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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, 2010.
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 30, 2010
 
 
Common stock, $1.00 par value
39,204,087 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, 2010 and 2009
 
 
 
 
Condensed Consolidated Balance Sheets — unaudited
 
 
June 30, 2010, December 31, 2009 and June 30, 2009
 
 
 
 
Condensed Consolidated Statements of Cash Flows — unaudited
 
 
Six Months Ended June 30, 2010 and 2009
 
 
 
 
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 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:
 
Acquisition Facility
Our $1.0 billion single-draw, senior unsecured facility from which a $383 million draw was used to provide part of the funding for the Aquila Transaction
AFUDC
Allowance for Funds Used During Construction
Annexation Agreement
Agreement with the City of Pueblo, Colorado under which the City of Pueblo annexed the property on which Colorado Electric and Colorado IPP are constructing their generation facilities
AOCI
Accumulated Other Comprehensive Income (Loss)
Aquila
Aquila, Inc.
ASC
Accounting Standards Codification
ASC 810-10-15
ASC 810-10-15, "Consolidation of Variable Interest Entities"
ASC 820
ASC 820, "Fair Value Measurements and Disclosures"
ASC 932-10-S99
ASC 932-10-S99, "Extractive Activities - Oil and Gas, SEC Materials"
Bbl
Barrel
Bcf
Billion cubic feet
Bcfe
Billion cubic feet equivalent
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
Blackbox
Blackbox 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 confidential
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 that was formerly known as Black Hills Energy, Inc.
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
Commodities Futures and 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
Corporate Credit Facility
Our $525 million credit facility which was terminated on April 15, 2010
CPUC
Colorado Public Utilities Commission
De-designated interest rate swaps
The $250.0 million notional amount interest rate swaps that were originally designated as cash flow hedges under accounting for derivatives and hedges but were de-designated in December 2008

3

 

DOE
U.S. Department of Energy
Dth
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
EDF
EDF Trading North America, LLC
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
GAAP
Generally Accepted Accounting Principles
GSRS
Gas Safety and Reliability Surcharge
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
IPP Transaction
Our July 11, 2008 sale of seven of our IPP plants to affiliates of Hastings Fund Management Ltd and IIF BH Investment LLC
IUB
Iowa Utilities Board
JPB
Consolidated Wyoming Municipalities Electric Power System Joint Powers 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
KCC
Kansas Corporation Commission
LIBOR
London Interbank Offered Rate
LOE
Lease Operating Expense
Mcf
One thousand standard cubic feet
Mcfe
One thousand standard cubic feet equivalent
MDU
MDU Resources Group, Inc.
MEAN
Municipal Energy Agency of Nebraska
MMBtu
One million British thermal units
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
NPA
Nebraska Public Advocate
NPSC
Nebraska Public Service Commission
NYMEX
New York Mercantile Exchange
Participation Agreement
Amended and Restated Wygen III Participation Agreement dated July 14, 2010 between BHP, MDU and JPB, which includes JPB as partial owner of Wygen III
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
SEC Release No. 33-8995
SEC Release No. 33-8995, "Modernization of Oil and Gas Reporting"
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,
 
2010
 
2009
 
2010
 
2009
 
(in thousands, except per share amounts)
Operating revenues
$
271,291
 
 
$
257,349
 
 
$
713,623
 
 
$
695,292
 
 
 
 
 
 
 
 
 
Operating expenses:
 
 
 
 
 
 
 
Fuel and purchased power
113,152
 
 
112,169
 
 
365,687
 
 
373,189
 
Operations and maintenance
39,520
 
 
40,461
 
 
82,142
 
 
79,795
 
Gain on sale of operating assets
 
 
 
 
(2,683
)
 
(25,971
)
Administrative and general
46,404
 
 
37,708
 
 
85,492
 
 
79,474
 
Depreciation, depletion and amortization
30,260
 
 
29,386
 
 
58,655
 
 
62,712
 
Taxes, other than income taxes
11,120
 
 
11,811
 
 
23,793
 
 
23,509
 
Impairment of long-lived assets
 
 
 
 
 
 
43,301
 
Total operating expenses
240,456
 
 
231,535
 
 
613,086
 
 
636,009
 
 
 
 
 
 
 
 
 
Operating income
30,835
 
 
25,814
 
 
100,537
 
 
59,283
 
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
Interest expense
(22,622
)
 
(23,338
)
 
(44,388
)
 
(42,239
)
Interest rate swap - unrealized (loss) gain
(24,918
)
 
31,706
 
 
(27,953
)
 
46,469
 
Interest income
84
 
 
329
 
 
330
 
 
856
 
Allowance for funds used during construction - equity
260
 
 
1,314
 
 
2,288
 
 
2,686
 
Other income, net
1,268
 
 
893
 
 
1,686
 
 
1,637
 
Total other income (expenses)
(45,928
)
 
10,904
 
 
(68,037
)
 
9,409
 
 
 
 
 
 
 
 
 
(Loss) income from continuing operations before equity in earnings (loss) of unconsolidated subsidiaries and income taxes
(15,093
)
 
36,718
 
 
32,500
 
 
68,692
 
Equity in earnings (loss) of unconsolidated subsidiaries
1,291
 
 
1,576
 
 
1,608
 
 
1,249
 
Income tax benefit (expense)
5,143
 
 
(13,713
)
 
(11,333
)
 
(19,735
)
 
 
 
 
 
 
 
 
(Loss) income from continuing operations
(8,659
)
 
24,581
 
 
22,775
 
 
50,206
 
Income from discontinued operations, net of taxes
 
 
 
 
 
 
766
 
Net (loss) income
$
(8,659
)
 
$
24,581
 
 
$
22,775
 
 
$
50,972
 
 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
 
 
Basic
38,902
 
 
38,598
 
38,875
 
 
38,554
 
Diluted
38,902
 
 
38,658
 
39,042
 
 
38,611
 
 
 
 
 
