form10q_3rdqtr-2009.htm

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 September 30, 2009.
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
o
 
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 October 30, 2009
   
Common stock, $1.00 par value
38,866,236 shares

 
 

 

TABLE OF CONTENTS

   
Page
     
 
Glossary of Terms and Abbreviations
3-5
     
 
Accounting Standards
6
     
PART I.
FINANCIAL INFORMATION
 
     
Item 1.
Financial Statements
 
     
 
Condensed Consolidated Statements of Income –
 
 
Three and Nine Months Ended September 30, 2009 and 2008
7
     
 
Condensed Consolidated Balance Sheets –
 
 
September 30, 2009, December 31, 2008 and September 30, 2008
8
     
 
Condensed Consolidated Statements of Cash Flows –
 
 
Nine Months Ended September 30, 2009 and 2008
9
     
 
Notes to Condensed Consolidated Financial Statements
10-52
     
Item 2.
Management’s Discussion and Analysis of Financial Condition and
 
 
Results of Operations
53-91
     
Item 3.
Quantitative and Qualitative Disclosures about Market Risk
91-97
     
Item 4.
Controls and Procedures
98
     
PART II.
OTHER INFORMATION
 
     
Item 1.
Legal Proceedings
99
     
Item 1A.
Risk Factors
99-100
     
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
101
     
Item 6.
Exhibits
102
     
 
Signatures
103
     
 
Exhibit Index
104

 
2

 

GLOSSARY OF TERMS AND ABBREVIATIONS
 
The following terms and abbreviations 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
AOCI
Accumulated Other Comprehensive Income (Loss)
Aquila
Aquila, Inc.
Aquila Transaction
Our July 14, 2008 acquisition of Aquila’s regulated electric utility in
 
Colorado and its regulated gas utilities in Colorado, Kansas,
 
Nebraska and Iowa
Bbl
Barrel
Bcf
Billions cubic feet
Bcfe
Billion cubic feet equivalents
BHCRPP
Black Hills Corporation Risk Policies and Procedures
BHEP
Black Hills Exploration and Production, Inc., a direct, wholly-owned
 
subsidiary of Black Hills Non-regulated Holdings
Black Hills Electric Generation
Black Hills Electric Generation, LLC, 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, including the gas and electric utility properties acquired
 
from Aquila
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 formed to acquire and own the utility properties
 
acquired from Aquila, all which are now doing business as
 
Black Hills Energy
Black Hills Wyoming
Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black
 
Hills Electric Generation
Btu
British thermal unit
Cheyenne Light
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned
 
subsidiary of the Company
Cheyenne Light Pension Plan
The Cheyenne Light, Fuel and Power Company Pension Plan
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, formed to hold the Colorado electric
 
utility properties acquired from Aquila

 
3

 


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, formed to hold the Colorado gas
 
utility properties acquired from Aquila
Corporate Credit Facility
Our unsecured $525 million revolving line of credit
CPUC
Colorado Public Utilities Commission
Dth
Dekatherm.  A unit of energy equal to 10 therms or one million
 
British thermal units (MMBtu)
Enserco
Enserco Energy Inc., a direct, wholly-owned subsidiary of Black Hills
 
Non-regulated Holdings
EPA
Environmental Protection Agency
EPS
Earnings per share
FERC
Federal Energy Regulatory Commission
GAAP
Generally Accepted Accounting Principles
GE
GE Packaged Power, Inc.
GHG
Greenhouse gases
GSRS
Gas Safety and Reliability Surcharge
Hastings
Hastings Funds Management Ltd
IIF
IIF BH Investment LLC, a subsidiary of an investment entity advised by
 
JPMorgan Asset Management
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, formed to hold the Iowa gas
 
utility properties acquired from Aquila
IPP
Independent Power Production
IPP Transaction
Our July 11, 2008 sale of seven of our IPP plants to affiliates of
 
Hastings and IIF
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, formed to hold the Kansas gas
 
utility properties acquired from Aquila
KCC
Kansas Corporation Commission
LIBOR
London Interbank Offered Rate
LOE
Lease Operating Expense
Mcf
One thousand cubic feet
Mcfe
One thousand 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

 
4

 


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, formed to hold the Nebraska gas
 
utility properties acquired from Aquila
NPA
Nebraska Public Advocate
NPSC
Nebraska Public Service Commission
NYMEX
New York Mercantile Exchange
PGA
Purchase Gas Adjustment
PPA
Power Purchase Agreement
PSCo
Public Service Company of Colorado
SDPUC
South Dakota Public Utilities Commission
SEC
United States Securities and Exchange Commission
Silver Sage
Silver Sage Windpower LLC, a subsidiary of Duke Energy Corporation
WPSC
Wyoming Public Service Commission
WRDC
Wyodak Resources Development Corp., a direct, wholly-owned
 
subsidiary of Black Hills Non-regulated Holdings

 
5

 

ACCOUNTING STANDARDS

ASC
Accounting Standards Codification
ASC 105
ASC 105, “FASB Accounting Standards Codification and the Hierarchy
 
of Generally Accepted Accounting Principles – a replacement of
 
FASB Standard No. 162
ASC 260
ASC 260, “Earnings Per Share”
ASC 715
ASC 715, “Compensation – Retirement Benefits”
ASC 805
ASC 805, “Business Combinations”
ASC 810
ASC 810, “Consolidations”
ASC 810-10-15
ASC 810-10-15, “Consolidation of Variable Interest Entities”
ASC 815
ASC 815, “Derivatives and Hedging”
ASC 820
ASC 820, “Fair Value Measurements and Disclosures”
ASC 825
ASC 825, “Financial Instruments”
ASC 855
ASC 855, “Subsequent Events”
ASC 940-325-S99
ASC 940-325-S99, “SEC Materials”
EITF
Emerging Issues Task Force
FASB
Financial Accounting Standards Board
FSP
FASB Staff Position
FSP EITF 03-6-1
FSP EITF 03-6-1, “Determining Whether Instruments Granted in
 
