
193

 
139

 
319

 
583

Kansas
706

 
880

 
1,017

 
1,143

Total Other
1,435

 
1,531

 
2,511

 
2,877

 
 
 
 
 
 
 
 
Total Regulated
43,642

 
40,403

 
117,171

 
112,431

 
 
 
 
 
 
 
 
Other - non-regulated Services
3,170

 
3,634

 
6,778

 
7,331

 
 
 
 
 
 
 
 
Total Gross Margin
$
46,812

 
$
44,037

 
$
123,949

 
$
119,762



51




Volumes Sold (in Dth)
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
Residential:
 
 
 
 
 
 
 
Colorado
1,127,379

 
1,150,169

 
3,847,384

 
3,971,016

Nebraska
1,772,388

 
1,384,365

 
7,842,625

 
7,720,752

Iowa
1,607,488

 
1,200,114

 
6,920,778

 
6,594,008

Kansas
818,677

 
836,716

 
4,249,556

 
4,405,333

Total Residential
5,325,932

 
4,571,364

 
22,860,343

 
22,691,109

 
 
 
 
 
 
 
 
Commercial:
 
 
 
 
 
 
 
Colorado
253,822

 
269,435

 
835,518

 
924,808

Nebraska
748,867

 
652,800

 
3,091,977

 
3,197,924

Iowa
1,042,988

 
799,463

 
3,888,734

 
3,707,567

Kansas
324,680

 
343,704

 
1,627,611

 
1,688,852

Total Commercial
2,370,357

 
2,065,402

 
9,443,840

 
9,519,151

 
 
 
 
 
 
 
 
Industrial:
 
 
 
 
 
 
 
Colorado
99,708

 
45,902

 
115,322

 
49,656

Nebraska
22,946

 
117,670

 
36,194

 
337,640

Iowa
68,662

 
46,235

 
178,463

 
177,501

Kansas
1,312,270

 
706,933

 
1,508,598

 
817,557

Total Industrial
1,503,586

 
916,740

 
1,838,577

 
1,382,354

 
 
 
 
 
 
 
 
Transportation:
 
 
 
 
 
 
 
Colorado
183,494

 
176,676

 
528,665

 
475,219

Nebraska
6,688,435

 
5,558,285

 
12,636,481

 
13,548,913

Iowa
4,026,034

 
3,944,164

 
9,579,099

 
9,256,912

Kansas
2,940,539

 
3,092,475

 
7,380,809

 
7,302,303

Total Transportation
13,838,502

 
12,771,600

 
30,125,054

 
30,583,347

 
 
 
 
 
 
 
 
Other:
 
 
 
 
 
 
 
Colorado

 

 

 

Nebraska

 
173

 

 
1,149

Iowa

 
10,232

 

 
52,529

Kansas
17,081

 
11,844

 
62,066

 
70,853

Total Other
17,081

 
22,249

 
62,066

 
124,531

 
 
 
 
 
 
 
 
Total Volumes Sold
23,055,458

 
20,347,355

 
64,329,880

 
64,300,492





52



 
Three Months Ended June 30, 2011
 
Six Months Ended June 30, 2011
Heating Degree Days:
Actual
 
Variance
From
 Normal
 
Actual
 
Variance
From
 Normal
Colorado
840

 
(11
)%
 
3,601

 
(6
)%
Nebraska
585

 
2
 %
 
3,866

 
2
 %
Iowa
851

 
7
 %
 
4,545

 
1
 %
Kansas*
406

 
(10
)%
 
3,031

 
1
 %
Combined Gas Utilities Heating Degree Days
660

 
 %
 
3,872

 
 %

 
Three Months Ended June 30, 2010
 
Six Months Ended June 30, 2010
Heating Degree Days:
Actual
 
Variance
From
 Normal
 
Actual
 
Variance
From
 Normal
Colorado
856

 
(9.7
)%
 
3,693

 
(3.0
)%
Nebraska
495

 
(13.3
)%
 
3,867

 
3.0
 %
Iowa
556

 
(29.9
)%
 
4,081

 
(8.0
)%
Kansas*
427

 
(4.9
)%
 
3,118

 
4.0
 %
Combined Gas Utilities Heating Degree Days
544

 
(17.0
)%
 
3,747

 
(1.0
)%
_______________
*    Kansas Gas has a 30-year weather normalization adjustment mechanism in place that neutralizes the impact of weather on revenues at Kansas Gas.

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

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010. Net income for the Gas Utilities segment was $4.4 million for the three months ended June 30, 2011 compared to Net loss of $0.9 million for the three months ended June 30, 2010 as a result of:

Gross margin increased $2.8 million primarily due to recently approved rate adjustments and cooler weather than in the same period in the prior year.

Operations and maintenance decreased $3.8 million primarily due to lower property tax expense including an $0.8 million credit from a recent settlement on assessments from prior tax years, overall efficiencies and lower allocation of corporate costs.

Depreciation and amortization decreased $0.8 million primarily due to a shift in corporate allocations as a result of higher asset deployment at the Electric Utilities.

Interest expense, net decreased $0.5 million primarily due to increased interest income on intercompany lending.

Other expense was comparable to the same period in the prior year.

Income tax benefit (expense): The effective tax rate decreased for the three months ended June 30, 2011 was impacted by a favorable adjustment related to a state net operating loss true-up.



53



Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010. Net income for the Gas Utilities segment was $23.7 million for the six months ended June 30, 2011 compared to Net income of $18.6 million for the six months ended June 30, 2010 as a result of:

Gross margin increased $4.2 million primarily due to recently approved rate adjustments and cooler weather than in the same period in the prior year.

Operations and maintenance decreased $3.6 million primarily due to lower property tax expense including an $0.8 million credit from a recent settlement on assessment from prior tax years, and allocation of corporate costs.

Gain on sale of operating assets represents assets sold by Nebraska Gas to the City of Omaha, Nebraska after a portion of Nebraska Gas' service territory was annexed by the City.

Depreciation and amortization decreased $1.9 million primarily due to a shift in corporate allocations as a result of higher asset deployment at the Electric Utilities.

Interest expense, net was comparable to the same period in the prior year.

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

Income tax expense: The effective tax rate for the six months ended June 30, 2011 was comparable to the same period in the prior year.

Regulatory Matters — Utilities Group

The following summarizes our recent state and federal rate case and surcharge activity (dollars in millions):                         
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Approved Capital
Structure
 
 
Type of
 Service
 
Date
Requested
 
Date
Effective
 
Amount
Requested
 
Amount
Approved
 
Return on
Equity
 
Equity
 
Debt
Nebraska Gas (1)
 
Gas
 
12/2009
 
9/2010
 
$
12.1

 
$
8.3

 
10.1
%
 
52.0
%
 
48.0
%
Iowa Gas (2)
 
Gas
 
6/2010
 
6/2010
 
$
4.7

 
$
3.4

 
Global Settlement
 
Global Settlement
 
Global Settlement
Black Hills Power (3)
 
Electric
 
9/2009
 
4/2010
 
$
32.0

 
$
15.2

 
Global Settlement
 
Global Settlement
 
Global Settlement
Black Hills Power (3)
 
Electric
 
10/2009
 
6/2010
 
$
3.8

 
$
3.1

 
10.5
%
 
52.0
%
 
48.0
%
Black Hills Power (4)
 
Electric
 
1/2011
 
6/2010
 
Not Applicable
 
$
3.1

 
Not Applicable
 
Not Applicable
 
Not Applicable
Colorado Electric (5)
 
Electric
 
1/2010
 
8/2010
 
$
22.9

 
$
17.9

 
10.5
%
 
52.0
%
 
48.0
%
Colorado Electric (6)
 
Electric
 
4/2011
 
Pending
 
$
40.2

 
Pending

 
Pending

 
Pending

 
Pending


(1)
In December 2009, Nebraska Gas filed a rate case with the NPSC and interim rates went into effect on March 1, 2010. In August 2010 NPSC issued a decision approving an annual revenue increase of approximately $8.3 million effective on September 1, 2010. A refund to customers for the difference between interim rates and approved rates was completed in the first quarter of 2011. The Nebraska Public Advocate has filed appeals which have been denied. The Public Advocate currently has a filed notice of appeal with the Court of Appeals.

(2)
In June 2010, Iowa Gas filed a request with the IUB for a $4.7 million, or 2.9%, revenue increase to recover the cost of capital investments we made in our gas distribution system and other expense increases incurred since December 2008. Interim rates, subject to refund, equal to a $2.6 million increase, or 1.6%, in revenues went into effect on June 18, 2010. In August 2010, we reached a settlement with the OCA for a revenue increase of $3.4 million and hearings on the settlement were held in October 2010. Approval from the IUB of a modified settlement for a revenue increase of $3.4 million was received in February 2011.


(3)     This rate case was previously described in our 2010 Annual Report filed on Form 10-K.

54




(4)     In January 2011, Black Hills Power filed a request with the SDPUC for approval of an Environmental Improvement Adjustment tariff pursuant to state legislation for tariff mechanisms to recover eligible investments and expenses related to new environmental measures. In May 2011, the SDPUC approved an Environmental Improvement Cost Recovery Adjustment tariff for Black Hills Power. This tariff, which was implemented to recover Black Hill Power's investment of $25 million for pollution control equipment at the PacifiCorp operated Wyodak plant, went into effect June 1, 2011 with an annual revenue increase of $3.1 million.
   