 
 
 
 
Earnings (loss) per share:
 
 
 
 
 
 
 
Basic-
 
 
 
 
 
 
 
Continuing operations
$
(0.22
)
 
$
0.64
 
 
$
0.59
 
 
$
1.30
 
Discontinued operations
 
 
 
 
 
 
0.02
 
Total (loss) earnings per share - basic
$
(0.22
)
 
$
0.64
 
 
$
0.59
 
 
$
1.32
 
 
 
 
 
 
 
 
 
Diluted-
 
 
 
 
 
 
 
Continuing operations
$
(0.22
)
 
$
0.64
 
 
$
0.58
 
 
$
1.30
 
Discontinued operations
 
 
 
 
 
 
0.02
 
Total (loss) earnings per share - diluted
$
(0.22
)
 
$
0.64
 
 
$
0.58
 
 
$
1.32
 
 
 
 
 
 
 
 
 
Dividends paid per share of common stock
$
0.360
 
 
$
0.355
 
 
$
0.720
 
 
$
0.710
 
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,
2010
 
December 31,
2009
 
June 30,
2009
 
(in thousands, except share amounts)
ASSETS
 
 
 
 
 
Current assets:
 
 
 
 
 
Cash and cash equivalents
$
64,033
 
 
$
112,901
 
 
$
122,351
 
Restricted cash
16,169
 
 
17,502
 
 
 
Accounts receivables, net
208,185
 
 
274,489
 
 
181,250
 
Materials, supplies and fuel
135,049
 
 
123,322
 
 
88,672
 
Derivative assets, current
54,589
 
 
37,747
 
 
75,600
 
Income tax receivable, net
 
 
2,031
 
 
 
Deferred income tax asset, current
19,956
 
 
4,523
 
 
17,640
 
Regulatory assets, current
41,852
 
 
25,085
 
 
14,086
 
Other current assets
13,339
 
 
27,270
 
 
31,917
 
Total current assets
553,172
 
 
624,870
 
 
531,516
 
 
 
 
 
 
 
Investments
18,261
 
 
18,524
 
 
20,316
 
 
 
 
 
 
 
Property, plant and equipment
3,141,029
 
 
2,975,993
 
 
2,819,510
 
Less accumulated depreciation and depletion
(852,414
)
 
(815,263
)
 
(773,278
)
Total property, plant and equipment, net
2,288,615
 
 
2,160,730
 
 
2,046,232
 
 
 
 
 
 
 
Other assets:
 
 
 
 
 
Goodwill
353,734
 
 
353,734
 
 
359,288
 
Intangible assets, net
4,189
 
 
4,309
 
 
4,784
 
Derivative assets, non-current
9,726
 
 
3,777
 
 
5,029
 
Regulatory assets, non-current
121,026
 
 
135,578
 
 
133,386
 
Other assets, non-current
21,559
 
 
16,176
 
 
11,189
 
Total other assets
510,234
 
 
513,574
 
 
513,676
 
 
 
 
 
 
 
TOTAL ASSETS
$
3,370,282
 
 
$
3,317,698
 
 
$
3,111,740
 
 
The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.

6

 

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Continued)
(unaudited)
 
 
June 30,
2010
 
December 31,
2009
 
June 30,
2009
 
(in thousands, except share amounts)
LIABILITIES AND STOCKHOLDERS' EQUITY
 
 
 
 
 
Current liabilities:
 
 
 
 
 
Accounts payable
$
206,422
 
 
$
229,352
 
 
$
175,190
 
Accrued liabilities
130,194
 
 
151,504
 
 
133,291
 
Derivative liabilities, current
91,259
 
 
57,166
 
 
69,347
 
Accrued income taxes, net
13,974
 
 
 
 
27,152
 
Regulatory liabilities, current
22,447
 
 
7,092
 
 
36,943
 
Notes payable
225,000
 
 
164,500
 
 
270,500
 
Current maturities of long-term debt
4,539
 
 
35,245
 
 
32,086
 
Total current liabilities
693,835
 
 
644,859
 
 
744,509
 
 
 
 
 
 
 
Long-term debt, net of current maturities
990,130
 
 
1,015,912
 
 
719,243
 
Deferred credits and other liabilities:
 
 
 
 
 
Deferred income tax liability, non-current
271,684
 
 
262,034
 
 
233,592
 
Derivative liabilities, non-current
18,177
 
 
11,999
 
 
12,098
 
Regulatory liabilities, non-current
50,227
 
 
42,458
 
 
39,967
 
Benefit plan liabilities
148,190
 
 
140,671
 
 
160,712
 
Other deferred credits and other liabilities
115,656
 
 
114,928
 
 
121,519
 
Total deferred credits and other liabilities
603,934
 
 
572,090
 
 
567,888
 
 
 
 
 
 
 
Stockholders' equity:
 
 
 
 
 
Common stockholders' equity —
 
 
 
 
 
Common stock $1 par value; 100,000,000 shares authorized; Issued 39,204,231; 38,977,526 and 38,836,918 shares, respectively
39,204
 
 
38,978
 
 
38,837
 
Additional paid-in capital
595,219
 
 
591,390
 
 
586,879
 
Retained earnings
468,430
 
 
473,857
 
 
470,883
 
Treasury stock at cost – 1,021; 8,834 and 3,549 shares, respectively
(27
)
 
(224
)
 
(84
)
Accumulated other comprehensive loss
(20,443
)
 
(19,164
)
 
(16,415
)
Total stockholders' equity
1,082,383
 
 
1,084,837
 
 
1,080,100
 
 
 
 
 
 
 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
3,370,282
 
 
$
3,317,698
 
 
$
3,111,740
 
 
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,
 
2010
 
2009
Operating activities:
(in thousands)
 
 
 
 
Net income
$
22,775
 
 
$
50,972
 
Income from discontinued operations, net of taxes
 
 
(766
)
Income from continuing operations
22,775
 
 
50,206
 
Adjustments to reconcile income from continuing operations to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
58,655
 