Share-Based Payment Transactions are Participating Securities”
FSP FAS 107-1
FSP FAS 107-1, “Interim Disclosure About Fair Value of Financial
 
Instruments”
FSP FAS 132(R)-1
FSP FAS 132(R)-1, “Employer’s Disclosures about Pensions and Other
 
Postretirement Benefits” (Revised)
FSP FAS 157-4
FSP FAS 157-4, “Determining Whether a Market is Not Active and a
 
Transaction is Not Distressed”
SEC Release No. 33-8995
SEC Release No. 33-8995, “Modernization of Oil and Gas Reporting”
SFAS
Statement of Financial Accounting Standards
SFAS 141(R)
SFAS 141(R), “Business Combinations”
SFAS 157
SFAS 157, “Fair Value Measurements”
SFAS 160
SFAS 160, “Non-controlling Interest in Consolidated Financial
 
Statements – an amendment of ARB No. 51”
SFAS 161
SFAS 161, “Disclosure about Derivative Instruments and Hedging
 
Activities – an amendment of FASB Statement No. 133”
SFAS 165
SFAS 165, “Subsequent Events”
SFAS 167
SFAS 167, “Amendment to FASB Interpretation No. 46(R)”
SFAS 168
SFAS 168, “FASB Accounting Standards Codification and the
 
Hierarchy of Generally Accepted Accounting Principles – a
 
replacement of FASB Standard No. 162”


 
6

 

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)

   
Three Months Ended
Nine Months Ended
   
September 30,
September 30,
   
2009
     
2008
2009
   
2008
 
   
(in thousands, except per share amounts)
                 
Operating revenues
  $ 225,799     $ 291,892     $ 921,090     $ 598,015  
                                 
Operating expenses:
                               
Fuel and purchased power
    94,120       131,300       467,309       230,643  
Operations and maintenance
    35,431       34,477       115,226       80,762  
Gain on sale of assets
                (25,971 )      
Administrative and general
    38,344       40,993       117,817       90,273  
Depreciation, depletion and amortization
    29,824       30,825       92,535       70,999  
Taxes, other than income taxes
    11,171       11,609       34,680       31,590  
Impairment of long-lived assets
                43,301        
      208,890       249,204       844,897       504,267  
                                 
Operating income
    16,909       42,688       76,193       93,748  
                                 
Other income (expense):
                               
Interest expense
    (20,691 )     (16,402 )     (62,930 )     (35,160 )
Interest rate swap – unrealized (loss) gain
    (8,694 )           37,775        
Interest income
    327       628       1,184       1,427  
Allowance for funds used during
                               
construction – equity
    2,598       1,390       5,284       2,287  
Other income, net
    2,142       171       3,779       573  
      (24,318 )     (14,213 )     (14,908 )     (30,873 )
                                 
(Loss) income from continuing operations
                               
before equity in earnings of
                               
unconsolidated subsidiaries and income
                               
taxes
    (7,409 )     28,475       61,285       62,875  
Equity in earnings of unconsolidated
                               
subsidiaries
    119       1,359       1,368       3,656  
Income tax benefit (expense)
    3,437       (10,312 )     (16,300 )     (21,989 )
                                 
(Loss) income from continuing operations
    (3,853 )     19,522       46,353       44,542  
Income from discontinued operations,
                               
net of taxes
    1,673       145,389       2,439       159,486  
                                 
Net (loss) income
    (2,180 )     164,911       48,792       204,028  
Net loss attributable to non-controlling
                               
 interest
                      (130 )
                                 
Net (loss) income available for
                               
common stock
  $ (2,180 )   $ 164,911     $ 48,792     $ 203,898  
                                 
Weighted average common shares
                               
outstanding:
                               
Basic
    38,643       38,307       38,584       38,145  
Diluted
    38,643       38,425       38,646       38,430  
                                 
Earnings (loss) per share:
                               
Basic–
                               
Continuing operations
  $ (0.10 )   $ 0.51     $ 1.20     $ 1.16  
Discontinued operations
    0.04       3.79       0.06       4.18  
Total
  $ (0.06 )   $ 4.30     $ 1.26     $ 5.34  
                                 
Diluted–
                               
Continuing operations
  $ (0.10 )   $ 0.51     $ 1.20     $ 1.16  
Discontinued operations
    0.04       3.78       0.06       4.15  
Total
  $ (0.06 )   $ 4.29     $ 1.26     $ 5.31  
                                 
Dividends declared per share of common stock
  $ 0.355     $ 0.350     $ 1.065     $ 1.050  
The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.
 
7

 

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
   
September 30,
   
December 31,
   
September 30,
 
   
2009
   
2008
   
2008
 
   
(in thousands, except share amounts)
 
ASSETS
                 
Current assets:
                 
Cash and cash equivalents
  $ 137,681     $ 168,491     $ 152,457  
Restricted cash
    6             5,514  
Short-term investments
                6,310  
Receivables, net
    208,563       357,404       227,862  
Materials, supplies and fuel
    99,952       118,021       173,734  
Derivative assets
    56,951       73,068       84,758  
Income tax receivable, net
          20,269        
Deferred income taxes
    13,221       10,244        
Regulatory assets
    12,775       35,390       17,360  
Other current assets
    31,565       16,380       15,064  
Assets of discontinued operations
          246       322  
      560,714       799,513       683,381  
                         
Investments
    19,462       22,764       21,911  
                         
Property, plant and equipment
    2,891,102       2,705,492       2,615,627  
Less accumulated depreciation and depletion
    (795,378 )     (683,332 )     (566,191 )
      2,095,724       2,022,160       2,049,436  
Other assets:
                       
Goodwill
    353,734       359,290       400,959  
Intangible assets, net
    4,725       4,884        
Derivative assets
    5,438       9,799       1,500  
Regulatory assets
    120,677       143,705       51,122  
Other
    7,861       17,774       18,390  
      492,435       535,452       471,971  
    $ 3,168,335     $ 3,379,889     $ 3,226,699  
LIABILITIES AND STOCKHOLDERS’ EQUITY
                       