(5)    On January 5, 2010, Colorado Electric filed a rate case with CPUC requesting an electric revenue increase primarily related to the recovery of rising costs from electricity supply contracts, as well as recovery for investment in equipment and electricity distribution facilities necessary to maintain and strengthen the reliability of the electric delivery system. Colorado Electric requested a $22.9 million, or approximately 12.8%, increase in annual revenue. In August 2010, the CPUC approved a settlement agreement for $17.9 million in annual revenue with a return on equity of 10.5% and a capital structure of 52% equity and 48% debt. New rates were effective August 6, 2010.

Included in the rate case order was a provision that off-system sales margins be shared with customers commencing August 6, 2010.  The percentage of margin to be shared with the customers was not resolved at the time of the rate case settlement.  The CPUC has therefore required that the off-system operating income earned beginning August 6, 2010 be deferred on the balance sheet until settlement of the sharing mechanism.  Since August 2010, $1.1 million in off-system operating income has been deferred. The determination for a sharing mechanism is now being considered as part of the rate case filed with the CPUC by Colorado Electric discussed below.

(6)     On April 28, 2011, Colorado Electric filed a request with the CPUC for an annual revenue increase of $40.2 million, or 18.8%, to recover costs and a return on capital associated with the 180 MW generating facilities currently under construction, associated infrastructure assets and other utility expenses, including the PPA with Colorado IPP. The facilities are expected to be in operation by the end of 2011. A hearing on the rate case with the CPUC has been scheduled for late October 2011.


Non-regulated Energy Group

We report four segments within our Non-regulated Group: Oil and Gas, Coal Mining, Energy Marketing and Power Generation. An analysis of results from our Non-regulated Energy Group's operating segments follows:

Oil and Gas

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
 
(in thousands)
Revenue
$
18,838

 
$
18,658

 
$
36,744

 
$
38,401

 
 
 
 
 
 
 
 
Operations and maintenance
10,187

 
10,499

 
20,754

 
20,233

Depreciation, depletion and amortization
7,602

 
6,842

 
14,923

 
12,953

Total operating expenses
17,789

 
17,341

 
35,677

 
33,186

 
 
 
 
 
 
 
 
Operating income (loss)
1,049

 
1,317

 
1,067

 
5,215

 
 
 
 
 
 
 
 
Interest expense
(1,389
)
 
(1,391
)
 
(2,772
)
 
(2,173
)
Other income
88

 
239

 
(97
)
 
542

Income tax (expense) benefit
173

 
56

 
1,008

 
(1,015
)
 
 
 
 
 
 
 
 
Net income (loss)
$
(79
)
 
$
221

 
$
(794
)
 
$
2,569



55



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

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
Fuel production:
 
 
 
 
 
 
 
Bbls of oil sold
100,901

 
84,427

 
204,451

 
168,818

Mcf of natural gas sold
2,247,381

 
2,356,674

 
4,382,039

 
4,508,850

Mcf equivalent sales
2,852,787

 
2,863,236

 
5,608,745

 
5,521,758


 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
Average price received: (a)
 
 
 
 
 
 
 
Gas/Mcf (b)
$
4.29

 
$
4.85

 
$
4.47

 
$
5.36

Oil/Bbl
$
79.53

 
$
89.98

 
$
73.10

 
$
82.19

 
 
 
 
 
 
 
 
Depletion expense/Mcfe
$
2.40

 
$
2.15

 
$
2.38

 
$
2.08

____________
(a)
Net of hedge settlement gains and losses
(b)
Exclusive of natural gas liquids

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

 
Three Months Ended June 30, 2011
 
Three Months Ended June 30, 2010
 
LOE
Gathering,
 Compression
 and Processing
Production Taxes
Total
 
LOE
Gathering,
 Compression
and Processing
Production Taxes
Total
San Juan
$
1.21

$
0.35

$
0.55

$
2.11

 
$
1.32

$
0.31

$
0.54

$
2.17

Piceance
0.83

0.76

(0.36
)
1.23

 
0.38

0.62

0.27

1.27

Powder River
1.42


1.38

2.80

 
1.00


1.02

2.02

Williston
0.50


1.48

1.98

 
2.42


1.70

4.12

All other properties
1.23


0.04

1.27

 
0.95


0.34

1.29

Total weighted average
$
1.15

$
0.23

$
0.63

$
2.01

 
$
1.09

$
0.20

$
0.60

$
1.89


 
Six Months Ended June 30, 2011
 
Six Months Ended June 30, 2010
 
LOE
Gathering,
 Compression
 and Processing
Production Taxes
Total
 
LOE
Gathering,
 Compression
and Processing
Production Taxes
Total
San Juan
$
1.23

$
0.41

$
0.55

$
2.19

 
$
1.36

$
0.34

$
0.63

$
2.33

Piceance
0.76

0.78

(0.06
)
1.48

 
0.45

0.72

0.32

1.49

Powder River
1.36


1.33

2.69

 
1.17


1.07

2.24

Williston
0.38


1.49

1.87

 
1.51


1.28

2.79

All other properties
1.43


0.21

1.64

 
1.07


0.25

1.32

Total weighted average
$
1.17

$
0.25

$
0.68

$
2.10

 
$
1.17

$
0.22

$
0.63

$
2.02



56



Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010. Net loss for the Oil and Gas segment was $0.1 million for the three months ended June 30, 2011 compared to Net income of $0.2 million for the same period in 2010 as a result of:

Revenue increased $0.2 million primarily due to a 20% increase in oil volumes largely related to production in our ongoing Bakken drilling program in North Dakota, partially offset by a 12% lower average hedged oil price received. The decrease in crude oil price was influenced by fixed price swaps previously entered into at prices significantly below current oil market prices. Natural gas volumes, exclusive of gas liquids, were 4% lower than the prior period and the natural gas average hedged price decreased 12%.

Operations and maintenance costs were comparable to the same period in the prior year.

Depreciation, depletion and amortization increased $0.8 million primarily due to a higher depletion rate, resulting primarily from higher finding and development costs on a per Mcfe basis for our Bakken oil drilling program.

Interest expense, net was comparable to the same period in the prior year.

Other income decreased due to lower earnings from equity investments.

Income tax (expense) benefit: The effective tax rate in the second quarter of 2011 was impacted by the tax benefit generated by percentage depletion.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010. Net loss for the Oil and Gas segment was $0.8 million for the six months ended June 30, 2011 compared to a Net income of $2.6 million for the same period in 2010 as a result of:

Revenue decreased $1.7 million due to a 17% decrease in the average hedged price of natural gas and an 11% decrease in the average hedged price of oil, as well as a 3% decline in gas volumes, exclusive of gas liquids, partially offset by a 21% increase in oil volumes. The decrease in average crude oil prices was influenced by fixed price swaps previously entered into at prices significantly below current market prices. The increase in oil volumes was favorably impacted by volumes at new wells in our ongoing Bakken drilling program in North Dakota.

Operations and maintenance costs were comparable to the same period in the prior year.

Depreciation, depletion and amortization increased $2.0 million primarily due to a higher depletion rate, resulting primarily from higher finding and development costs on a per Mcfe basis for our Bakken oil drilling program.

Interest expense increased $0.6 million primarily due to higher interest rates.

Other income decreased $0.6 million due to lower earnings from equity investments.

Income tax (expense) benefit: The effective tax rate for the six months ended June 30, 2011 was positively impacted by a $0.3 million credit for research and development credits.


57



Coal Mining

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
 
(in thousands)
Revenue
$
15,540

 
$
15,049

 
$
31,035

 
$
29,029

 
 
 
 
 
 
 
 
Operations and maintenance
13,011

 
9,050

 
27,583

 
19,291

Depreciation, depletion and amortization
4,595

 
3,321

 
9,213

 
6,211

Total operating expenses
17,606

 
12,371

 
36,796

 
25,502

 
 
 
 
 
 
 
 
Operating income
(2,066
)
 
2,678

 
(5,761
)
 
3,527

 
 
 
 
 
 
 
 
Interest income, net
936

 
787

 
1,896

 
1,105

Other income
549

 
527

 
1,118

 
1,083

Income tax benefit (expense)
200

 
(918
)
 
1,068

 
(1,295
)
 
 
 
 
 
 
 
 
Net income (loss)
$
(381
)
 
$
3,074

 
$
(1,679
)
 
$
4,420


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

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
Tons of coal sold
1,235

 
1,459

 
2,605

 
2,851

Cubic yards of overburden moved
2,933

 
3,752

 
6,388

 
7,323


Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010. Net loss for the Coal Mining segment was $0.4 million for the three months ended June 30, 2011 compared to Net income of $3.1 million for the same period in 2010, as a result of:

Revenue increased $0.5 million primarily due to a 22% increase in average sales price per ton. The higher average sales price reflects the impact of price escalators and adjustments in certain of our sales contracts where we are able to pass a portion of higher mining costs to our customers. Approximately 40% of our coal production is sold under these regulated sales contracts where the sales price escalates based on actual mining cost increases. Most of our remaining production is sold under contracts where the sales price may escalate with published indices, which may not necessarily represent changes in actual mining costs. Revenue was also impacted during the current quarter by 15% lower volumes, primarily due to customer plant outages, plant closures and weather conditions which restricted our ability to mine coal.

Operations and maintenance increased $4.0 million which reflects the current phase of our mine where we have longer haul distances and higher stripping costs. Additionally, we experienced higher costs associated with drilling and blasting, equipment maintenance, fuel, staffing levels for our train load-out facility and weather conditions. As noted above, over half of our production is sold under contracts that have price escalators based on published indices. These escalators have not kept up with actual mining cost increases, reducing coal mine operating income, and are expected to continue to negatively impact 2011 results. Previous periods also include the capitalization of certain costs associated with mine infrastructure, including our in-pit conveyor system that is used to transport coal to mine-mouth generation facilities.

