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EX-10 - ENSERCO CREDIT AGREEMENT - BLACK HILLS CORP /SD/ex_10.htm
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EX-32.2 - SECTION 1350 CFO CERTIFICATION - BLACK HILLS CORP /SD/ex32_2.htm
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EX-32.1 - SECTION 1350 CEO CERTIFICATION - BLACK HILLS CORP /SD/ex32_1.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.


 
10

 


(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.

 
12

 


(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.

 

 
13

 


(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  


 
14

 


(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.

 
16

 


(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  


 
17

 


(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  


 
18

 


   
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 )


 
19

 


(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.


 
20

 

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.


 
21

 


(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  


 
22

 

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.


 
23

 

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.

 
24

 


(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.


 
25

 

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  


 
26

 


   
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
   
2008
   
2009
   
2008
 
                         
Depreciation, depletion and amortization
                       
Utilities:
                       
Electric Utilities
  $ 10,682     $ 10,630     $ 32,606     $ 26,269  
Gas Utilities
    7,366       6,567       23,045       6,567  
Non-regulated Energy:
                               
Oil and Gas
    7,142       9,401       22,281       25,761  
Power Generation
    961       1,111       2,812       3,504  
Coal Mining
    3,502       2,658       11,076       6,510  
Energy Marketing
    122       159       384       527  
Corporate
    49       299       331       1,861  
Total
  $ 29,824     $ 30,825     $ 92,535     $ 70,999  


 
27

 


   
September 30,
   
December 31,
   
September 30,
 
   
2009
   
2008
   
2008
 
Total assets
                 
Utilities:
                 
Electric Utilities
  $ 1,592,852     $ 1,485,040     $ 1,284,150  
Gas Utilities
    619,855       733,377       753,649  
Non-regulated Energy:
                       
Oil and Gas
    340,046       403,583       465,118  
Power Generation
    120,426       155,819       145,784  
Coal Mining
    79,796       75,872       70,582  
Energy Marketing
    341,720       339,543       364,626  
Corporate
    73,640       186,409       142,468  
Discontinued operations
          246       322  
Total
  $ 3,168,335     $ 3,379,889     $ 3,226,699  


(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 and natural gas reserves and production, and fuel procurement for certain of our gas-fired generation assets;
 
· Interest rate risk associated with variable rate credit facilities;
 
· Interest rate risk associated with 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 2 of the Notes to our Consolidated Financial Statements in our 2008 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 and Note 15.


 
28

 

Trading Activities

Natural Gas and Crude Oil Marketing

We have a natural gas and crude oil 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 and crude oil 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 and crude oil 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.  ASC 940-325-S99 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 and crude oil 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, ASC 815 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 and crude oil 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 gas marketing Risk Management Policies and Procedures as approved by our Executive Risk Committee.  Our contracts do not include credit risk-related contingent features.

We use a number of quantitative tools to measure, monitor and limit our exposure to market risk in our natural gas and oil 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.


 
29

 

The contract or notional amounts and terms of our natural gas and crude oil marketing activities and derivative commodity instruments are as follows:

   
Outstanding at
   
Outstanding at
   
Outstanding at
 
   
September 30, 2009
   
December 31, 2008
   
September 30, 2008
 
         
Latest
         
Latest
         
Latest
 
   
Notional
   
Expiration
   
Notional
   
Expiration
   
Notional
   
Expiration
 
   
Amounts
   
(months)
   
Amounts
   
(months)
   
Amounts
   
(months)
 
(in thousands of MMBtus)
                                   
Natural gas basis
                                   
swaps purchased
    246,175       25       187,368       34       184,099       37  
Natural gas basis
                                               
swaps sold
    242,246       25       186,710       34       180,322       37  
Natural gas fixed-for-float
                                               
swaps purchased
    89,371       18       85,412       24       73,872       24  
Natural gas fixed-for-float
                                               
swaps sold
    94,619       18       90,171       24       84,786       24  
Natural gas physical
                                               
purchases
    150,698       18       131,937       16       146,273       18  
Natural gas physical sales
    179,134       18       145,706       21       182,512       24  
Natural gas options
                                               
purchased
    1,227       6       1,440       3       3,958       6  
Natural gas options sold
    1,227       6       1,440       3       3,958       6  