Current liabilities:
                       
Accounts payable
  $ 184,208     $ 288,907     $ 234,647  
Accrued liabilities
    150,042       134,940       140,981  
Derivative liabilities
    68,634       118,657       62,409  
Deferred income taxes
                592  
Accrued income taxes, net
    15,734             48,360  
Regulatory liabilities
    30,120       5,203       3,787  
Notes payable
    350,500       703,800       627,800  
Current maturities of long-term debt
    32,091       2,078       2,074  
Liabilities of discontinued operations
          88       124  
      831,329       1,253,673       1,120,774  
                         
Long-term debt, net of current maturities
    719,215       501,252       501,277  
                         
Deferred credits and other liabilities:
                       
Deferred income taxes
    228,715       223,607       240,654  
Derivative liabilities
    27,824       22,025       6,792  
Regulatory liabilities
    40,168       38,456       37,824  
Benefit plan liabilities
    135,027       159,034       44,465  
Other
    123,527       131,306       125,552  
      555,261       574,428       455,287  
                         
Stockholders’ equity:
                       
Common stock equity –
                       
Common stock $1 par value; 100,000,000 shares authorized;
                       
Issued 38,872,925; 38,676,054 and 38,490,315 shares,
                       
respectively
    38,873       38,676       38,490  
Additional paid-in capital
    588,556       584,582       580,601  
Retained earnings
    454,907       447,453       561,102  
Treasury stock at cost – 7,605; 40,183 and 40,059
                       
shares, respectively
    (197 )     (1,392 )     (1,419 )
Accumulated other comprehensive loss
    (19,609 )     (18,783 )     (29,545 )
Total common stockholders’ equity
    1,062,530       1,050,536       1,149,229  
Non-controlling interest in subsidiaries
                132  
Total equity
    1,062,530       1,050,536       1,149,361  
                         
    $ 3,168,335     $ 3,379,889     $ 3,226,699  
The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.
 
8

 

BLACK HILLS CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)

   
Nine Months Ended
 
   
September 30,
 
   
2009
   
2008
 
   
(in thousands)
 
Operating activities:
           
Net income
  $ 48,792     $ 204,028  
Income from discontinued operations, net of taxes
    (2,439 )     (159,486 )
Income from continuing operations
    46,353       44,542  
Adjustments to reconcile income from continuing operations
               
to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    92,535       70,999  
Impairment of long-lived assets
    43,301        
Derivative fair value adjustments
    19,647       (26,853 )
Gain on sale of operating assets
    (25,971 )      
Unrealized mark-to-market gain on interest rate swaps
    (37,775 )      
Deferred income taxes
    5,164       76,546  
Distributed (undistributed) earnings of associated companies
    3,424       (1,988 )
Allowance for funds used during construction – equity
    (5,284 )     (2,287 )
Other non-cash adjustments
    (4,782 )     (4,295 )
Change in operating assets and liabilities:
               
Materials, supplies and fuel, net of market adjustments
    23,210       (47,382 )
Accounts receivable and other current assets
    157,118       111,595  
Accounts payable and other current liabilities
    (101,902 )     (118,369 )
Regulatory assets and liabilities
    54,272       (30,204 )
Other operating activities
    (939 )     (10,403 )
Net cash provided by operating activities of continuing operations
    268,371       61,901  
Net cash provided by operating activities of discontinued operations
    2,556       18,184  
Net cash provided by operating activities
    270,927       80,085  
                 
Investing activities:
               
Property, plant and equipment additions
    (245,114 )     (219,350 )
Proceeds from sale of business operations
          835,316  
Proceeds from sale of ownership interest in plants
    84,661        
Payment for acquisition of net assets, net of cash acquired
          (937,606 )
Working capital adjustment of purchase price allocation on Aquila assets
    7,098        
Purchase of short-term investments
          (6,525 )
Other investing activities
    1,933       (698 )
Net cash used in investing activities of continuing operations
    (151,422 )     (328,863 )
Net cash used in investing activities of discontinued operations
          (28,966 )
Net cash used in investing activities
    (151,422 )     (357,829 )
                 
Financing activities:
               
Dividends paid
    (41,338 )     (40,189 )
Common stock issued
    2,338       2,611  
(Decrease) increase in short-term borrowings, net
    (353,300 )     590,800  
Long-term debt – issuances
    248,500        
Long-term debt – repayments
    (2,024 )     (130,276 )
Other financing activities
    (4,532 )     (72 )
Net cash (used in) provided by financing activities of continuing operations
    (150,356 )     422,874  
Net cash used in financing activities of discontinued operations
          (73,928 )
Net cash (used in) provided by financing activities
    (150,356 )     348,946  
                 
(Decrease) increase in cash and cash equivalents
    (30,851 )     71,202  
                 
Cash and cash equivalents:
               
Beginning of period
    168,532 (a)     81,255 (b)
End of period
  $ 137,681     $ 152,457  
                 
Supplemental disclosure of cash flow information:
               
Non-cash investing and financing activities-
               
Property, plant and equipment acquired with accrued liabilities
  $ 31,202     $ 25,549  
Cash paid during the period for-
               
Interest (net of amounts capitalized)
  $ 50,311     $ 29,748  
Income taxes (refunded) paid
  $ (23,311 )   $ 2,984  
_________________________
(a)
Includes less than $0.1 million of cash included in the assets of discontinued operations.
(b)
Includes approximately $4.4 million of cash included in the assets of discontinued operations.
The accompanying notes to condensed consolidated financial statements are an integral part of these condensed consolidated financial statements.
 
9

 

BLACK HILLS CORPORATION

Notes to Condensed Consolidated Financial Statements
(unaudited)
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2008 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,” “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 2008 Annual Report on Form 10-K filed with the SEC.  These financial statements include consideration of events through November 6, 2009.