Depreciation, depletion and amortization increased $1.3 million primarily due to higher depreciation on reclamation related costs and mining equipment.

Interest income, net was comparable to the same period in the prior year.

Other income was comparable to the same period in the prior year.
 

58



Income tax benefit (expense): The effective tax rate for the three months ended June 30, 2010 was impacted by a tax benefit generated by percentage depletion.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010. Net loss for the Coal Mining segment was $1.7 million for the six months ended June 30, 2011 compared to Net income of $4.4 million for the same period in 2010 as a result of:

Revenue increased $2.0 million primarily due to a 17% increase in average sales price received per ton. The higher average sales price reflects the impact of price escalators and adjustments in certain of our sales contracts where we are able to pass a portion of higher mining costs to our customers. Approximately 40% of our coal production is sold under these regulated sales contracts where the sales price escalates based on actual mining cost increases. Most of our remaining production is sold under contracts where the sales price may escalate with published indices, which may not necessarily represent changes in actual mining costs. The increase in price received per ton during the quarter was partially offset by 9% lower volumes primarily due to customer plant outages, plant closures, and weather conditions which restricted our ability to mine coal.

Operations and maintenance costs increased $8.3 million which reflects the current phase of our mine where we have longer haul distances and higher overburden stripping costs. Additionally, we experienced higher costs associated with drilling and blasting, equipment maintenance, fuel, and staffing levels for our train load-out facility. As noted above, over half of our production is sold under contracts that have price escalators based on published indices. These escalators have not kept up with actual mining cost increases, reducing coal mine operating income, which is expected to continue to negatively impact 2011 results. Previous periods also include the capitalization of certain costs associated with mine infrastructure, including our in-pit conveyor system that is used to transport coal to mine-mouth generation facilities.

Depreciation, depletion and amortization increased $3.0 million primarily related to reclamation costs and increased depreciation on equipment.

Interest income, net increased $0.8 million primarily due to increased lending to affiliates and higher interest rates earned.

Other income was comparable to the same period in the prior year.

Income tax benefit (expense): Income tax benefit (expense) reflects lower pre-tax earnings and a higher effective income tax rate, which for the period ended June 30, 2010 was favorably impacted by a tax benefit generated by percentage depletion.

Energy Marketing

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
 
(in thousands)
Gross margin —
 
 
 
 
 
 
 
Realized gross margin
$
1,193

 
$
2,645

 
$
6,450

 
$
14,698

Unrealized gross margin
11,283

 
6,250

 
8,491

 
3,969

Total gross margin
12,476

 
8,895

 
14,941

 
18,667

 
 
 
 
 
 
 
 
Operating expenses
6,574

 
6,032

 
12,331

 
11,458

Depreciation and amortization
144

 
127

 
283

 
259

Total operating expenses
6,718

 
6,159

 
12,614

 
11,717

 
 
 
 
 
 
 
 
Operating income
5,758

 
2,736

 
2,327

 
6,950

 
 
 
 
 
 
 
 
Interest expense, net
(205
)
 
(800
)
 
(657
)
 
(1,562
)
Other income (expense)
3

 
184

 
2

 
153

Income tax (expense) benefit
(1,861
)
 
(793
)
 
(618
)
 
(2,021
)
 
 
 
 
 
 
 
 
Net income (loss)
$
3,695

 
$
1,327

 
$
1,054

 
$
3,520



59



Gross margin by commodity (in thousands):

 
Three Months Ended
 
 
Natural Gas
Crude Oil
Coal (a)
Power (a)
Environmental (a)
Total
June 30, 2011
 
 
 
 
 
 
Realized
$
(1,378
)
$
2,277

$
530

$
(236
)
$

$
1,193

Unrealized
4,739

1,857

1,714

2,854

119

11,283

Total
$
3,361

$
4,134

$
2,244

$
2,618

$
119

$
12,476

 
 
 
 
 
 
 
June 30, 2010
 
 
 
 
 
 
Realized
$
2,046

$
1,042

$
(443
)
$

$

$
2,645

Unrealized
44

2041

4,165



6,250

Total
$
2,090

$
3,083

$
3,722

$

$

$
8,895


 
Six Months Ended
 
 
Natural Gas
Crude Oil
Coal (a)
Power (a)
Environmental (a)
Total
June 30, 2011
 
 
 
 
 
 
Realized
$
3,910

$
2,535

$
1,606

$
(1,601
)
$

$
6,450

Unrealized
1,262

(124
)
3,363

3,871

119

8,491

Total
$
5,172

$
2,411

$
4,969

$
2,270

$
119

$
14,941

 
 
 
 
 
 
 
June 30, 2010
 
 
 
 
 
 
Realized
$
12,567

$
2,574

$
(443
)
$

$

$
14,698

Unrealized
(960
)
764

4,165



3,969

Total
$
11,607

$
3,338

$
3,722

$

$

$
18,667

_____________________
(a)    Coal marketing activity began June 1, 2010, Power marketing began late in the third quarter of 2010, and Environmental marketing which began late in the third quarter of 2010 with no activity until second quarter of 2011.

Following is a summary of average daily quantities marketed:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
Natural gas physical sales — MMBtus
1,524,897

 
1,348,887

 
1,626,973

 
1,549,913

Crude oil physical sales — Bbls
23,257

 
20,935

 
22,255

 
17,203

Coal physical sales — Tons(a)
33,693

 
27,972

 
35,105

 
27,972

Power - MWh (a)
104

 

 
52

 

______________
(a)    Coal marketing activity began June 1, 2010 and Power marketing began late in the third quarter of 2010.

Natural gas, crude oil and coal inventory held by Energy Marketing primarily consists of gas held in storage. Such gas is being held in inventory to capture the price differential between the time at which it was purchased and a subsequent sales date. Quantities held were as follows:

 
As of June 30, 2011
As of December 31, 2010
As of June 30, 2010
Natural gas (MMBtu)
6,257,284

14,922,353

16,289,903

Crude oil (Bbl)
154,998

198,052

118,000

Coal (Ton)
46,700

1,529




60



Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010. Net income for the Energy Marketing segment was $3.7 million for the three months ended June 30, 2011 compared to a Net income of $1.3 million for the same period in 2010 as a result of:

Gross margin increased $3.6 million primarily due to higher unrealized marketing margins of $5.0 million. This increase was driven by timing of natural gas settlements of $4.7 million and increased margins of $2.9 million from the Company’s portfolio of power marketing contracts partially offset by decreased unrealized margins from the coal portfolio of $2.5 million. The unrealized marketing gains were partially offset by lower realized marketing margins of $1.5 million. A less favorable natural gas market contributed to this variance. Natural gas volumes marketed increased 13%, crude oil volumes marketed increased 11% and coal marketing volumes increased 20%.

Operating expenses increased $0.5 million primarily due to higher compensation and benefit expenses relating to additional staff marketing new commodities and new geographic regions and a higher provision for compensation related to increased margins.

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

Interest expense, net decreased $0.6 million primarily due to changes in affiliate borrowings and decreased costs related to the committed Enserco Credit Facility.

Other income was comparable to the same period in the prior year.

Income tax (expense) benefit: The effective income tax rate for the three months ended June 30, 2011 was comparable to the same period in the prior year.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010. Net income for the Energy Marketing segment was $1.1 million for the six months ended June 30, 2011 compared to a Net income of $3.5 million for the same period in 2010 as a result of:

Gross margin decreased $3.7 million primarily driven by lower realized marketing margins of $8.2 million partially offset by an increase of $4.5 million in unrealized marketing margins. The decrease in realized marketing margins primarily reflected lower natural gas margins. Unrealized marketing gains include margins from power marketing activities of $3.9 million, which began in September, 2010 and unrealized gains of $2.2 million from natural gas partially offset by lower margins from crude oil and coal.

Operating expenses increased $0.9 million primarily due to higher compensation and benefit expenses relating to additional staff marketing new commodities and new geographic regions.

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

Interest expense, net decreased $0.9 million primarily due to changes in affiliate borrowings and decreased costs related to the committed Enserco Credit Facility.

Other income was comparable to the same period in the prior year.

Income tax (expense) benefit: The effective tax rate for the six months ended June 30, 2011 was comparable to the six months ended June 30, 2010.


61



Power Generation

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
 
2010
 
2011
 
2010
 
(in thousands)
Revenue
$
7,780

 
$
6,679

 
$
15,400

 
$
14,747

 
 
 
 
 
 
 
 
Operating, general and administrative costs
4,091

 
5,191

 
8,279

 
8,565

Depreciation and amortization
1,040

 
1,298

 
2,104

 
2,326

Gain on sale of operating asset

 

 

 

Total operating expense (income)
5,131

 
6,489

 
10,383

 
10,891

 
 
 
 
 
 
 
 
Operating income
2,649

 
190

 
5,017

 
3,856

 
 
 
 
 
 
 
 
Interest expense, net
(1,835
)
 
(1,986
)
 
(3,626
)
 
(3,983
)
Other (expense) income
21

 
1,171

 
1,225

 
1,160

Income tax (expense) benefit
(287
)
 
209

 
(882
)
 
(369
)
 
 
 
 
 
 
 
 
Net income (loss)
$
548

 
$
(416
)
 
$
1,734

 
$
664


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

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2011
2010
 
2011
2010
Contracted power plant fleet availability:
 
 
 
 
 
Coal-fired plant
99.5
%
98.9
%
 
99.8
%
99.5
%
Natural gas-fired plants
100.0
%
100.0
%
 
100.0
%
100.0
%
Total availability
99.7
%
99.3
%
 
99.8
%
99.7
%
________________
In January 2011, we sold our ownership interests in the partnerships which own the Idaho facilities.