 
62,712
 
Impairment of long-lived assets
 
 
43,301
 
Derivative fair value adjustments
(2,445
)
 
12,780
 
Gain on sale of operating assets
(2,683
)
 
(25,971
)
Stock compensation
1,971
 
 
744
 
Unrealized mark-to-market loss (gain) on interest rate swaps
27,953
 
 
(46,469
)
Deferred income taxes
(6,078
)
 
(21
)
Equity in (earnings) loss of unconsolidated subsidiaries
(1,608
)
 
(1,249
)
Allowance for funds used during construction - equity
(2,288
)
 
(2,686
)
Employee benefit plans
8,143
 
 
8,556
 
Other non-cash adjustments
3,380
 
 
2,333
 
Change in operating assets and liabilities:
 
 
 
Materials, supplies and fuel
(19,896
)
 
31,938
 
Accounts receivable and other current assets
93,873
 
 
164,718
 
Accounts payable and other current liabilities
(50,011
)
 
(112,073
)
Regulatory assets
(2,806
)
 
31,623
 
 Regulatory liabilities
13,401
 
 
30,939
 
Other operating activities
1,654
 
 
(6,024
)
Net cash provided by operating activities of continuing operations
143,990
 
 
245,357
 
Net cash provided by operating activities of discontinued operations
 
 
883
 
Net cash provided by operating activities
143,990
 
 
246,240
 
 
 
 
 
Investing activities:
 
 
 
Property, plant and equipment additions
(171,115
)
 
(163,608
)
Proceeds from sale of ownership interest in operating assets
6,105
 
 
84,199
 
Payment for acquisition of business
(2,250
)
 
 
Working capital adjustment of purchase price allocation on Aquila assets
 
 
7,658
 
Other investing activities
4,239
 
 
(4,963
)
Net cash used in investing activities
(163,021
)
 
(76,714
)
 
 
 
 
Financing activities:
 
 
 
Dividends paid
(28,202
)
 
(27,542
)
Common stock issued
2,281
 
 
1,553
 
Increase in short-term borrowings
268,500
 
 
272,500
 
Decrease in short-term borrowings
(208,000
)
 
(705,800
)
Long-term debt - issuances
 
 
248,500
 
Long-term debt - repayments
(56,488
)
 
(2,001
)
Other financing activities
(7,928
)
 
(2,917
)
Net cash used in financing activities
(29,837
)
 
(215,707
)
 
 
 
 
Decrease in cash and cash equivalents
(48,868
)
 
(46,181
)
 
 
 
 
Cash and cash equivalents:
 
 
 
Beginning of period
112,901
 
 
168,532
 
End of period
$
64,033
 
 
$
122,351
 
 
 
 
 
 
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 2009 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 2009 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 estimates which are, in the opinion of management, necessary for a fair presentation of the June 30, 2010, December 31, 2009 and June 30, 2009 financial information and are of a normal recurring nature. Certain industries in which we operate are highly seasonal and revenues 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, 2010 and June 30, 2009, and our financial condition as of June 30, 2010 and December 31, 2009, 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 financial statements have been reclassified to conform to the current year presentation. These reclassifications had no effect on total assets, net income, cash flows or earnings per share.
 
 
(2)    RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION
 
Recently Adopted Accounting Standards
 
Extractive Activities — Oil and Gas Reserves (SEC Release #33-8995), ASC 932-10-S99
 
The FASB issued an accounting standards update which aligns the oil and gas reserve estimation and disclosure requirements with the SEC released Final Rule, "Modernization of Oil and Gas Reporting" amending the existing Regulation S-K and Regulation S-X reporting requirements to align with current industry practices and technology advances. Key revisions include the ability to include non-traditional resources in reserves, the use of new technology for determining reserves, permitting disclosure of probable and possible reserves, and changes to the oil and gas prices used to determine reserves from the period-end price to a 12-month average price. The average is calculated using the first-day-of-the-month price for each of the 12 months before the end of the reporting period. The amendment was effective for reporting periods ending on or after December 31, 2009. The implementation of this SEC requirement resulted in additional depletion expense of $1.3 million in the fourth quarter of 2009.
 
Consolidation of Variable Interest Entities, ASC 810-10-15
 
In June 2009, the FASB issued a revision regarding consolidations. The amendment requires a company to consider whether an entity that is insufficiently capitalized or is not controlled through voting should be consolidated. It requires additional disclosures about the involvement with variable interest entities and any significant changes in risk exposure due to that involvement. This standard is effective for annual periods that begin after November 15, 2009 with ongoing re-evaluation. The adoption of this standard in January 2010 did not have any impact on our consolidated financial statements, results of operations, and cash flows. We also evaluated this standard on a segment basis and the adoption of this standard did not have any impact on our segment reporting.

9

 

 
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 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 are 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 are effective on January 1, 2011. The guidance requires additional disclosures, but did not impact our financial position, results of operations or cash flows. The additional disclosures are included in Note 14 of the accompanying Notes to Condensed Consolidated Financial Statements.
 
Recently Issued Accounting Standards and Legislation
 
Patient Protection and Affordable Care Act (HR 3590 and HR 4872)
 
In March 2010, the President of the United States signed into law comprehensive healthcare reform legislation under the Patient Protection and Affordable Care Act as amended by the Healthcare and Education Reconciliation Act (the "PPACA). The 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 accounting implications of the PPACA as related regulations and interpretations become available. 
 
Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173)
 
In July 2010, the President of the United States signed into law comprehensive financial reform legislation under the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Act"). Title VII of this Act 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, the Act (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. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it 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. However, significant rule-making by numerous governmental agencies, particularly the CFTC with respect to non-security commodities, will be required over the next several months to implement the restrictions, limitations, and requirements contemplated by the Act and we will continue to evaluate the impact as these rules become available.
 