Accounting methods historically employed require certain estimates as of interim dates.  The information furnished in the accompanying condensed quarterly financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the September 30, 2009, December 31, 2008 and September 30, 2008 financial information and are of a normal recurring nature.  Certain reclassifications have been made to prior period presentations to conform to the current year presentation but have no affect over the results of the prior period numbers.  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 nine months ended September 30, 2009, and our financial condition as of September 30, 2009 and December 31, 2008, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.  All earnings per share amounts discussed refer to diluted earnings per share unless otherwise noted.

On July 11, 2008, we completed the sale of seven of our IPP plants.  Amounts associated with the IPP plants divested in the IPP Transaction have been reclassified as discontinued operations for the quarter ended September 30, 2008.  See Note 19 for additional information.

On July 14, 2008, we completed the acquisition of a regulated electric utility in Colorado and regulated gas utilities in Colorado, Kansas, Nebraska and Iowa from Aquila.  Effective as of that date, the assets and liabilities, results of operations, and cash flows of the acquired utilities are included in our Condensed Consolidated Financial Statements.  See Note 17 for additional information.


 
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(2)
RECENTLY ADOPTED ACCOUNTING STANDARDS

FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Standard No. 162, ASC 105 (SFAS 168)

On July 1, 2009, the FASB Accounting Standards CodificationTM became the source of authoritative GAAP recognized by the FASB to be applied by non-governmental entities.  On the effective date of this Statement, the Codification superseded all then-existing non-SEC accounting and reporting standards.  All other non-SEC accounting literature not included or grandfathered in the Codification became non-authoritative.  This Statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009.

Following this Statement, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Task Force Abstracts.  Instead, it will issue Accounting Standards Updates.  The FASB will not consider Accounting Standards Updates as authoritative in their own right.  Accounting Standards Updates will serve only to update the Codification, provide background information about the guidance, and provide the basis for conclusions on the change(s) in the Codification.

Business Combinations, ASC 805 (SFAS 141(R))

The ASC for Business Combinations requires an acquiring entity to recognize the assets acquired, the liabilities assumed and any non-controlling interests in the acquiree at the acquisition date be measured at their fair values as of the acquisition date, with limited exceptions.  Acquisition-related costs will be expensed in the periods in which the costs are incurred or services are rendered.  If income tax liabilities are settled for an amount other than as previously recorded, the adjustment of any remaining liability would affect goodwill.  If such liabilities are adjusted subsequent to December 31, 2008, such adjustments will affect expense including income tax expense in the period of adjustment.  Costs to issue debt or equity securities shall be accounted for under other applicable GAAP.  These requirements apply prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008.  Effective January 1, 2009, any impact a business combination will have on our consolidated financial statements will depend on the nature and magnitude of any future acquisitions we consummate and the resolution of certain tax contingencies.

Fair Value Measurements and Disclosures, ASC 820 (SFAS 157 and FSP FAS 157-4)

The ASC for Fair Value Measurements and Disclosures defines fair value, establish a framework for measuring fair value in GAAP and expand disclosures about fair value measurements.  This does not expand the application of fair value accounting to any new circumstances, but applies the framework to other applicable GAAP that requires or permits fair value measurement.  We apply fair value measurements to certain assets and liabilities, primarily commodity derivatives within our Energy Marketing and Oil and Gas segments, interest rate swap instruments, and other miscellaneous derivatives.

On January 1, 2008, we discontinued our use of a “liquidity reserve” in valuing the total forward positions within our energy marketing portfolio.  This impact was accounted for prospectively as a change in accounting estimate and resulted in a $1.2 million after-tax benefit that was recorded within our unrealized marketing margins.  Unrealized margins are presented as a component of Operating revenues on the accompanying Condensed Consolidated Statements of Income.  Disclosures regarding the level of pricing observability associated with instruments carried at fair value are provided in Note 15.


 
11

 

Consolidation of Non-Controlling Interest, ASC 810 (SFAS 160)

The ASC for Consolidation of Non-Controlling Interest establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, changes in a parent’s ownership interest, and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated.  The ASC establishes disclosure requirements that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners.  These standards and disclosure requirements were effective January 1, 2009.

Non-controlling interest in the accompanying Condensed Consolidated Statements of Income and Balance Sheets represents the non-affiliated equity investors’ interest in Wygen Funding LP, a Variable Interest Entity as defined by ASC 810.  In June 2008, we purchased the non-controlling share.  Presentation of a non-controlling interest that we held until June 2008 was retrospectively applied as required, and had an immaterial overall effect.

Derivative and Hedging Disclosures, ASC 815 (SFAS 161)

The ASC for Derivative and Hedging Disclosures requires enhanced disclosures about derivative and hedging activities and their affect on an entity’s financial position, financial performance and cash flows.  ASC 815 encourages, but does not require, disclosures for earlier periods presented for comparative purposes at initial adoption.  Required disclosures for periods subsequent to January 1, 2009 are provided in Note 13 and Note 14.

Subsequent Events, ASC 855 (SFAS 165)

The ASC for Subsequent Events establishes general standards of accounting for and disclosures of events that occur after the balance sheet date, but before financial statements are issued or are available to be issued.  These standards and disclosures were applied to our financial statements issued after June 15, 2009.

Financial Instruments, ASC 825 (FSP FAS 107-1)

The ASC for Financial Instruments requires public companies to provide more frequent disclosures about the fair value of their financial instruments for interim and annual periods ending after June 15, 2009.  These disclosures are included in Note 15.

Earnings Per Share, ASC 260 (FSP EITF 03-6-1)

The ASC for Earnings per share states that unvested share-based payment awards that contain non-forfeitable rights to dividends are “participating securities” as defined and should be included in computing EPS using the two-class method.  The two-class method is an earnings allocation method for computing EPS and determines EPS based on dividends declared on common stock and participating securities in any undistributed earnings.  As of January 1, 2009, we prepared our current and prior period EPS computation in accordance with the guidance in ASC 260 and there was no impact on our EPS.

