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