 
(3)    SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
 
 
Six Months Ended
 
June 30,
2010
 
June 30,
2009
 
(in thousands)
Non-cash investing activities—
 
 
 
Property, plant and equipment acquired with accrued liabilities
$
32,207
 
 
$
40,053
 
Cash (paid) refunded during the period for—
 
 
 
Interest (net of amounts capitalized)
$
(26,881
)
 
$
(41,969
)
Income taxes
$
(399
)
 
$
23,861
 
 
 
 
 
 

10

 

 
(4)    MATERIALS, SUPPLIES AND FUEL
 
The amounts of materials, supplies and fuel included on the accompanying Condensed Consolidated Balance Sheets, by major classification, are provided as follows (in thousands):
 
Major Classification
 
June 30,
2010
 
December 31,
2009
 
June 30,
2009
Materials and supplies
 
$
32,361
 
 
$
31,535
 
 
$
32,145
 
Fuel - Electric Utilities
 
8,913
 
 
7,128
 
 
7,264
 
Natural gas in storage — Gas Utilities
 
15,513
 
 
24,053
 
 
13,109
 
Gas and oil held by Energy Marketing*
 
78,262
 
 
60,606
 
 
36,154
 
Total materials, supplies and fuel
 
$
135,049
 
 
$
123,322
 
 
$
88,672
 
_____________
* As of June 30, 2010, December 31, 2009 and June 30, 2009, market adjustments related to natural gas held by Energy Marketing and recorded in inventory were $(8.5) million, $(0.3) million and $(3.8) million, respectively (see Note 13 for further discussion of Energy Marketing trading activities).
 
Gas and oil 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. Natural gas volumes held as of June 30, 2010, December 31, 2009 and June 30, 2009 include 16,289,903 MMBtu, 12,152,465 MMBtu, and 9,437,198 MMBtu, respectively. Crude oil volumes held as of June 30, 2010, December 31, 2009 and June 30, 2009 include 118,000 Bbl, 69,045 Bbl, and 62,000 Bbl, respectively.
 
Natural gas in storage at our Gas Utilities represents primarily gas purchased for use by our customers. Natural gas volumes held in storage by us fluctuates with the seasonality of our business and the commodity price of natural gas, and the carrying values are impacted by price fluctuations. Volumes held as of June 30, 2010, December 31, 2009 and June 30, 2009 include 3,730,489 MMBtu, 6,866,550 MMBtu and 3,563,638 MMBtu, respectively.
 
 
(5)    ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS
 
Our Accounts receivable represents primarily customer trade accounts at our Electric Utilities and Gas Utilities and counterparty trade accounts at our Energy Marketing segment. This balance fluctuates due to the seasonality of our regulated Gas Utilities and volumes and commodity prices at our Energy Marketing segment. We maintain an allowance for doubtful accounts which reflects our best estimate of potentially uncollectible trade receivables. We regularly review our trade receivables allowance 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):
 
 
June 30,
2010
 
December 31,
2009
 
June 30,
2009
Accounts receivable, trade
$
185,746
 
 
$
217,723
 
 
$
161,261
 
Unbilled revenues
26,736
 
 
61,387
 
 
26,999
 
Total accounts receivable
212,482
 
 
279,110
 
 
188,260
 
Less allowance for doubtful accounts
(4,297
)
 
(4,621
)
 
(7,010
)
Accounts receivable, net
$
208,185
 
 
$
274,489
 
 
$
181,250
 
 
 

11

 

(6)    NOTES PAYABLE
 
Our credit facilities and debt securities contain certain restrictive covenants including, among others, recourse leverage ratios and consolidated net worth covenant. At June 30, 2010, except as noted below for the Enserco Credit Facility, we were in compliance with these covenants. None of our facilities or debt securities contain default provisions pertaining to our credit ratings.
 
Revolving Credit Facility
 
On April 15, 2010, we terminated our $525 million Corporate Credit Facility and entered into a new $500 million Revolving Credit Facility expiring April 14, 2013. The new Facility can be used for the issuance of letters of credit, to fund working capital needs and for general corporate purposes. The covenants and events of default are substantially the same as the prior facility, except the minimum interest expense coverage ratio covenant was eliminated. 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 are 1.75%, 2.75% and 2.75%, respectively. The new 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 to increase the capacity of the facility to $600 million. Deferred financing costs of $4.6 million were capitalized and are being amortized over the three-year term of the facility. Amortization of deferred financing costs was $0.4 million and $0.4 million for the three and six months ended June 30, 2010, respectively, and $0.1 million and $0.3 million for the three and six months ended June 30, 2009, respectively.
 
Our consolidated net worth was $1,082.4 million at June 30, 2010, which was approximately $246.1 million in excess of the net worth we are required to maintain under the Revolving Credit Facility. At June 30, 2010, our long-term debt ratio was 47.8%, our total debt leverage ratio (long-term debt and short-term debt) was 53.0%, and our recourse leverage ratio was 54.6%. We are currently in compliance with these covenants.
 
Enserco Credit Facility
 
In May 2010, Enserco entered into an agreement for a two-year $250 million committed credit facility. The facility contains an accordion feature which allows us, with the consent of the administrative agent, to increase commitments under the facility to $350 million. This facility replaces the $300 million credit facility which expired on May 7, 2010. Maximum borrowings under the facility are subject to a sub-limit 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%.
 
At June 30, 2010, $141.4 million of letters of credit were issued and outstanding under this facility and there were no cash borrowings outstanding. Deferred financing costs of $2.1 million were recorded for the Enserco Credit Facility and are being amortized over the term of the Facility. Amortization of deferred financing costs under our committed Enserco Credit Facility is included in Interest expense on the accompanying Condensed Consolidated Income Statement. Amortization of deferred financing costs was approximately $0.4 million and $1.0 million for the three and six months ended June 30, 2010, respectively, and $0.3 million and $0.4 million for the three and six months ended June 30, 2009, respectively.
 