 
Outstanding at
 
Outstanding at
 
Outstanding at
 
 
September 30, 2009
 
December 31, 2008
 
September 30, 2008
 
       
Latest
       
Latest
       
Latest
 
 
Notional
   
Expiration
 
Notional
   
Expiration
 
Notional
   
Expiration
 
 
Amounts
   
(months)
 
Amounts
   
(months)
 
Amounts
   
(months)
 
                                     
(in thousands of Bbls)
                                   
Crude oil physical
                                   
purchases
    3,263       4       7,446       12       5,994       15  
Crude oil physical sales
    3,126       4       6,251       12       4,690       15  
Crude oil swaps/options
                                               
purchased
                435       24       465       24  
Crude oil swaps/options
                                               
sold
    64       3       502       24       525       24  


 
30

 

Derivatives and certain natural gas and crude oil marketing activities were marked to fair value on September 30, 2009, December 31, 2008 and September 30, 2008, 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):

   
September 30,
   
December 31,
   
September 30,
 
   
2009
   
2008
   
2008
 
                   
Current derivative assets
  $ 38,650     $ 52,723     $ 66,807  
Non-current derivative assets
  $ 4,547     $ (145 )   $ (1,140 )
Current derivative liabilities
  $ 14,668     $ 15,553     $ 22,292  
Non-current derivative liabilities
  $ 646     $ (777 )   $ (227 )
Cash collateral (receivable)/payable included
                       
in derivative assets/liabilities(a)
  $ (4,829 )   $ 16,315     $ 1,789  
Unrealized gain
  $ 23,054     $ 54,117     $ 45,391  
____________________________
(a)  
A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.  When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between us and a counterparty.  Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. At September 30, 2009, we had the right to reclaim cash collateral of $4.8 million.  At December 31, 2008 and September 30, 2008, we had an obligation to return cash collateral of $16.3 million and $1.8 million, respectively.

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 September 30, 2009, December 31, 2008 and September 30, 2008, the market adjustments recorded in inventory were $(1.3) million, $(9.4) million and $(15.1) million, respectively.

 
31

 

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 September 30, 2009, December 31, 2008 and September 30, 2008, 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, properly documented 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 was reported in other comprehensive income and the ineffective portion was reported in earnings.

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

   
September 30, 2009
   
December 31, 2008
   
September 30, 2008
 
   
Crude Oil
   
Natural Gas
   
Crude Oil
   
Natural Gas
   
Crude Oil
   
Natural Gas
 
   
Swaps/Options
   
Swaps
   
Swaps/Options
   
Swaps
   
Swaps/Options
   
Swaps
 
                                     
Notional*
    450,000       9,448,050       435,000       8,523,500       465,000       9,231,000  
Maximum terms in
                                               
years**
    0.25       0.75       0.25       1.00       0.25       1.08  
Current derivative assets
  $ 5,091     $ 8,607     $ 7,674     $ 11,828     $ 1,309     $ 7,391  
Non-current derivative
                                               
assets
  $ 128     $ 241     $ 3,464     $ 3,749     $ 909     $ 1,632  
Current derivative
                                               
liabilities
  $     $ 1,079     $     $     $ 3,955     $ 236  
Non-current derivative
                                               
liabilities
  $ 1,895     $ 1,934     $ 10     $ 297     $ 1,268     $ 165  
Pre-tax accumulated
                                               
other comprehensive
                                               
income (loss) included
                                               
in balance sheet
  $ 2,840     $ 5,835     $ 9,642     $ 15,280     $ (4,308 )   $ 8,622  
Earnings
  $ 484     $     $ 1,486     $     $ 1,303     $  
___________________________
   *
Crude in Bbls, gas in MMBtu.
 **
Refers to the term of the derivative instrument.  Assets and liabilities are classified as current/non-current based on the timing of the hedged transaction and the corresponding settlement of the derivative instrument.