 
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(3)
RECENTLY ISSUED ACCOUNTING STANDARDS

SEC Release No. 33-8995

On December 29, 2008, the SEC issued Release No. 33-8995, amending the existing Regulation S-K and Regulation S-X requirements for reporting the quantity and value of oil and gas reserves 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 pricing used to determine reserves.  Companies must use a 12-month average price.  The average is calculated using unweighted average of the first-day-of-the-month price for each of the 12 months that make up the reporting period.  The amendment is effective for annual reporting periods ending on December 31, 2009, and early adoption is prohibited.  We are currently assessing the impact that the adoption will have on our disclosures, operating results, financial position and cash flows.

Consolidation of Variable Interest Entities, ASC 810-10-15 (SFAS 167)

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 will require 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.  We are currently assessing the impact that the adoption of this standard will have on our financial condition, results of operations, and cash flows.

Compensation – Retirement Benefits, ASC 715 (FSP FAS 132(R)-1)

The ASC for Compensation – Retirement Benefits provides guidance on an employer’s disclosures about plan assets in a defined benefit pension or other postretirement plan to provide users of financial statements with an understanding of:

· How investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies;
 
· The major categories of plan assets;
 
· The input and valuation techniques used to measure the fair value of plan assets;
 
· The effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period; and
 
· Significant concentrations of risk within plan assets.

These disclosures are effective for fiscal years ending after December 15, 2009.

 

 
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(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):

   
September 30,
   
December 31,
   
September 30,
 
Major Classification
 
2009
   
2008
   
2008
 
                   
Materials and supplies
  $ 31,650     $ 32,580     $ 32,565  
Fuel – Electric Utilities
    7,234       10,058       11,497  
Natural gas in storage – Gas Utilities
    29,943       59,529       74,407  
Gas and oil held by Energy
                       
Marketing*
    31,125       15,854       55,265  
                         
Total materials, supplies and fuel
  $ 99,952     $ 118,021     $ 173,734  
___________________________
 
* As of September 30, 2009, December 31, 2008 and September 30, 2008, market adjustments related to natural gas held by Energy Marketing and recorded in inventory were $(1.3) million, $(9.4) million and $(15.1) 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 in the future.  Natural gas volumes held as of September 30, 2009, December 31, 2008 and September 30, 2008 include 8.2 Bcf, 3.6 Bcf, and 7.9 Bcf.  Crude oil volumes held as of September 30, 2009, December 31, 2008 and September 30, 2008 include 71,000 Bbl, 54,000 Bbl, and 64,000 Bbl, respectively.

Natural gas in storage at our Gas Utilities represents primarily gas purchased for use by our customers.  The natural gas in storage fluctuates with the seasonality of our business and the commodity price of natural gas.  Although volumes held in storage by us have varied due to season, there has been a notable price decrease during 2009 and 2008.  Volumes held as of September 30, 2009, December 31, 2008 and September 30, 2009 include 8.6 Bcf, 7.3 Bcf and 8.6 Bcf, respectively.

(5)
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 allowances by considering such factors as historical experience, credit-worthiness, the age of the receivable balances and current economic conditions that may affect the ability to pay.

Following is a summary of receivables (in thousands):

   
September 30,
   
December 31,
   
September 30,
 
   
2009
   
2008
   
2008
 
                   
Accounts receivable
  $ 214,065     $ 364,155     $ 233,939  
Less allowance for doubtful accounts
    5,502       6,751       6,077  
Net accounts receivable
  $ 208,563     $ 357,404     $ 227,862  


 
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(6)
NOTES PAYABLE AND LONG-TERM DEBT

Debt Offering

On May 14, 2009, we issued a $250 million aggregate principal amount of senior unsecured notes due in 2014 pursuant to a public offering.  The notes were priced at par and carry a fixed interest rate of 9%.  We received proceeds of $248.5 million, net of underwriting fees.  Proceeds were used to pay down the Acquisition Facility.  Deferred financing costs related to the offering of $2.3 million were capitalized and will be amortized over the life of the debt.  Amortization of these deferred financing costs is included in interest expense and for the three and nine months ended September 30, 2009 was approximately $0.1 million and $0.2 million, respectively.

Acquisition Facility

In May 2007, we entered into a senior unsecured $1 billion Acquisition Facility with ABN AMRO Bank N.V., as administrative agent, and other banks to fund the Aquila Transaction.  On July 14, 2008, in conjunction with the completion of the purchase of the Aquila properties, we executed a single draw of $382.8 million under the Acquisition Facility.  The loan was originally scheduled to mature on February 5, 2009.  However, on December 18, 2008, we amended the facility to extend the maturity date to December 29, 2009.  The Acquisition Facility was repaid in the second quarter of 2009 using:  (1) net proceeds from the sale of a 25% ownership interest in the Wygen III plant of $30.2 million; (2) net proceeds from the $250 million public debt offering; and (3) $104.6 million from borrowings under the Corporate Credit Facility.  Approximately $3.6 million of unamortized deferred financing costs were fully expensed in the second quarter of 2009 in conjunction with the repayment of this facility.  Therefore, amortization of the deferred financing costs associated with this facility is included in Interest expense on the accompanying Condensed Consolidated Statements of Income and for the nine months ended September 30, 2009 was $4.8 million.

Corporate Credit Facility

Our consolidated net worth was $1,062.5 million at September 30, 2009, which was approximately $254.0 million in excess of the net worth we are required to maintain under the Corporate Credit Facility.  At September 30, 2009, our long-term debt ratio was 40.4%, our total debt coverage leverage ratio (long-term debt and short-term debt) was 50.9%, and our recourse leverage ratio was approximately 55.2%.  Our interest expense coverage ratio for the twelve month period ended September 30, 2009 was 3.7 to 1.0.  We were in compliance with our covenants as of September 30, 2009.