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010. Net income for the Power Generation segment was $0.5 million for the three months ended June 30, 2011 compared to Net loss of $0.4 million for the same period in 2010 as a result of:

Revenue increased $1.1 million primarily due to increased sales from Wygen I, which incurred a forced outages and a major overhaul in the same period in the prior year.

Operations and maintenance decreased $1.1 million primarily as costs were incurred in the same period in the prior year related to the forced outage and major overhaul of Wygen I.

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

Interest expense, net was comparable to the same period in the prior year.

Other (expense) income decreased $1.2 million due to lower earnings from our partnership investments.

Income tax (expense) benefit: The effective tax rate for the three months ended June 30, 2011 was comparable to the same period in the prior year.


62



Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010. Net income for the Power Generation segment was $1.7 million for the six months ended June 30, 2011 compared to $0.7 million for the same period in 2010 as a result of:

Revenue increased $0.7 million primarily due to increased sales from Wygen I, which incurred a forced outages and a major overhaul in the same period in the prior year.

Operations and maintenance decreased $0.3 million primarily as higher costs were incurred in the same period in the prior year related to the forced outage and major overhaul of Wygen I.

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

Interest expense, net was comparable to the same period in the prior year.

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

Income tax expense: The effective tax rate for the six months ended June 30, 2011 was comparable to the same period in the prior year.


Corporate

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010. Net loss for Corporate was
$9.1 million for the three months ended June 30, 2011 compared to Net loss of $19.2 million for the three months ended June 30, 2010 as a result of an unrealized net, non-cash mark-to-market loss for the quarter ended June 30, 2011 of approximately $7.8 million on certain interest rate swaps compared to a $24.9 million unrealized mark-to-market non-cash loss on these interest rate swaps in the prior year.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010. Net loss for Corporate was $8.2 million compared to Net loss of $24.1 million as a result of an unrealized net, mark-to-market losses for the six months ended June 30, 2011 of approximately $2.4 million on certain interest rate swaps compared to a $28.0 million unrealized mark-to-market non-cash loss on these interest rate swaps in the prior year.


Critical Accounting Policies

There have been no material changes in our critical accounting policies from those reported in our 2010 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 2010 Annual Report on Form 10-K.

Liquidity and Capital Resources

Cash Flow Activities

The following table summarizes our cash flows for the six months ended June 30, 2011 and 2010 (in thousands):

Cash provided by (used in):
2011
2010
Operating activities
$
182,017

$
143,990

Investing activities
$
(225,064
)
$
(163,021
)
Financing activities
$
98,682

$
(29,837
)


63



2011 Compared to 2010

Operating Activities

Net cash provided by operating activities was $38.0 million higher for the six months ended June 30, 2011than in the same period in 2010 primarily attributable to:

Cash earnings (net income plus non-cash adjustments) were $28.1 million higher for the six months ended June 30, 2011 than for the same period the prior year.

Net inflows from operating assets and liabilities were $52.9 million for the six months ended June 30, 2011, which is an increase of $18.3 million from the same period in the prior year as a result of:

Net inflows from working capital accounts were $9.3 million for the six months ended June 30, 2011, which is a decrease of $14.7 million from the prior year net inflows from working capital accounts. In addition to normal working capital changes and seasonality of our gas utility operations, 2011 reflects increased cash inflows from higher withdrawals of gas storage inventories by Energy Marketing. Energy Marketing also experienced higher outflows in the current period related to higher margin posted on marketing transactions; and

Inflows from changes in regulatory assets and regulatory liabilities, primarily related to collection of gas costs by our Gas Utilities.

Investing Activities

Net cash used in investing activities was $62.0 million more for the six months ended June 30, 2011 than in the same period in 2010 reflecting higher capital additions. During 2011, cash outflows for property, plant and equipment additions totaled $225.9 million, including the partial completion of construction of 180 MW of natural gas-fired electric generation at Colorado Electric and 200 MW of natural gas-fired electric generation at Black Hills Colorado IPP, and oil and gas property maintenance capital and development drilling.

Financing Activities

Net cash provided by financing activities was $128.5 million more for the six months ended June 30, 2011 than in the same period in 2010 primarily due to increased borrowings to finance our construction program. During the six months ended June 30, 2011, we borrowed an additional $150 million on a new corporate term loan which was used to pay down a portion of our Revolving Credit Facility, paid $4.1 million of long-term debt primarily related to required payments on the Black Hills Wyoming Project Financing, and paid $29.5 million of cash dividends on common stock.


Dividends

Dividends paid on our common stock totaled $29.5 million for the six months ended June 30, 2011, or $0.73 per share. On July 27, 2011, our Board of Directors declared an additional quarterly dividend of $0.365 per share payable September 1, 2011, which is equivalent to an annual dividend rate of $1.46 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 credit facilities and our future business prospects.

Financing Transactions and Short-Term Liquidity

Our principal sources of short-term liquidity are our Revolving Credit Facility and cash provided by operations. In addition to availability under our Revolving Credit Facility described below, as of June 30, 2011, we had approximately $88 million of cash unrestricted for operations.


64



Revolving Credit Facility

Our $500 million Revolving Credit Facility expiring April 14, 2013 can be used for the issuance of letters of credit, to fund working capital needs and for general corporate purposes. Borrowings are available under a base rate option or a Eurodollar option. The cost of borrowings or letters of credit is determined based upon our credit ratings. At current ratings levels, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 1.75%, 2.75% and 2.75%, respectively. The facility contains a commitment fee to be charged on the unused amount of the Facility. Based upon current credit ratings, the fee is 0.5%. The facility contains an accordion feature which allows us, with the consent of the administrative agent, to increase the capacity of the facility to $600 million.

At June 30, 2011, we had borrowings of $130 million and letters of credit outstanding of $43 million on our Revolving Credit Facility. Available capacity remaining on our Revolving Credit Facility was approximately $327.0 million at June 30, 2011.

Our consolidated net worth was $1,108.1 million at June 30, 2011, which was approximately $231.5 million in excess of the net worth we were required to maintain under the Revolving Credit Facility. At June 30, 2011, our long-term debt ratio was 51.6%, our total debt leverage ratio (long-term debt and short-term debt) was 58.6%, and our recourse leverage ratio was approximately 59.3%.

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 maintenance of certain financial covenants including a minimum consolidated net worth and a recourse leverage ratio not to exceed 0.65 to 1.00.

In addition to covenant violations, an event of default under the Revolving Credit Facility may be triggered by other events, such as a failure to make payments when due or a failure to make payments when due in respect of, or a failure to perform obligations relating to, other debt obligations of $35 million or more. Subject to applicable cure periods (none of which apply to a failure to timely pay indebtedness), an event of default would permit the lenders to restrict our ability to further access the credit facility for loans or new letters of credit, and could require both the immediate repayment of any outstanding principal and interest and the cash collateralization of outstanding letter of credit obligations.

Enserco Credit Facility

Enserco utilizes a two-year, $250 million committed credit facility which includes an accordion feature which allows us, with the consent of the administrative agent, to increase commitments under the facility to $350 million. Maximum borrowings under the facility are subject to a sublimit of $50 million. Borrowings under this facility are available under a base rate option or a Eurodollar option. Margins for base rate borrowings are 1.75% and for Eurodollar borrowings are 2.50%. Enserco was in compliance with its debt covenants as of June 30, 2011

At June 30, 2011, $118.7 million of letters of credit were issued under this facility and there were no cash borrowings outstanding.

Corporate Term Loans

In June 2011, we entered into a one-year $150 million unsecured, single draw, term loan with CoBank, the Bank of Nova Scotia and U.S. Bank due on June 24, 2012. The cost of borrowing under the loan is based on a spread of 125 basis points over LIBOR (1.44% at June 30, 2011). The covenants are substantially the same as those included in the Revolving Credit Facility and we were in compliance with these covenants as of June 30, 2011.

In December 2010, we entered into a one-year $100.0 million term loan with J.P. Morgan and Union Bank due in December 2011. The cost of borrowing under this Term Loan was based on a spread of 137.5 basis points over LIBOR (1.56% at June 30, 2011). The covenants are substantially the same as those included in the Revolving Credit Facility and we were in compliance with these covenants as of June 30, 2011.


65



Dividend Restrictions

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 shareholders is derived from these cash flows. As a result of certain statutory limitations or regulatory or financing agreements, we could have restrictions on the amount of distributions allowed to be made by our subsidiaries.

Our utility subsidiaries are generally 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 June 30, 2011, the restricted net assets at our Electric and Gas Utilities were approximately $207.3 million.

Our Enserco credit facility is a borrowing base credit facility, the structure of which requires certain levels of tangible net worth and net working capital to be maintained for a given borrowing base election level. In order to maintain a borrowing base election level, Enserco may be restricted from making dividend payments to the parent company. Enserco's restricted net assets at June 30, 2011 were $153.1 million compared to $93.0 million at December 31, 2010.

As a covenant of the Black Hills Wyoming project financing, Black Hills Non-regulated Holdings has restricted assets of $100 million. Black Hills Non-regulated Holdings is the parent of Black Hills Electric Generation which is the parent of Black Hills Wyoming.

Future Financing Plans

We have substantial capital expenditures in 2011, which are primarily due to the construction of additional utility and IPP generation to serve Colorado Electric. Our capital requirements are expected to be financed through a combination of operating cash flows, borrowings on our Revolving Credit Facility and long-term financings. We intend to settle the equity forward in the fourth quarter of 2011. We may complete an additional long-term senior unsecured debt financing at the holding company level in late 2011 or 2012. We intend to maintain a consolidated debt-to-capitalization level in the range of 50% to 55%; however, during the construction period of our new generation facilities in Colorado, we may exceed this level on a temporary basis.