The June 1, 2010 coal marketing acquisition (see Note 20) included certain contractual positions that caused Enserco to temporarily not in compliance with one of the non-financial covenants to the Enserco Credit Facility as of June 30, 2010. The Enserco Credit Facility limited the net fixed price volume of coal to 1.0 million tons. As of June 30, 2010, Enserco was above that limit. In July, the participating banks waived the non-compliance with this covenant and increased the permitted net fixed price volume of coal allowed to 2.25 million tons for July 2010 and 2.0 million tons thereafter.
 
 

12

 

(7) LONG-TERM DEBT
 
Black Hills Power Series AC Bonds
 
In February 2010, the Black Hills Power Series AC bonds matured. These were paid in full for $30.0 million of principal plus accrued interest of $1.2 million.
 
Black Hills Power Series Y Bonds
 
In February 2010, Black Hills Power provided notice to the bondholders of its intent to call the Series Y bonds in full. These bonds were originally due in 2018. A total of $2.7 million was paid on March 31, 2010, which included the principal balance of $2.5 million plus accrued interest and an early redemption premium of 2.618%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Consolidated Balance Sheets and will be amortized over the remaining term of the original bonds.
 
Black Hills Power Series Z Bonds
 
In April 2010, Black Hills Power provided notice to the bondholders of its intent to call the Series Z bonds in full. These bonds were originally due to mature in 2021. A total of $21.8 million was paid on June 1, 2010, which included the principal balance of $20.0 million plus accrued interest and an early redemption premium of 4.675%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Consolidated Balance Sheets and will be amortized over the remaining term of the original bonds.
 
 

13

 

(8)    EARNINGS PER SHARE
 
Basic earnings per share from continuing operations are computed by dividing income from continuing operations by the weighted-average number of common shares outstanding during the period. Diluted earnings per share from continuing operations are computed by using all dilutive common shares potentially outstanding during a period. A reconciliation of Income from continuing operations and basic and diluted share amounts, used to compute earnings per share, is as follows (in thousands):
 
Period ended June 30, 2010
 
Three Months
 
Six Months
 
 
Income
 
Average Shares
 
Income
 
Average Shares
 
 
 
 
 
 
 
 
 
(Loss) income from continuing operations
 
$
(8,659
)
 
 
 
$
22,775
 
 
 
 
 
 
 
 
 
 
 
 
Basic earnings
 
$
(8,659
)
 
38,902
 
 
$
22,775
 
 
38,875
 
Dilutive effect of:
 
 
 
 
 
 
 
 
Restricted stock
 
 
 
 
 
 
 
99
 
Other
 
 
 
 
 
 
 
68
 
Diluted (loss) earnings
 
$
(8,659
)
 
38,902
 
 
$
22,775
 
 
39,042
 
 
 
 
 
 
 
 
 
 
Diluted (loss) earnings per share
 
$
(0.22
)
 
 
 
$
0.58
 
 
 
 
Period ended June 30, 2009
 
Three Months
 
Six Months
 
 
Income
 
Average Shares
 
Income
 
Average Shares
 
 
 
 
 
 
 
 
 
Income from continuing operations
 
$
24,581
 
 
 
 
$
50,206
 
 
 
 
 
 
 
 
 
 
 
 
Basic earnings
 
$
24,581
 
 
38,598
 
 
$
50,206
 
 
38,554
 
Dilutive effect of:
 
 
 
 
 
 
 
 
Restricted stock
 
 
 
60
 
 
 
 
57
 
Diluted earnings
 
$
24,581
 
 
38,658
 
 
$
50,206
 
 
38,611
 
 
 
 
 
 
 
 
 
 
Diluted earnings per share
 
$
0.64
 
 
 
 
$
1.30
 
 
 
 
The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive (in thousands):
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2010
 
2009
 
2010
 
2009
Options to purchase common stock
137
 
 
435
 
 
228
 
 
435
 
Restricted stock
108
 
 
 
 
 
 
 
Other
64
 
 
 
 
 
 
 
 
309
 
 
435
 
 
228
 
 
435
 
 
 

14

 

(9)    OTHER COMPREHENSIVE (LOSS) INCOME
 
The following table presents the components of our other comprehensive (loss) income (in thousands):
 
 
Three Months Ended
June 30,
 
2010
 
2009
Net (loss) income
$
(8,659
)
 
$
24,581
 
Other comprehensive (loss) income, net of tax:
 
 
 
Minimum pension liability adjustments (net of tax of $(—))
(27
)
 
 
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $746 and $4,072, respectively)
(1,283
)
 
(7,793
)
Reclassification adjustments on cash flow hedges settled and included in net (loss) income (net of tax of $1,843 and $(2,143), respectively)
(3,274
)
 
3,793
 
Comprehensive (loss) income
$
(13,243
)
 
$
20,581
 
 
 
Six Months Ended
June 30,
 
2010
 
2009
Net income
$
22,775
 
 
$
50,972
 
Other comprehensive income, net of tax:
 
 
 
Minimum pension liability adjustments (net of tax of $(7))
(15
)
 
 
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $155 and $2,928, respectively)
133
 
 
(4,795
)
Reclassification adjustments on cash flow hedges settled and included in net income (net of tax of $782 and $(4,060), respectively)
(1,397
)
 
7,163
 
Comprehensive income
$
21,496
 
 
$
53,340
 
 
Balances by classification included within Accumulated other comprehensive loss on the accompanying Condensed Consolidated Balance Sheets are as follows (in thousands):
 
 
June 30,
2010
 
December 31,
2009
 
June 30,
2009
Derivatives designated as cash flow hedges
$
(10,751
)
 
$
(9,462
)
 
$
(2,191
)
Employee benefit plans
(9,651
)
 
(9,636
)
 
(14,127
)
Amount from equity-method investees
(41
)
 
(66
)
 
(97
)
Total
$
(20,443
)
 
$
(19,164
)
 
$
(16,415
)
 
 

15

 

(10)     COMMON STOCK
 
Other than the following transactions, we had no material changes in our common stock during the first six months of 2010 as reported in Note 11 of the Notes to Consolidated Financial Statements in our 2009 Annual Report on Form 10-K.
 