Enserco Credit Facility

On May 8, 2009, Enserco entered into an agreement for a $240 million committed credit facility.  Societe Generale, Fortis Capital Corp., and BNP Paribas were co-lead arranger banks.  On May 27, 2009, Enserco entered into an agreement for an additional $60 million of commitments under the credit facility with three new participating banks: Calyon, Rabobank and RZB Finance.  This credit facility expires on May 7, 2010 and is a borrowing base line of credit, which allows for the issuance of letters of credit and for borrowings.  Maximum borrowings under the facility are subject to a sublimit of $50 million.  Borrowings under this facility are available under a base rate option or a Eurodollar option.  The base rate option borrowing rate is 2.75% plus the higher of: (i) 0.5% above the Federal Funds Rate, or (ii) the prime rate established by Fortis Bank S.A./N.V.  The Eurodollar option borrowing rate is 2.75% plus the higher of the Eurodollar Rate or the reference bank cost of funds.


 
15

 

At September 30, 2009, $71.7 million of letters of credit were issued and outstanding under this facility and there were no cash borrowings outstanding.  Deferred financing costs of $1.9 million were capitalized and are amortized over the life of the facility.  Amortization of these deferred financing costs is included in interest expense and for the three and nine months ended September 30, 2009 was approximately $0.1 million and $0.9 million, respectively.

Industrial Development Revenue Bonds

Cheyenne Light completed a $17 million weekly variable rate refunding bond issuance on September 3, 2009.  The new issue replaces existing debt and  the bond credit support structure from an AMBAC Financial Group insurance policy to a direct-pay letter of credit issued by Wells Fargo Bank.  Laramie County, Wyoming was the tax-exempt conduit issuer for this transaction.  The bonds were issued in two series:  a $10.0 million series maturing March 1, 2027 and a $7.0 million series maturing September 1, 2021.  The principal amounts and maturity dates did not change from the original financing.  The initial variable weekly rate was set at 0.4%.  Excluding the letter of credit fees and other issuance costs, the current all-in rate is approximately 2.65%.

 (7)
GUARANTEES

Guarantees to GE

We issued two guarantees for up to $37.9 million each to GE for payment obligations arising from a contract to purchase two LMS100 natural gas turbine generators by Colorado Electric, which will be used in meeting a portion of the capacity and energy needs of our Colorado Electric customers.  These are continuing guarantees which terminate upon payment in full of the purchase price to GE.  Payments are scheduled based upon estimated construction milestone dates with the final payment due October 27, 2010.

Surety Bonds Issued to MEAN

On January 20, 2009, we issued a surety bond for $9.2 million to MEAN to secure operating performance obligations related to the Wygen I ownership agreement.  Black Hills Wyoming and MEAN entered into the ownership agreement when MEAN acquired a 23.5% ownership interest in the Wygen I plant.  The surety bond and guarantees expire on December 31, 2009.

Enserco

We have guaranteed up to $7.0 million of the obligations of Enserco under an agency agreement whereby Enserco provides services to structure certain transactions involving the buying, selling, transportation and storage of natural gas on behalf of another energy company.  The guarantee expires in July 2010.

 
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(8)
EARNINGS PER SHARE

Basic earnings per share from continuing operations is 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 is as follows (in thousands):

Period ended September 30, 2009
 
Three Months
   
Nine Months
 
         
Average
         
Average
 
   
Income
   
Shares
   
Income
   
Shares
 
                         
(Loss) income from continuing
                       
operations
  $ (3,853 )         $ 46,353        
                             
Basic earnings
    (3,853 )     38,643       46,353       38,584  
Dilutive effect of:
                               
Restricted stock
                      60  
Other
                      2  
Diluted earnings
  $ (3,853 )     38,643     $ 46,353       38,646  


Period ended September 30, 2008
 
Three Months
   
Nine Months
 
         
Average
         
Average
 
   
Income
   
Shares
   
Income
   
Shares
 
                         
Income from continuing operations
  $ 19,522           $ 44,542        
                             
Basic earnings
    19,522       38,307       44,542       38,145  
Dilutive effect of:
                               
Stock options
          42             62  
Estimated contingent shares issuable
                               
for prior acquisition
                      132  
Restricted stock
          72             70  
Other
          4             21  
Diluted earnings
  $ 19,522       38,425     $ 44,542       38,430  

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
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Options to purchase common stock
    374       151       484       99  


 
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(9)
OTHER COMPREHENSIVE INCOME

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

   
Three Months Ended
 
   
September 30,
 
   
2009
   
2008
 
             
Net (loss) income
  $ (2,180 )   $ 164,911  
Other comprehensive income (loss),
               
net of tax:
               
Minimum pension liability adjustments (net of
               
tax of $(1,999))
    3,671        
Fair value adjustment on derivatives
               
designated as cash flow hedges
               
(net of tax of $5,670 and $(14,030),
               
respectively)
    (10,311 )     25,824  
Reclassification adjustments on cash
               
flow hedges settled and included in
               
net income (net of tax of $(1,948)
               
and $(1,539), respectively)
    3,446       2,761  
Unrealized gain on available for sale
               
securities (net of tax of $17 in 2008)
          (32 )
                 
Comprehensive (loss) income attributable to
               
Black Hills Corporation
  $ (5,374 )   $ 193,464  


 
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Nine Months Ended
 
   
September 30,
 
   
2009
   
2008
 
             
Net income
  $ 48,792     $ 204,028  
Other comprehensive income (loss),
               
net of tax:
               
Minimum pension liability adjustment
               
(net of tax of $(1,999))
    3,671        
Fair value adjustment on derivatives
               
designated as cash flow hedges
               
(net of tax of $8,598 and $6,449,
               
respectively)
    (15,106 )     (11,951 )
Reclassification adjustments on cash
               
flow hedges settled and included in
               
net income (net of tax of $(6,008)
               
and $(3,952), respectively)
    10,609       7,071  
Unrealized loss on available for sale
               
securities (net of tax of $58)
          (157 )
                 
Total comprehensive income
    47,966       198,991  
                 
Comprehensive loss attributable to
               
non-controlling interest
          (130 )
                 
Comprehensive income attributable to
               
Black Hills Corporation
  $ 47,966     $ 198,861  

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

   
September 30,
   
December 31,
   
September 30,
 
   
2009
   
2008
   
2008
 
                   
Derivatives designated as cash flow hedges
  $ (9,037 )   $ (4,522 )   $ (23,168 )
Employee benefit plans
    (10,456 )     (14,127 )     (6,115 )
Amount from equity-method investees
    (116 )     (134 )     (122 )
Unrealized loss on available-for-sale
                       
securities
                (140 )
Total
  $ (19,609 )   $ (18,783 )   $ (29,545 )


 
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(10)
COMMON STOCK

Other than the following transactions, we had no material changes in our common stock, as reported in Note 10 of the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K.