Equity Forward

In November 2010, we entered into a Forward Agreement with J.P. Morgan in connection with a public offering of 4,000,000 shares of Black Hills Corporation common stock. Under the Forward Agreement on November 10, 2010, we agreed to issue to J.P. Morgan 4,000,000 shares of our common stock at an initial forward price of $28.70875 per share. On December 7, 2010, the underwriters exercised the over-allotment option to purchase an additional 413,519 shares under the same terms as the original Forward Agreement (together with the Forward Agreement, the "Forward Agreements").

Based on the closing Black Hills Corporation common stock price of $30.09 on June 30, 2011, and the forward price on that date for the equity forward of $27.92 and over-allotment shares of $27.92, the fair value net cash settlement of the 4,000,000 equity forward instrument and 413,519 over-allotment shares was approximately $10 million. The Forward Agreements require a 60 day notice prior to settlement for cash or net share settlements. Forward prices and volume-weighted average market prices for the period between when notice is provided and settlement are used to calculate cash and net share settlement amounts.

At June 30, 2011, the equity forward instrument could have been settled with physical delivery of 4,413,519 shares to J.P. Morgan in exchange for cash of $123.2 million. Assuming required notices were given and actions taken, the forward instruments could have also been net settled at June 30, 2011 with delivery of cash of approximately $9.6 million or approximately 331,000 shares of common stock to J.P. Morgan. We may settle the equity forward instrument at any time up to the maturity date of November 10, 2011. We may also unilaterally elect to cash or net share settle at any date up to maturity, for all or a portion of the equity forward shares. It is our intent to settle the equity forward with the physical delivery of shares in the fourth quarter of 2011.


66



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 income statement. For the three and six months ended June 30, 2011, respectively, we recorded a $7.8 million and $2.4 million pre-tax unrealized mark-to-market non-cash loss on the swaps. The mark-to-market value on these swaps was a liability of $56.3 million at June 30, 2011. 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 over the term of the swaps would have a pre-tax impact of approximately $0.3 million. These swaps hedge interest rate exposure for periods to 2018 and 2028 and have amended mandatory early termination dates ranging from December 15, 2011 to December 29, 2011. We have continued to maintain these swaps in anticipation of our upcoming financing needs, particularly as they relate to our planned capital requirements to build gas-fired power generation facilities to serve our Colorado Electric customers, and because of our upcoming holding company debt maturities, which are $225 million and $250 million in years 2013 and 2014, respectively. Alternatively, we may choose to cash settle these swaps at their fair value prior to their mandatory 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 termination dates.

In addition, we have $150 million notional amount floating-to-fixed interest rate swaps, having a maximum remaining term of 5.5 years. These swaps have been designated as cash flow hedges and accordingly, their mark-to-market adjustments are recorded in Accumulated other comprehensive loss on the accompanying Condensed Consolidated Balance Sheets. The mark-to-market value of these swaps was a liability of $22.7 million at June 30, 2011.

There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2010 Annual Report on Form 10-K filed with the SEC.

Energy Marketing Commodities

Our energy marketing segment uses derivative instruments, including options, swaps, futures, forwards and other contractual commitments for both non-trading (hedging) and trading purposes. These activities can have liquidity impacts which the Company monitors and manages in accordance with its Risk Management Policies and Procedures. The primary sources of liquidity for our Energy Marketing segment are: cash from operations, the stand-alone Enserco Credit Facility and advances of cash from the parent company.

In our Energy Marketing segment, our largest counterparties consist primarily of financial institutions and major energy companies.  This concentration of counterparties may materially impact our exposure to credit risk resulting from market, economic or regulatory conditions.  We seek to minimize credit risk through an evaluation of the counterparties financial condition and credit ratings and collateral requirements under certain circumstances, including the use of master netting agreements. We continuously monitor collections and payments from our counterparties.

The addition of the coal, environmental, and power marketing businesses has not and is not expected to result in a significant increase to the liquidity requirement of the marketing business in the near term.

Credit Ratings

Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements. As of June 30, 2011, our senior unsecured credit ratings, as assessed by the three major credit rating agencies, were as follows:

Rating Agency
Rating
Outlook
 
 
 
Fitch *
BBB-
Stable
Moody's
Baa3
Stable
S&P
BBB-
Stable


67



In addition, as of June 30, 2011, Black Hills Power's first mortgage bonds were rated as follows:

Rating Agency
Rating
Outlook
Fitch
A-
Stable
Moody's
A3
Stable
S&P
BBB+
Stable

*     In May 2011, Fitch downgraded our corporate credit rating from BBB to BBB-. The Black Hills Power credit rating remained unchanged.


Capital Requirements

Actual and forecasted capital requirements for maintenance capital and development capital are as follows (in thousands):
 
Expenditures for the
 
Total
 
Total
 
Total
 
 
Six Months Ended June 30, 2011
 
2011 Planned
Expenditures
 
2012 Planned
Expenditures
 
2013 Planned
Expenditures
 
Utilities:
 
 
 
 
 
 
 
 
Electric Utilities (1) (2) (3)
$
99,795

 
$
201,500

 
$
284,300

 
$
280,600

 
Gas Utilities
16,291

 
58,600

 
55,800

 
47,600

 
Non-regulated Energy:
 
 
 
 
 
 
 
 
Oil and Gas (4)
22,313

 
67,500

 
61,500

 
93,300

 
Power Generation (5) 
63,706

 
91,700

 
4,200

 
4,400

 
Coal Mining
5,237

 
12,500

 
16,000

 
16,700

 
Energy Marketing
2,651

 
2,400

 
3,400

 
3,400

 
Corporate
1,347

 
6,950

 
11,630

 
6,650

 
 
$
211,340

 
$
441,150

 
$
436,830

 
$
452,650

 
____________
(1)    The 2011 total planned expenditures include capital requirements associated with the on-going construction of 180 MW gas-fired power generation facility to serve our Colorado Electric customers. We spent $39.6 million during the first six months of 2011. The total construction cost of the facility is expected to be approximately $227 million and construction is expected to be completed by the end of 2011.

(2)    Planned 2011 expenditures include expected spending of $5.4 million for a planned wind project for Colorado Electric, subject to CPUC approval. Planned 2011 expenditures reflect the cancellation of the wind project at Black Hills Power.

(3)     Planned expenditures for 2012 and 2013 have been updated from our 2010 Annual Report filed on Form 10-K to include (a) $34.4 million for 2012 and $87.4 million for 2013 for new generation and transmission at Cheyenne Light for which a CPCN was filed on August 1, 2011 that is subject to acceptance of the CPCN and air permits, (b) approximately $21.1 million for 2012 for our 50% share of the Colorado Electric wind project, subject to CPUC approval, (c) $43.0 million and $54.3 million, respectively, for 2012 and 2013 for the 88 MW utility owned gas-fired generation at Colorado Electric, also subject to CPUC approval, and (d) $14.6 million additional transmission for Colorado Electric

(4)    Oil and Gas planned expenditures have increased $18.6 million from our planned expenditures disclosed in our Form 10-K, primarily due to development in the Bakken formation and our Mancos test program.

(5)    Our Power Generation segment was awarded the bid to provide 200 MW of generation capacity for a 20-year period to Colorado Electric. We spent $63.5 million during the first six months of 2011. The total construction cost of the new facility is expected to be approximately $260 million, and construction is expected to be completed by the end of 2011.

We continually evaluate all of our forecasted capital expenditures, and if determined prudent, we may defer some of these expenditures for a period of time. Future projects are dependent upon the availability of attractive economic opportunities, and as a result, actual expenditures may vary significantly from forecasted estimates.


Contractual Obligations

Unconditional purchase obligations for firm transportation and storage fees for our Energy Marketing segment decreased $3.4 million from $83.5 million at December 31, 2010 to $80.1 million at June 30, 2011. Approximately $46.9 million of the firm transportation and storage fee obligations relate to the 2011-2013 period with the remaining occurring thereafter.


68



Construction of a 180 MW power generation facility by our Colorado Electric utility and 200 MW power generation facility by our Power Generation segment is progressing. Cost of construction is expected to be approximately $227 million for Colorado Electric and $260 million for the Power Generation segment. Construction is expected to be completed at both facilities by December 31, 2011. As of June 30, 2011, committed contracts for equipment purchases and for construction were 100% and 95% complete, respectively, for the Colorado Electric utility and 100% and 94% complete, respectively, for the Power Generation segment.

As part of its plan to meet Colorado's Renewable Energy Standard, Colorado Electric filed a proposal in March 2011 with the CPUC to rate base 50% ownership in a 29 MW wind turbine project. On July 15, 2011, Colorado Electric signed a wind turbine supply agreement with Vestas-American Wind Technologies, Inc. for $33.3 million. Our 50% share of the project is expected to cost approximately $27.0 million and is expected to begin serving Colorado Electric customers no later than December 31, 2012. The proposal is pending with the CPUC.

Guarantees

Except as noted below, there have been no new guarantees provided from those previously disclosed in Note 20 of our Notes to the Consolidated Financial Statements in our 2010 Annual Report on Form 10-K.

The guarantee for up to $7.0 million of the obligations of Enserco under an agency agreement expired in the first quarter of 2011.

The construction of the office building in Papillion, Nebraska was completed and the guarantee for $6.0 million was terminated upon purchase of the building in April 2011.