Equity Compensation Plans
 
•    
We granted 77,693 target performance shares to certain officers and business unit leaders for the January 1, 2010 through December 31, 2012 performance period. Actual shares are not issued until the end of the performance plan period (December 31, 2012). 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, the ending stock price must be at least equal to 75% of the beginning stock price 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 $24.25 per share.
 
•    
We issued 9,625 shares of common stock under the 2009 short-term incentive compensation plan during the six months ended June 30, 2010. Pre-tax compensation cost related to the awards was approximately $0.3 million, which was accrued for in 2009.
 
•    
We granted 159,230 restricted common shares during the six months ended June 30, 2010. The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $4.2 million will be recognized over the three-year vesting period.
 
•    
30,000 stock options were exercised during the six months ended June 30, 2010 at a weighted-average exercise price of $21.875 per share which provided $0.7 million of proceeds.
 
Total compensation expense recognized for all equity compensation plans for the three months ended June 30, 2010 and 2009 was $1.1 million and $1.4 million, respectively, and for the six months ended June 30, 2010 and 2009 was $2.9 million and $1.8 million, respectively.
 
As of June 30, 2010, total unrecognized compensation expense related to non-vested stock awards was $8.8 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 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 57,235 new shares at a weighted-average price of $28.36 during the six months ended June 30, 2010. At June 30, 2010, 238,747 shares of unissued common stock were available for future offering under the Plan.

16

 

 
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% of aggregate consolidated net income since January 1, 2005. As of June 30, 2010, we were in compliance with the above 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 at June 30, 2010:
 
•    
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, 2010, the restricted net assets at our Utilities Group were approximately $164.0 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, 2010 were $78.7 million.
 
•    
As a covenant of 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.
 
 
(11)     EMPLOYEE BENEFIT PLANS
 
Defined Benefit Pension Plans
 
We have three non-contributory defined benefit pension plans (the "Plans"). One Plan covers employees of the following subsidiaries who meet certain eligibility requirements: Black Hills Service Company, Black Hills Power, WRDC and BHEP. The second Plan covers employees of our subsidiary, Cheyenne Light, who meet certain eligibility requirements. The third Plan covers employees of the Black Hills Energy utilities who meet certain eligibility requirements.
 
The components of net periodic benefit cost for the three Plans are as follows (in thousands):
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2010
 
2009
 
2010
 
2009
Service cost
$
1,533
 
 
$
1,929
 
 
$
3,066
 
 
$
3,858
 
Interest cost
3,773
 
 
3,679
 
 
7,546
 
 
7,358
 
Expected return on plan assets
(3,623
)
 
(3,458
)
 
(7,246
)
 
(6,916
)
Prior service cost
305
 
 
41
 
 
610
 
 
82
 
Net loss
500
 
 
752
 
 
1,000
 
 
1,504
 
 
 
 
 
 
 
 
 
Net periodic benefit cost
$
2,488
 
 
$
2,943
 
 
$
4,976
 
 
$
5,886
 
 
We made contributions of less than $0.1 million to the Plans in the first six months of 2010. Contributions of less than $0.1 million and $30.1 million are anticipated to be made to the Plans for 2010 and 2011, respectively.
 

17

 

Non-pension Defined Benefit Postretirement Healthcare Plans
 
We sponsor three 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.
 
The components of net periodic benefit cost for the Healthcare Plans are as follows (in thousands):
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2010
 
2009
 
2010
 
2009
Service cost
$
377
 
 
$
260
 
 
$
754
 
 
$
520
 
Interest cost
611
 
 
542
 
 
1,222
 
 
1,084
 
Expected return on plan assets
(52
)
 
(56
)
 
(104
)
 
(112
)
Prior service benefit
(77
)
 
(22
)
 
(154
)
 
(44
)
Net transition obligation
 
 
15
 
 
 
 
30
 
Net loss (gain)
159
 
 
(8
)
 
318
 
 
(16
)
 
 
 
 
 
 
 
 
Net periodic benefit cost
$
1,018
 
 
$
731
 
 
$
2,036
 
 
$
1,462
 
 
We anticipate that we will make aggregate contributions to the Healthcare Plans for the 2010 and 2011 fiscal years of approximately $3.8 million and $4.0 million, respectively. The contributions are expected to be made in the form of benefits payments.
 
It has been determined that our post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The decrease in net periodic postretirement benefit cost due to the subsidy was approximately $0.1 million for each of the three and six month periods ended June 30, 2010 and 2009, respectively.
 
Supplemental Non-qualified Defined Benefit Plans
 
Additionally, 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 are as follows (in thousands):
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2010
 
2009
 
2010
 
2009
Service cost
$
171
 
 
$
117
 
 
$
342
 
 
$
234
 
Interest cost
321
 
 
344
 
 
642
 
 
688
 
Prior service cost
1
 
 
1
 
 
2
 
 
2
 
Net loss
71
 
 
147
 
 
142
 
 
294
 
 
 
 
 
 
 
 
 
Net periodic benefit cost
$
564
 
 
$
609
 
 
$
1,128
 
 
$
1,218
 
 
We anticipate that we will make aggregate contributions to the Supplemental Plans for the 2010 fiscal year of approximately $0.9 million. The contributions are expected to be made in the form of benefit payments.
 
 

18

 

 
(12)     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, 2010, 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 and Idaho. 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 to be constructed in Colorado, which are expected to be placed into service by December 31, 2011;
 
•    
Coal Mining, which engages in the mining and sale of coal from our mine near Gillette, Wyoming; and
 
•    
Energy Marketing, which markets natural gas, crude oil, coal and related services primarily 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 2009 Annual Report on Form 10-K. In accordance with accounting standards for regulated operations, intercompany fuel and energy sales to the regulated utilities are not eliminated.
 