Equity Compensation Plans

· We granted 78,136 target performance shares to certain officers and business unit leaders for the January 1, 2009 through December 31, 2011 performance period.  Actual shares are not issued until the end of the Performance Plan period (December 31, 2011).  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, our stock price must also increase during the performance period.  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 $29.20 per share.
 
· We issued 47,331 shares of common stock under the 2008 short-term incentive compensation plan during the nine months ended September 30, 2009.  Pre-tax compensation cost related to the award was approximately $1.6 million, which was accrued for in 2008.
 
· We granted 84,376 restricted common shares during the nine months ended September 30, 2009.  The pre-tax compensation cost related to the awards of restricted stock and restricted stock units of approximately $2.3 million will be recognized over the three-year vesting period.
 
· 5,000 stock options were exercised during the nine months ended September 30, 2009 at a weighted-average exercise price of $24.06 per share providing $0.1 million of proceeds to the Company.

Total compensation expense recognized for all equity compensation plans for the three months ended September 30, 2009 and 2008 was $1.1 million and $0.3 million, respectively, and for the nine months ended September 30, 2009 and 2008 was $2.9 million and $1.0 million, respectively.

As of September 30, 2009, total unrecognized compensation expense related to non-vested stock awards was $5.8 million and is expected to be recognized over a weighted-average period of 2.0 years.


 
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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 111,753 new shares at a weighted-average price of $20.91 during the nine months ended September 30, 2009.  At September 30, 2009, 327,562 shares of unissued common stock were available for future offering under the Plan.

Dividend Restrictions

Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries.  The cash to pay dividends to our shareholders is derived from these cash flows.  As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries.

Our utility subsidiaries are generally limited to the amount of dividends allowed by state regulatory authorities to be paid to us as a utility holding company and also may have further restrictions under the Federal Power Act.  As of September 30, 2009, the restricted net assets at our Electric and Gas Utilities were approximately $79.2 million.

In August 2009, one of the covenants to the Enserco Credit Facility was amended to temporarily increase the allowable rolling twelve month Net Cumulative Loss as calculated on a Non-GAAP basis and temporarily restrict all dividends or loans to the Company.   In addition to the borrowing base structure which requires Enserco to maintain certain levels of tangible net worth and net working capital, 100% of Enserco’s net assets are now restricted.  The Company expects this to be the case through November 30, 2009. Therefore, upon review of these covenants at September 30, 2009, restricted net assets at Enserco total $214.3 million for this stand-alone Enserco Credit Facility.


 
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(11)
EMPLOYEE BENEFIT PLANS

We have three non-contributory defined benefit pension plans (“Plans”) and three Postretirement Healthcare Plans (“Healthcare 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.

Defined Benefit Pension Plans

In July 2009, the Board of Directors approved a resolution to freeze two of our Defined Benefit Pension Plans to new participants and to transfer certain existing participants to an age and service based defined contribution plan, effective January 1, 2010.  The first plan covers employees of Black Hills Service Company, Black Hills Power, WRDC and BHEP and the second plan covers employees of Black Hills Energy.  Plan assets and obligations were revalued July 31, 2009 in conjunction with the curtailment of these plans and we recognized a pre-tax curtailment expense of approximately $0.3 million in the three months ended September 30, 2009.

The following table sets forth the projected benefit obligation as of December 31, 2008 and July 31, 2009.  The July 31, 2009 projected benefit obligation reflects the curtailment of the two plans and includes the Cheyenne Light pension plan projected benefit obligation as of its December 31, 2008 measurement date:

   
Defined Benefit
 
   
Pension Plans
 
   
at July 31, 2009
 
   
(in thousands)
 
       
Change in benefit obligation:
     
       
Projected benefit obligation at
     
December 31, 2008
  $ 242,545  
         
Service cost
    4,743  
Interest cost
    8,713  
Actuarial loss
    453  
Amendments
    20  
Benefits paid
    (5,159 )
Benefits curtailed
    (8,033 )
Change in discount rate
    (1,613 )
Net increase (decrease)
    (876 )
Projected benefit obligation at
       
July 31, 2009
  $ 241,669  


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

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Service cost
  $ 1,877     $ 1,547     $ 5,736     $ 3,055  
Interest cost
    3,679       3,165       11,036       5,625  
Expected return on plan assets
    (3,638 )     (3,644 )     (10,553 )     (6,790 )
Prior service cost
    25       41       108       123  
Net loss
    637             2,140        
Curtailment expense
    320             320        
                                 
Net periodic benefit cost
  $ 2,900     $ 1,109     $ 8,787     $ 2,013  

We made a $0.5 million contribution to the Plans in the first quarter of 2009, a $3.9 million contribution to the Plans in the second quarter of 2009, and a $12.5 million contribution to the Plans during the third quarter of 2009.  There are no additional contributions anticipated to be made to the Plans for 2009.  We anticipate additional contributions totaling approximately $7.7 million in 2010.

Non-pension Defined Benefit Postretirement Healthcare Plans

Employees who are participants in our Healthcare Plans and who meet certain eligibility requirements are entitled to certain postretirement healthcare benefits.