In June 2011, a guarantee to Colorado Interstate Gas was amended from $9.3 million to $10.0 million and the expiration date was extended to July 31, 2012. All other terms remained the same.

In June 2011, we issued a guarantee to Cross Timbers Energy Services for the performance and payment obligations of BHUH for natural gas supply purchases up to $7.5 million. The guarantee expires on June 30, 2012 or upon 30 days written notice to the counterpart.

In July 2011, we issued a guarantee to Vestas-American Wind Technology, Inc. for the performance and payment obligations of Colorado Electric for $33.3 million relating to the purchase of wind turbines for a Colorado Electric wind power generation project. This guarantee will remain in effect until satisfaction of Colorado Electric's contractual obligation. We expect the guarantee to expire on or about January 15, 2013.

New Accounting Pronouncements

Other than the new pronouncements reported in our 2010 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.


69



FORWARD-LOOKING INFORMATION

This report contains forward-looking information. All statements, other than statements of historical fact, included in this report that address activities, events, or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. Forward-looking information involves risks and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potential," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized. The factors which may cause our results to vary significantly from our forward-looking statements include the risk factors described in Item 1A. of our 2010 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, and the following:

We are evaluating financing options including senior notes, first mortgage bonds, term loans, project financing and equity issuance. Some important factors that could cause actual results to differ materially from those anticipated include:

Our ability to access the bank loan and debt and equity capital markets depends on market conditions beyond our control. If the capital markets deteriorate, we may not be able to permanently refinance some short-term debt and fund our power generation projects on reasonable terms, if at all.

Our ability to raise capital in the debt capital markets depends upon our financial condition and credit ratings, among other things. If our financial condition deteriorates unexpectedly, or our credit ratings are lowered, we may not be able to refinance some short-term debt and fund our power generation projects on reasonable terms, if at all.

We anticipate that our existing credit capacity and available cash will be sufficient to fund our working capital needs and our maintenance capital requirements. Some important factors that could cause actual results to differ materially from those anticipated include:

Our access to revolving credit capacity depends on maintaining compliance with loan covenants. If we violate these covenants, we may lose revolving credit capacity and not have sufficient cash available for our peak winter needs and other working capital requirements, and our forecasted capital expenditure requirements.

Counterparties may default on their obligations to supply commodities, return collateral to us, or otherwise meet their obligations under commercial contracts, including those designed to hedge against movements in commodity prices.

We expect to fund a portion of our capital requirements for the planned regulated and non-regulated generation additions to supply our Colorado Electric subsidiary through a combination of long-term debt and issuance of equity.

We expect contributions to our defined benefit pension plans to be approximately $10.0 million and $13.4 million for the remainder of 2011 and for 2012, respectively. Some important factors that could cause actual contributions to differ materially from anticipated amounts include:

The actual value of the plans' invested assets.

The discount rate used in determining the funding requirement.

The outcome of pending labor negotiations relating to benefit participation of our collective bargaining agreements.

We expect the goodwill related to our utility assets to fairly reflect the long-term value of stable, long-lived utility assets. Some important factors that could cause us to revisit the fair value of this goodwill include:

A significant and sustained deterioration of the market value of our common stock.


70



Negative regulatory orders, condemnation proceedings or other events that materially impact our Utilities' ability to generate sufficient stable cash flow over an extended period of time.

We expect to make approximately $441.2 million of capital expenditures in 2011. Some important factors that could cause actual expenditures to differ materially from those anticipated include:

The timing of planned generation, transmission or distribution projects for our Utilities is influenced by state and federal regulatory authorities and third parties. The occurrence of events that impact (favorably or unfavorably) our ability to make planned or unplanned capital expenditures could cause our forecasted capital expenditures to change.

Forecasted capital expenditures associated with our Oil and Gas segment are driven, in part, by current market prices. Changes in crude oil and natural gas prices may cause us to change our planned capital expenditures related to our oil and gas operations.

Our ability to complete the planning, permitting, construction, start-up and operation of power generation facilities in a cost-efficient and timely manner.

The timing, volatility, and extent of changes in energy and commodity prices, supply or volume, the cost and availability of transportation of commodities, changes in interest or foreign exchange rates, and the demand for our services, any of which can affect our earnings, our financial liquidity and the underlying value of our assets including the possibility that we may be required to take future impairment charges under the SEC's full cost ceiling test for natural gas and oil reserves.

Federal and state laws concerning climate change and air emissions, including emission reduction mandates, carbon emissions and renewable energy portfolio standards, may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain or which could mandate or require closure of one or more of our generating units.

The effect of Dodd-Frank and the regulations to be adopted thereunder on our use of derivative instruments in connection with our Energy Marketing activities and to hedge our expected production of oil and natural gas and on our use of interest rate derivative instruments.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Utilities

We produce, purchase and distribute power in four states and purchase and distribute natural gas in five states. All of our gas distribution utilities have PGA provisions that allow them to pass the prudently-incurred cost of gas through to the customer. To the extent that gas prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to true-up billed amounts to match the actual natural gas cost we incurred. These adjustments are subject to periodic prudence reviews by the state utility commissions. We have a mechanism in South Dakota, Colorado, Wyoming and Montana for our electric utilities that serves a purpose similar to the PGAs for our gas utilities. To the extent that our fuel and purchased power energy costs are higher or lower than the energy cost built into our tariffs, the difference (or a portion thereof) is passed through to the customer.

As allowed or required by state utility commissions, we have entered into certain exchange-traded natural gas futures, options and basis swaps to reduce our customers' underlying exposure to volatility of natural gas prices. These transactions are considered derivatives and are marked-to-market. Gains or losses, as well as option premiums on these transactions, are recorded in Regulatory assets or Regulatory liabilities.

The fair value of our Utilities derivative contracts is summarized below (in thousands):

 
June 30,
2011
 
December 31,
2010
 
June 30,
2010
Net derivative (liabilities) assets
$
(3,441
)
 
$
(7,188
)
 
$
(6,045
)
Cash collateral
6,254

 
10,355

 
9,551

 
$
2,813

 
$
3,167

 
$
3,506



71



Non-Regulated Trading Activities

The following table provides a reconciliation of Energy Marketing activity in our marketing portfolio that has been recorded at fair value including market value adjustments on inventory positions that have been designated as part of a fair value hedge during the six months ended June 30, 2011 (in thousands):

Total fair value of energy marketing positions marked-to-market at December 31, 2010
$
23,418

(a)
Net cash settled during the period on positions that existed at December 31, 2010
918

 
Unrealized gain (loss) on new positions entered during the period and still existing at June 30, 2011
26,288

 
Realized (gain) loss on positions that existed at December 31, 2010 and were settled during the period
(9,422
)
 
Change in cash collateral
(2,708
)
 
Unrealized gain (loss) on positions that existed at December 31, 2010 and still exist at June 30, 2011
(10,414
)
 
Total fair value of energy marketing positions at June 30, 2011
$
28,080

(a)
____________
(a)
The fair value of energy marketing positions consists of derivative assets and derivative liabilities held at fair value in accordance with accounting standards for fair value measurements and market value adjustments to natural gas inventory that has been designated as a hedged item as part of a fair value hedge in accordance with accounting standards for derivatives and hedges, as follows (in thousands):

 
June 30,
2011
 
March 31,
2011
 
December 31,
2010
Net derivative assets
$
27,415

 
$
11,518

 
$
28,524

Cash collateral
1,250

 
2,984

 
3,958

Market adjustment recorded in material, supplies and fuel
(585
)
 
316

 
(9,064
)
Total fair value of energy marketing positions marked-to-market
$
28,080

 
$
14,818

 
$
23,418


To value the assets and liabilities for our outstanding derivative contracts, we use the fair value methodology outlined in accounting standards for fair value measurements and disclosures. See Note 3 of the Notes to Consolidated Financial Statements in our 2010 Annual Report on Form 10-K and Note 12 and Note 13 of the accompanying Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

The sources of fair value measurements were as follows (in thousands):

Source of Fair Value of Energy Marketing Positions
Maturities
Less than 1 year
 
1 - 2 years
 
Total Fair Value
Cash collateral
$
1,184

 
$
66

 
$
1,250

Level 1

 

 

Level 2
13,142

 
7,958

 
21,100

Level 3
2,475

 
3,840

 
6,315

Market value adjustment for inventory (see footnote (a) above)
(585
)
 

 
(585
)
 
 
 
 
 
 
Total fair value of our energy marketing positions
$
16,216

 
$
11,864

 
$
28,080



72



GAAP restricts mark-to-market accounting treatment primarily to only those contracts that meet the definition of a derivative under accounting for derivatives and hedging. Therefore, the above reconciliation does not present a complete picture of our overall portfolio of trading activities or our expected cash flows from energy trading activities. In our natural gas, crude oil and coal marketing operations, we often employ strategies that include utilizing derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of our producer services, end-use origination and wholesale marketing groups. Except in circumstances when we are able to designate transportation, storage or inventory positions as part of a fair value hedge, accounting standards for derivatives generally do not allow us to mark our inventory, transportation or storage positions to market. The result is that while a significant majority of our energy marketing positions are fully economically hedged, we are required to mark some parts of our overall strategies (the derivatives) to market value, but are generally precluded from marking the rest of our economic hedges (transportation, inventory or storage) to market. Volatility in reported earnings and derivative positions should be expected given these accounting requirements. The table below references non-GAAP measures that quantify these positions.