19

 

Segment information included in the accompanying Condensed Consolidated Statements of Income and Balance Sheets is as follows (in thousands):
 
Three Months Ended June 30, 2010
 
External
Operating
Revenues
 
Inter-segment
Operating
Revenues
 
Income (Loss)
from Continuing
Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
135,496
 
 
$
769
 
 
$
7,196
 
   Gas
 
87,115
 
 
 
 
(886
)
Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas
 
18,658
 
 
 
 
221
 
   Power Generation
 
6,679
 
 
 
 
(416
)
   Coal Mining
 
7,805
 
 
7,244
 
 
3,074
 
   Energy Marketing
 
8,895
 
 
 
 
1,327
 
Corporate (a)
 
 
 
 
 
(19,161
)
Inter-segment eliminations
 
 
 
(1,370
)
 
(14
)
Total
 
$
264,648
 
 
$
6,643
 
 
$
(8,659
)
 
Three Months Ended June 30, 2009
 
External
Operating
Revenues
 
Inter-segment
Operating
Revenues
 
Income (Loss)
from Continuing
Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
118,606
 
 
$
215
 
 
$
4,541
 
   Gas
 
93,338
 
 
 
 
442
 
Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas  
 
17,829
 
 
 
 
129
 
   Power Generation
 
7,215
 
 
 
 
758
 
   Coal Mining
 
7,746
 
 
5,747
 
 
(499
)
   Energy Marketing
 
7,738
 
 
 
 
2,210
 
Corporate (a)
 
 
 
 
 
16,780
 
Inter-segment eliminations
 
 
 
(1,085
)
 
220
 
Total
 
$
252,472
 
 
$
4,877
 
 
$
24,581
 
 
Six Months Ended June 30, 2010
 
External
Operating
Revenues
 
Inter-segment
Operating
Revenues
 
Income (Loss)
from Continuing
Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
284,132
 
 
$
942
 
 
$
17,048
 
   Gas (b)
 
330,285
 
 
 
 
18,612
 
Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas
 
38,401
 
 
 
 
2,569
 
   Power Generation
 
14,747
 
 
 
 
664
 
   Coal Mining
 
14,687
 
 
14,342
 
 
4,420
 
   Energy Marketing
 
18,667
 
 
 
 
3,520
 
Corporate (a)
 
 
 
 
 
(24,128
)
Inter-segment eliminations
 
 
 
(2,580
)
 
70
 
Total
 
$
700,919
 
 
$
12,704
 
 
$
22,775
 
 

20

 

Six Months Ended June 30, 2009
 
External
Operating
Revenues
 
Inter-segment
Operating
Revenues
 
Income (Loss)
from Continuing
Operations
Utilities:
 
 
 
 
 
 
   Electric
 
$
255,665
 
 
$
430
 
 
$
13,858
 
   Gas
 
349,676
 
 
 
 
17,708
 
Non-regulated Energy:
 
 
 
 
 
 
   Oil and Gas (c)
 
34,340
 
 
 
 
(25,591
)
   Power Generation (d)
 
14,834
 
 
 
 
17,911
 
   Coal Mining
 
15,683
 
 
12,212
 
 
319
 
   Energy Marketing
 
14,557
 
 
 
 
3,247
 
Corporate (a)
 
 
 
 
 
22,316
 
Inter-segment eliminations
 
 
 
(2,105
)
 
438
 
Total
 
$
684,755
 
 
$
10,537
 
 
$
50,206
 
 
____________
(a)
Income (loss) from continuing operations includes $16.2 million and $18.2 million net after-tax mark-to-market loss on interest rate swaps for the three and six months ended June 30, 2010 and a $20.6 million and $30.2 million net after-tax mark-to-market gain on interest rate swaps for the three and six months ended June 30, 2009.
(b)
Income (loss) from continuing operations includes a $1.7 million after-tax gain on sale of operating assets at Nebraska Gas.
(c)
As a result of lower natural gas prices at March 31, 2009, our Income (loss) from continuing operations reflects a $27.8 million after-tax non-cash ceiling test impairment of oil and gas assets included in the Oil and Gas segment in the first quarter of 2009 (see Note 18).
(d)
Income (loss) from continuing operations includes $16.9 million after-tax gain on sale to MEAN of 23.5% ownership interest in Wygen I power generation facility.
 
Total assets
June 30,
2010
 
December 31,
2009
 
June 30,
2009
Utilities:
 
 
 
 
 
   Electric
$
1,736,413
 
 
$
1,659,375
 
 
$
1,558,525
 
   Gas
622,585
 
 
684,375
 
 
628,152
 
Non-regulated Energy:
 
 
 
 
 
   Oil and Gas
348,509
 
 
338,470
 
 
347,198
 
   Power Generation
197,545
 
 
161,856
 
 
119,876
 
   Coal Mining
87,474
 
 
76,209
 
 
75,647
 
   Energy Marketing
294,043
 
 
321,207
 
 
299,374
 
Corporate
83,713
 
 
76,206
 
 
82,968
 
Total
$
3,370,282
 
 
$
3,317,698
 
 
$
3,111,740
 
 
 

21

 

(13)     RISK MANAGEMENT ACTIVITIES
 
Our activities in the regulated and non-regulated energy sector 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, and fuel procurement for certain of our gas-fired generation assets and variability in revenue due to changes in gas usage at our regulated Gas Utilities segment resulting 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 2009 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 in this Note along with Note 14.
 
Trading Activities
 
Natural Gas, Crude Oil and Coal Marketing
 
We have a natural gas, crude oil and coal marketing business specializing in producer services, end-use origination and wholesale marketing that conducts business in the western and central regions of the United States and Canada.
 