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

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Service cost
  $ 260     $ 226     $ 780     $ 476  
Interest cost
    542       503       1,626       937  
Expected return on plan assets
    (56 )     (43 )     (168 )     (43 )
Prior service benefit
    (22 )           (66 )      
Net transition obligation
    15       15       45       45  
Net gain
    (8 )     (20 )     (24 )     (60 )
                                 
Net periodic benefit cost
  $ 731     $ 681     $ 2,193     $ 1,355  

We anticipate that we will make aggregate contributions to the Healthcare Plans for the 2009 and 2010 fiscal years of approximately $2.8 million and $3.0 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 and $0.3 million for the three and nine month periods ended September 30, 2009.


 
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Supplemental Non-qualified Defined Benefit Plans

Additionally, we have various supplemental retirement plans for key executives (“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
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Service cost
  $ 117     $ 112     $ 351     $ 336  
Interest cost
    344       311       1,032       933  
Prior service cost
    1       3       3       9  
Net loss
    147       142       441       426  
                                 
Net periodic benefit cost
  $ 609     $ 568     $ 1,827     $ 1,704  

We anticipate that we will make aggregate contributions to the Supplemental Plans for the 2009 fiscal year of approximately $1.0 million.  The contributions are expected to be made in the form of benefit payments.

 
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(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 September 30, 2009, substantially all of our operations and assets are located within the United States.

The Utilities Group includes two reportable segments:  Electric Utilities and Gas Utilities.  We manage our electric and gas utility businesses predominantly by state; however, because our electric utilities and our gas utilities have similar economic characteristics, we aggregate our electric (and combination) utility businesses in the Electric Utilities reporting segment and our gas utility businesses in the Gas Utilities reporting segment.  Electric Utilities include the operating results of the regulated electric utility operations of Black Hills Power and Colorado Electric, and the regulated electric and natural gas utility operations of Cheyenne Light.  The natural gas operations within our combination utility, Cheyenne Light, have historically provided relatively stable gross margins and overall financial results.  Periodic variances are therefore rarely expected to significantly impact the operating results for the Electric Utilities segment.  Presentation of prior periods has been adjusted to reflect the combination of Black Hills Power and Cheyenne Light within the Electric Utilities segment.  Gas Utilities, acquired on July 14, 2008, consists of the operating results of the regulated natural gas utility operations of Colorado Gas, Iowa Gas, Kansas Gas, and Nebraska Gas.

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.  Our Power Generation segment has also 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 and 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 and related services primarily in the western and central regions of the United States and Canada.

Segment information follows the same accounting policies as described in Note 1 of the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K.  In accordance with accounting standards for regulated operations, intercompany fuel sales to the regulated utilities are not eliminated.


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

   
Three Months Ended
 
   
September 30, 2009
   
September 30, 2008
 
   
External
   
Inter-segment
   
External
   
Inter-segment
 
   
Operating
   
Operating
   
Operating
   
Operating
 
   
Revenues
   
Revenues
   
Revenues
   
Revenues
 
                         
Utilities:
                       
Electric Utilities
  $ 128,943     $ 223     $ 136,644     $ 334  
Gas Utilities
    62,691             83,937        
Non-regulated Energy:
                               
Oil and Gas
    17,887             25,438        
Power Generation
    7,538             11,704        
Coal Mining
    8,284       6,903       8,103       7,928  
Energy Marketing
    (5,259 )           19,196        
Inter-segment eliminations
          (1,411 )           (1,392 )
                                 
Total
  $ 220,084     $ 5,715     $ 285,022     $ 6,870  


   
Nine Months Ended
 
   
September 30, 2009
   
September 30, 2008
 
   
External
   
Inter-segment
   
External
   
Inter-segment
 
   
Operating
   
Operating
   
Operating
   
Operating
 
   
Revenues
   
Revenues
   
Revenues
   
Revenues
 
                         
Utilities:
                       
Electric Utilities
  $ 384,607     $ 653     $ 329,512     $ 1,004  
Gas Utilities
    412,366             83,937        
Non-regulated Energy:
                               
Oil and Gas
    52,227             85,770        
Power Generation
    22,372             29,079        
Coal Mining
    23,967       19,115       23,979       17,946  
Energy Marketing
    9,299             30,465        
Inter-segment eliminations
          (3,516 )           (3,677 )
                                 
Total
  $ 904,838     $ 16,252     $ 582,742     $ 15,273  


 
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Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Income (loss) from continuing
                       
operations
                       
Utilities:
                       
Electric Utilities
  $ 10,537     $ 10,765     $ 24,395     $ 30,485  
Gas Utilities
    (3,484 )     (1,854 )     14,223       (1,854 )
Non-regulated Energy:
                               
Oil and Gas
    (149 )     1,517       (25,740 )(a)     11,266  
Power Generation
    575       3,197       18,487 (b)     1,828  
Coal Mining
    2,256       1,092       2,575       3,217  
Energy Marketing
    (4,404 )     6,902       (1,156 )     7,565  
Corporate
    (9,110 )(c)     (2,061 )     13,205 (c)     (7,889 )
Inter-segment eliminations
    (74 )     (36 )     364       (76 )
                                 
Total
  $ (3,853 )   $ 19,522     $ 46,353     $ 44,542  
_________________________
(a)  
As a result of lower natural gas prices at March 31, 2009, we recorded a non-cash ceiling test impairment of oil and gas assets included in the Oil and Gas segment in the first quarter of 2009.  The lower prices at March 31, 2009 resulted in a $27.8 million after-tax decrease in the full cost accounting method’s ceiling limit for capitalized oil and gas property costs.  The write-down in the net carrying value of our natural gas and crude oil properties was recorded as Impairment of long-lived assets and was based on the March 31, 2009 NYMEX price of $3.63 per Mcf, adjusted to $2.23 per Mcf at the wellhead, for natural gas; and NYMEX price of $49.66 per barrel, adjusted to $45.32 per barrel at the wellhead, for crude oil.
(b)  
Includes $16.9 million after-tax gain on sale to MEAN of 23.5% ownership interest in Wygen I power generation facility.
(c)  
Includes $8.7 million net mark-to-market loss for the three months ended September 30, 2009 and a $37.8 million net mark-to-market gain for the nine months ended September 30, 2009.

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009