The following table presents a reconciliation of our June 30, 2011 energy marketing positions recorded at fair value under GAAP to a non-GAAP measure of the fair value of our energy marketing forward book wherein all forward trading positions are marked-to-market (in thousands):

Fair value of our energy marketing positions marked-to-market in accordance with GAAP
(see footnote (a) above)
$
28,080

Market value adjustments for inventory, storage and transportation positions that are part of our forward trading book, but that are not marked-to-market under GAAP
(13,281
)
Fair value of all forward positions (non-GAAP)
14,799

Cash collateral included in GAAP marked-to-market fair value
(1,250
)
Fair value of all forward positions excluding cash collateral (non-GAAP) *
$
13,549

____________
*
We consider this measure a non-GAAP financial measure. This measure is presented because we believe it provides a more comprehensive view to our investors of our energy trading activities and thus a better understanding of these activities than would be presented by a GAAP measure alone.

Except as discussed above, there have been no material changes in market risk from those reported in our 2010 Annual Report on Form 10-K filed with the SEC. For more information on market risk, see Part II, Items 7 and 7A. in our 2010 Annual Report on Form 10-K, and Note 12 of the Notes to our Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.


73



Activities Other Than Trading

We have entered into agreements to hedge a portion of our estimated 2011, 2012 and 2013 natural gas and crude oil production from the Oil and Gas segment. The hedge agreements in place at June 30, 2011 were as follows:

Natural Gas
Location
 
Transaction Date
 
Hedge Type
 
Term
 
Volume
 
Price
 
 
 
 
 
 
 
 
(MMBtu/day)
 
 
CIG
 
9/2/2009
 
Swap
 
07/11 - 09/11
 
500

 
$
5.32

NWR
 
9/2/2009
 
Swap
 
07/11 - 09/11
 
500

 
$
5.32

San Juan El Paso
 
9/2/2009
 
Swap
 
07/11 - 09/11
 
2,500

 
$
5.54

CIG
 
9/25/2009
 
Swap
 
07/11 - 09/11
 
500

 
$
5.59

NWR
 
9/25/2009
 
Swap
 
07/11 - 09/11
 
1,000

 
$
5.59

AECO
 
9/25/2009
 
Swap
 
07/11 - 09/11
 
500

 
$
5.76

San Juan El Paso
 
9/25/2009
 
Swap
 
07/11 - 09/11
 
5,000

 
$
5.91

San Juan El Paso
 
10/23/2009
 
Swap
 
10/11 - 12/11
 
2,500

 
$
6.23

NWR
 
10/23/2009
 
Swap
 
10/11 - 12/11
 
1,500

 
$
6.12

AECO
 
12/11/2009
 
Swap
 
10/11 - 12/11
 
500

 
$
6.27

CIG
 
12/11/2009
 
Swap
 
10/11 - 12/11
 
1,500

 
$
6.03

San Juan El Paso
 
12/11/2009
 
Swap
 
10/11 - 12/11
 
5,000

 
$
6.15

San Juan El Paso
 
1/8/2010
 
Swap
 
01/12 - 03/12
 
2,500

 
$
6.38

NWR
 
1/8/2010
 
Swap
 
01/12 - 03/12
 
1,500

 
$
6.47

AECO
 
1/8/2010
 
Swap
 
01/12 - 03/12
 
500

 
$
6.32

CIG
 
1/8/2010
 
Swap
 
01/12 - 03/12
 
1,500

 
$
6.43

San Juan El Paso
 
1/25/2010
 
Swap
 
01/12 - 03/12
 
5,000

 
$
6.44

San Juan El Paso
 
3/19/2010
 
Swap
 
07/11 - 09/11
 
500

 
$
5.19

San Juan El Paso
 
3/19/2010
 
Swap
 
04/12 - 06/12
 
7,000

 
$
5.27

CIG
 
3/19/2010
 
Swap
 
04/12 - 06/12
 
1,500

 
$
5.17

NWR
 
3/19/2010
 
Swap
 
04/12 - 06/12
 
1,500

 
$
5.20

AECO
 
3/19/2010
 
Swap
 
04/12 - 06/12
 
250

 
$
5.15

San Juan El Paso
 
6/28/2010
 
Swap
 
07/12 - 09/12
 
3,500

 
$
5.19

NWR
 
6/28/2010
 
Swap
 
07/12 - 09/12
 
1,500

 
$
5.01

CIG
 
6/28/2010
 
Swap
 
07/12 - 09/12
 
1,500

 
$
4.98

CIG
 
2/18/2011
 
Swap
 
10/12 - 12/12
 
500

 
$
4.42

San Juan El Paso
 
2/18/2011
 
Swap
 
10/12 - 12/12
 
2,500

 
$
4.46

NWR
 
2/18/2011
 
Swap
 
10/12 - 12/12
 
1,000

 
$
4.44

San Juan El Paso
 
4/19/2011
 
Swap
 
07/12 - 09/12
 
2,000

 
$
4.45

San Juan El Paso
 
4/19/2011
 
Swap
 
10/12 - 12/12
 
2,000

 
$
4.62

San Juan El Paso
 
4/19/2011
 
Swap
 
01/13 - 03/13
 
2,500

 
$
5.03

San Juan El Paso
 
4/19/2011
 
Swap
 
04/13 - 06/13
 
2,500

 
$
4.64

San Juan El Paso
 
6/6/2011
 
Swap
 
01/13 - 03/13
 
2,500

 
$
5.18







74



Crude Oil

Location
 
Transaction Date
 
Hedge Type
 
Term
 
Volume
 
Price
 
 
 
 
 
 
 
 
(Bbls/month)
 
 
NYMEX
 
9/2/2009
 
Swap
 
07/11 - 09/11
 
5,000

 
$
75.10

NYMEX
 
9/2/2009
 
Put
 
07/11 - 09/11
 
5,000

 
$
63.00

NYMEX
 
9/29/2009
 
Swap
 
07/11 - 09/11
 
5,000

 
$
74.00

NYMEX
 
10/6/2009
 
Put
 
07/11 - 09/11
 
5,000

 
$
65.00

NYMEX
 
10/9/2009
 
Swap
 
10/11 - 12/11
 
5,000

 
$
79.35

NYMEX
 
10/23/2009
 
Put
 
10/11 - 12/11
 
5,000

 
$
75.00

NYMEX
 
11/19/2009
 
Swap
 
07/11 - 09/11
 
1,500

 
$
85.95

NYMEX
 
11/19/2009
 
Swap
 
10/11 - 12/11
 
5,000

 
$
87.50

NYMEX
 
1/8/2010
 
Put
 
10/11 - 12/11
 
6,000

 
$
75.00

NYMEX
 
1/8/2010
 
Put
 
01/12 - 03/12
 
5,000

 
$
75.00

NYMEX
 
1/25/2010
 
Swap
 
01/12 - 03/12
 
5,000

 
$
83.30

NYMEX
 
2/26/2010
 
Swap
 
01/12 - 03/12
 
5,000

 
$
83.80

NYMEX
 
3/19/2010
 
Swap
 
01/12 - 03/12
 
5,000

 
$
83.80

NYMEX
 
3/19/2010
 
Swap
 
04/12 - 06/12
 
5,000

 
$
84.00

NYMEX
 
3/31/2010
 
Put
 
04/12 - 06/12
 
5,000

 
$
75.00

NYMEX
 
5/13/2010
 
Swap
 
04/12 - 06/12
 
5,000

 
$
87.85

NYMEX
 
6/28/2010
 
Swap
 
07/12 - 09/12
 
5,000

 
$
83.80

NYMEX
 
8/17/2010
 
Swap
 
04/12 - 06/12
 
3,000

 
$
82.60

NYMEX
 
8/17/2010
 
Swap
 
07/12 - 09/12
 
5,000

 
$
82.85

NYMEX
 
9/16/2010
 
Swap
 
07/12 - 09/12
 
5,000

 
$
84.60

NYMEX
 
11/9/2010
 
Swap
 
10/12 - 12/12
 
5,000

 
$
91.10

NYMEX
 
1/6/2011
 
Swap
 
10/12 - 12/12
 
5,000

 
$
93.40

NYMEX
 
1/20/2011
 
Swap
 
01/13 - 03/13
 
5,000

 
$
94.20

NYMEX
 
2/17/2011
 
Swap
 
10/12 - 03/13
 
5,000

 
$
97.85

NYMEX
 
3/4/2011
 
Swap
 
07/11 - 12/11
 
5,000

 
$
106.10

NYMEX
 
3/4/2011
 
Swap
 
01/12 - 12/12
 
2,000

 
$
104.60

NYMEX
 
3/4/2011
 
Swap
 
01/13 - 03/13
 
3,000

 
$
103.35

NYMEX
 
4/20/2011
 
Swap
 
07/12 - 06/13
 
2,000

 
$
106.80

NYMEX
 
6/3/2011
 
Swap
 
04/13 - 06/13
 
5,000

 
$
100.90


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. As of June 30, 2011 we had $150.0 million of notional amount floating-to-fixed interest rate swaps, having a maximum term of 5.5 years. These swaps have been designated as hedges in accordance with accounting standards for derivatives and hedges and accordingly their mark-to-market adjustments are recorded in Accumulated other comprehensive loss on the Condensed Consolidated Balance Sheets.