Contracts and other activities at our natural gas, crude oil and coal marketing operations are accounted for under the accounting standards for energy trading contracts. As such, all of the contracts and other activities at our natural gas, crude oil and coal 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 revenues 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 natural gas, crude oil and coal 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 Risk Management Policies and Procedures as approved by our Executive Risk Committee. Our trading contracts do not include credit risk-related contingent features that require us to maintain a specific credit rating.

22

 

 
We use a number of quantitative tools to measure, monitor and limit our exposure to market risk in our natural gas, crude oil and coal 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 natural gas, crude oil and coal marketing activities and derivative commodity instruments are as follows:
 
 
Outstanding at
June 30, 2010
 
Outstanding at
December 31, 2009
 
Outstanding at
June 30, 2009
 
Notional
Amounts
 
Latest
Expiration
(months)
 
Notional
Amounts
 
Latest
Expiration
(months)
 
Notional
Amounts
 
Latest
Expiration
(months)
(in thousands of MMBtus)
 
 
 
 
 
 
 
 
 
 
 
Natural gas basis swaps purchased
238,853
 
 
21
 
 
231,703
 
 
22
 
 
289,140
 
 
28
 
Natural gas basis swaps sold
252,060
 
 
21
 
 
232,673
 
 
22
 
 
302,324
 
 
28
 
Natural gas fixed-for-float swaps purchased
67,103
 
 
39
 
 
60,927
 
 
16
 
 
90,974
 
 
21
 
Natural gas fixed-for-float swaps sold
86,200
 
 
19
 
 
72,904
 
 
25
 
 
100,088
 
 
18
 
Natural gas physical purchases
122,687
 
 
21
 
 
120,680
 
 
27
 
 
168,381
 
 
18
 
Natural gas physical sales
123,629
 
 
39
 
 
124,830
 
 
27
 
 
184,873
 
 
21
 
 
 
Outstanding at
June 30, 2010
 
Outstanding at
December 31, 2009
 
Outstanding at
June 30, 2009
 
Notional
Amounts
 
Latest
Expiration
(months)
 
Notional
Amounts
 
Latest
Expiration
(months)
 
Notional
Amounts
 
Latest
Expiration
(months)
(in thousands of Bbls)
 
 
 
 
 
 
 
 
 
 
 
Crude oil physical purchases
4,673
 
 
6
 
 
5,048
 
 
12
 
 
5,595
 
 
6
 
Crude oil physical sales
4,754
 
 
6
 
 
4,998
 
 
12
 
 
4,925
 
 
6
 
Crude oil swaps/options purchased
 
 
 
 
 
 
 
 
42
 
 
3
 
Crude oil swaps/options sold
140
 
 
4
 
 
69
 
 
2
 
 
111
 
 
3
 
 
 
Outstanding at June 30, 2010 *
 
 
Notional
Amounts
 
Latest
Expiration
(months)
 
(in thousands of tons)
 
 
 
 
Coal fixed-for-float swaps purchased
6,910
 
 
29
 
 
Coal fixed-for-float swaps sold
4,985
 
 
30
 
 
Coal physical purchases
24,925
 
 
54
 
 
Coal physical sales
6,472
 
 
38
 
 
Coal options purchased
334
 
 
42
 
 
Coal options sold
1,804
 
 
30
 
 
__________
* Coal contracts represent the contractual positions of the coal marketing business acquired on June 1, 2010 and contracts arising from subsequent trading activity.
 
Derivatives and certain natural gas, crude oil and coal marketing activities were marked to fair value on June 30, 2010, December 31, 2009 and June 30, 2009, and the related gains and/or losses recognized in earnings. The amounts included in the accompanying Condensed Consolidated Balance Sheets and Statements of Income are as follows (in thousands):

23

 

 
 
June 30,
2010
 
December 31,
2009
 
June 30,
2009
Derivative assets, current
$
41,576
 
 
$
25,366
 
 
$
52,870
 
Derivative assets, non-current
$
5,888
 
 
$
3,090
 
 
$
1,802
 
Derivative liabilities, current
$
15,912
 
 
$
9,377
 
 
$
14,970
 
Derivative liabilities, non-current
$
(168
)
 
$
(733
)
 
$
(1,917
)
Cash collateral (receivable)/payable included in derivative assets/liabilities
$
 
 
$
(2,728
)
 
$
(9,267
)
Unrealized gain
$
31,720
 
 
$
17,084
 
 
$
32,352
 
 
In addition, certain volumes of natural gas inventory have been designated as the underlying hedged item in a fair value hedge transaction. 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/loss on the Condensed Consolidated Statements of Income, effectively offsetting the earnings impact of the unrealized gain/loss recognized on the associated derivative asset or liability described above. As of June 30, 2010, December 31, 2009 and June 30, 2009, the market adjustments recorded in inventory were $(8.5) million, $(0.3) million and $(3.8) 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.
 
At June 30, 2010, December 31, 2009 and June 30, 2009, we had 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 other comprehensive income and the ineffective portion is reported in earnings.

24

 

 
We had the following derivatives and related balances (dollars in thousands):
 
 
June 30, 2010
 
December 31, 2009
 
June 30, 2009
 
Crude Oil
Swaps/
Options
 
Natural Gas
Swaps
 
Crude Oil
Swaps/
Options
 
Natural Gas
Swaps
 
Crude Oil
Swaps/
Options
 
Natural Gas
Swaps
Notional*
520,500
 
 
9,397,800
 
 
472,500
 
 
9,602,300
 
 
480,000
 
 
9,862,050
 
Maximum terms in years **
0.25
 
 
0.5
 
 
0.25
 
 
0.75
 
 
0.25
 
 
0.75
 
Derivative assets, current
$
2,040
 
 
$
6,855
 
 
$
3,345
 
 
$
5,994
 
 
$
3,600
 
 
$
14,012
 
Derivative assets, non-current
$
855
 
 
$
2,983
 
 
$
136
 
 
$
551
 
 
$
1,453
 
 
$
1,612
 
Derivative liabilities, current
$
2,170
 
 
$
44