We also have interest rate swaps with a notional amount of $250.0 million which were entered into for the purpose of hedging interest rate movements that would impact long-term financings that were originally expected to occur in 2008. The swaps were originally designated as cash flow hedges and the mark-to-market value was recorded in Accumulated other comprehensive loss on the Condensed Consolidated Balance Sheets. Based on credit market conditions that transpired during the fourth quarter of 2008, we determined it was probable that the forecasted long-term debt financings would not occur in the time period originally specified and as a result, the swaps were no longer effective hedges and the hedge relationships were de-designated. Mark-to-market adjustments on the swaps are now recorded within the income statement. For the three months and six months ended June 30, 2011 we recorded pre-tax unrealized mark-to-market losses of $7.8 million and $2.4 million, respectively, For the three months and six months ended June 30, 2010 we recorded pre-tax unrealized mark-to-market losses of $24.9 million and $28.0 million, respectively. These swaps are 7.5 and 17.5 year swaps which have amended mandatory early termination dates ranging from December 15, 2011 to December 29, 2011.


75



We have continued to maintain these swaps in anticipation of our upcoming financing needs, particularly our upcoming holding company debt maturities, which are $225 million and $250 million in years 2013 and 2014, respectively. Alternatively, we may choose to cash settle these swaps at their fair value prior to their mandatory 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 stated termination dates.

Further details of the swap agreements are set forth in Note 12 of the Notes to the Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

On June 30, 2011, December 31, 2010 and June 30, 2010, our interest rate swaps and related balances were as follows (dollars in thousands):

June 30, 2011
Notional
 
Weighted Average Fixed Interest Rate
 
Maximum Terms in Years *
 
Current Assets
 
Non- current Assets
 
Current Liabilities
 
Non- current Liabilities
 
Pre-tax Accumulated Other Comprehensive Income (Loss)
 
Pre-tax Income (Loss)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Designated Interest rate swaps
$150,000
 
5.04%
 
5.50
 
$

 
$

 
$6,900
 
$15,788
 
$(22,688)
 
$

De-designated Interest rate swaps
250,000
 
5.67%
 
0.50
 

 

 
56,342
 

 

 
(2,362
)
 
$400,000
 
 
 
 
 
$

 
$

$—
$63,242
$—
$15,788
 
$(22,688)
 
$
(2,362
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Designated Interest rate swaps
$
150,000

 
5.04
%
 
6.0

 
$

 
$

 
$
6,823

 
$
14,976

 
$
(21,799
)
 
$

De-designated Interest rate swaps
250,000

 
5.67
%
 
1.0

 

 

 
53,980

 

 

 
(15,193
)
 
$
400,000

 
 
 
 
 
$


$


$
60,803


$
14,976

 
$
(21,799
)

$
(15,193
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
June 30, 2010
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Designated Interest rate swaps
$
150,000

 
5.04
%
 
6.50

 
$

 
$

 
$
6,393

 
$
17,551

 
$
(23,944
)
 
$

De-designated Interest rate swaps
250,000

 
5.67
%
 
0.50

 

 

 
66,740

 

 

 
(27,953
)
 
$
400,000

 
 
 
 
 
$


$


$
73,133


$
17,551

 
$
(23,944
)

$
(27,953
)
* Maximum terms in years for our de-designed interest rate swaps reflect the amended mandatory early termination dates. If the mandatory 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 million terminate in 7.5 years and de-designated swaps totaling $150 million terminate in 17.5 years.

Based on June 30, 2011 market interest rates and balances for our $150 million notional interest rate swaps, a loss of approximately $6.9 million would be realized and reported in pre-tax earnings during the next 12 months. Estimated and realized losses will likely change during the next 12 months 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) as of June 30, 2011. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

There have been no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2011 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.


76



BLACK HILLS CORPORATION

Part II — Other Information

ITEM 1.
Legal Proceedings

For information regarding legal proceedings, see Note 19 in Item 8 of our 2010 Annual Report on Form 10-K and Note 15 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 15 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 December 31, 2010.

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
April 1, 2011 -
 
 
 
 
 
 
 
 
April 30, 2011
 

 
$

 

 

 
 
 
 
 
 
 
 
 
May 1, 2011 -
 
 
 
 
 
 
 
 
May 31, 2011
 
969

 
$
34.61

 

 

 
 
 
 
 
 
 
 
 
June 1, 2011 -
 
 
 
 
 
 
 
 
June 30, 2011
 

 
$

 

 

 
 
 
 
 
 
 
 
 
Total
 
969

 
$
34.61

 

 

____________
(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.


77



ITEM 5.     Other Information

Mine Safety and Health Administration Safety Data
Safety is a core value at Black Hills Corporation and at each of its subsidiary operations. We have in place a comprehensive safety program that includes extensive health and safety training for all employees, site inspections, emergency response preparedness, crisis communications training, incident investigation, regulatory compliance training and process auditing, as well as an open dialogue between all levels of employees. The goals of our processes are to eliminate exposure to hazards in the workplace, ensure that we comply with all mine safety regulations, and support regulatory and industry efforts to improve the health and safety of our employees along with the industry as a whole.

Under the recently enacted Dodd-Frank Act, each operator of a coal or other mine is required to include certain mine safety results in its periodic reports filed with the SEC. Our mining operations, consisting of our Wyodak Coal Mine, are subject to regulation by the federal Mine Safety and Health Administration (“MSHA”) under the Federal Mine Safety and Health Act of 1977 (the “Mine Act”). Below we present the following information regarding certain mining safety and health matters, for the three month period ended June 30, 2011. In evaluating this information, consideration should be given to factors such as: (i) the number of citations and orders will vary depending on the size of the coal mine, (ii) the number of citations issued will vary from inspector to inspector and mine to mine, and (iii) citations and orders can be contested and appealed, and in that process, are often reduced in severity and amount, and are sometimes dismissed. The information presented includes:

Total number of violations of mandatory health and safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under section 104 of the Mine Act for which we have received a citation from MSHA;

Total number of orders issued under section 104(b) of the Mine Act;

Total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health and safety standards under section 104(d) of the Mine Act;

Total number of imminent danger orders issued under section 107(a) of the Mine Act; and

Total dollar value of proposed assessments from MSHA under the Mine Act.
During the three months ended June 30, 2011, WRDC (i) was not assessed any Mine Act section 110(b)(2) penalties for failure to correct the subject matter of a Mine Act section 104(a) citation within the specified time period, which failure was deemed flagrant (i.e., a reckless or repeated failure to make reasonable efforts to eliminate a known violation that substantially and proximately caused, or reasonably could have been expected to cause, death or serious bodily injury); (ii) did not receive any Mine Act section 107(a) imminent danger orders to immediately remove miners; or (iii) did not receive any MSHA written notices under Mine Act section 104(e) of a pattern of violation of mandatory health or safety standards or of the potential to have such a pattern. In addition, there were no fatalities at the mine during the three months ended June 30, 2011.

The table below sets forth the total number of section 104 citations and/or orders issued by MSHA to WRDC under the indicated provisions of the Mine Act, together with the total dollar value of proposed MSHA assessments, received during the three months ended June 30, 2011 and legal actions pending before the Federal Mine Safety and Health Review Commission, together with the Administrative Law Judges thereof, for each of our mining complexes. All citations were abated within 24 hours of issue.

 
Mine Act Section 104 Significant and Substantial Citations
Mine Act Section 104(b) Orders
Mine Act Section 104(d) Citations and Orders
Mine Act Section 107(a) Imminent Danger Orders
Total Dollar Value of Proposed MSHA Assessments
Number of Legal Actions Pending Before the Federal Mining Safety and Health Review Commission
 
 
 
 
 
 
 
 




$




78



ITEM 6.
Exhibits

 
Exhibit 10.1
Credit Agreement dated June 24, 2011, among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, The Bank of Nova Scotia, as Administrative Agent, Co-Lead Arranger and Joint Book Runner, and U.S. Bank N.A. and CoBank, ACB as Co-Lead Arranger and Joint Book Runners (filed as exhibit to the Form 8-K filed on June 27, 2011 and incorporated by reference herein).
 
 
 
 
Exhibit 10.2
First Amendment to the Restoration Plan of Black Hills Corporation dated July 24, 2011.
 
 
 
 
Exhibit 10.3
First Amendment to the Independent Contractor Agreement between Black Hills Corporation and Lone Mountain Investments, Inc. dated July 27, 2011.
 
 
 
 
Exhibit 10.4
Seventh Amendment to Third Amendment and Restated Credit Agreement effective May 12, 2011, among Enserco Energy, Inc., as borrower, BNP Paribas, as administrative agent, collateral agent and the document agent, as an issuing bank, and a bank, Societe Generale, as an issuing bank, a bank and the syndication agent, and each of the other financial institutions which are parties thereto.

 
 
 
 
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 101
Financials for XBRL Format


79



BLACK HILLS CORPORATION

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: August 5, 2011
 


80



EXHIBIT INDEX


Exhibit Number
Description
 
 
Exhibit 10.1
Credit Agreement dated June 24, 2011, among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, The Bank of Nova Scotia, as Administrative Agent, Co-Lead Arranger and Joint Book Runner, and U.S. Bank N.A. and CoBank, ACB as Co-Lead Arranger and Joint Book Runners (filed as exhibit to the Form 8-K filed on June 27, 2011 and incorporated by reference herein).
 
 
Exhibit 10.2
First Amendment to the Restoration Plan of Black Hills Corporation dated July 24, 2011.
 
 
Exhibit 10.3
First Amendment to the Independent Contractor Agreement between Black Hills Corporation and Lone Mountain Investments, Inc. dated July 27, 2011.
 
 
Exhibit 10.4
Seventh Amendment to Third Amendment and Restated Credit Agreement effective May 12, 2011, among Enserco Energy, Inc., as borrower, BNP Paribas, as administrative agent, collateral agent and the document agent, as an issuing bank, and a bank, Societe Generale, as an issuing bank, a bank and the syndication agent, and each of the other financial institutions which are parties thereto.

 
 
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 101
Financials for XBRL Format

81