Based on September 30, 2009 market prices, a $9.7 million gain would be realized and reported in pre-tax earnings during the next twelve months related to hedges of production.  Estimated and actual realized gains will likely change during the next twelve months as market prices change.

 
32

 

Regulated Gas Utilities

Gas Hedges

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

The contract or notional amounts and terms of our natural gas derivative commodity instruments are as follows:

   
Outstanding at
   
Outstanding at
   
Outstanding at
 
   
September 30, 2009
   
December 31, 2008
   
September 30, 2008
 
         
Latest
         
Latest
         
Latest
 
   
Notional
   
Expiration
   
Notional
   
Expiration
   
Notional
   
Expiration
 
   
Amounts*
   
(months)
   
Amounts*
   
(months)
   
Amounts*
   
(months)
 
                                     
Natural gas futures purchased
    9,790       18       1,290       3       2,730       6  
Natural gas options purchased
    3,870       6       3,990       3       8,760       6  
Natural gas options sold
                820       3       1,800       6  
Natural gas basis swaps
                                               
purchased
    378       6                          
________________________
*gas in thousands of MMBtus


 
33

 

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

   
September 30,
   
December 31,
   
September 30,
 
   
2009
   
2008
   
2008
 
                   
Current derivative assets(a)
  $ 4,603     $ 4,224     $ 9,424  
Non-current derivative assets
  $ 522     $     $  
Current derivative liabilities
  $     $ 2,924     $ 5,241  
Non-current derivative liabilities
  $ 75     $     $  
Net unrealized (gain) loss included in
                       
regulatory assets
  $ (1,105 )   $ 11,668     $ 17,991  
Cash collateral included in derivative
                       
assets/liabilities(b)
  $ (1,840 )   $ (8,744 )   $ (12,750 )
__________________________
(a)
Includes option premium of $2.1 million, $4.2 million and $9.4 million at September 30, 2009, December 31, 2008 and September 30, 2008, respectively, which will be recorded as a regulatory asset upon settlement of the options.
(b)
A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.  When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between us and a counterparty.  Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement.  At September 30, 2009, December 31, 2008 and September 30, 2008, we had the right to reclaim cash collateral of $1.8 million, $8.7 million and $12.8 million, respectively.

Weather Derivatives

As approved in the State of Iowa, Iowa Gas uses a weather derivative to mitigate the effect of fluctuations from normal weather, but not for trading or speculative purposes.  Accounting standards for derivatives require that weather derivatives are accounted for by recording an asset or liability for the difference between the actual and contracted threshold cooling or heating degree days in the period, multiplied by the contract price.  Any gains and losses recorded on the contracts are recorded as regulatory assets or regulatory liabilities.  Contracts totaling $0.5 million are included in Other current assets on the accompanying Condensed Consolidated Balance Sheet as of September 30, 2009.


 
34

 

Fuel in Storage

At our Electric Utilities, we occasionally hold natural gas in storage for use as fuel for generating electricity with our gas-fired combustion turbines.  To minimize associated price risk and seasonal storage level requirements, we occasionally utilize various derivative instruments.  These transactions are marked-to-market, designated as cash flow hedges, and recorded in Derivative liabilities, current and Accumulated other comprehensive income on the accompanying Condensed Consolidated Balance Sheet.  Gains or losses on these transactions will be recorded in gross margins upon settlement.

On September 30, 2009, we had the following swaps and related balances (dollars, in thousands):

Notional*
    232,500  
Maximum terms in months
    12  
Current derivative asset
  $  
Non-current derivative asset
  $  
Current derivative liability
  $ 42  
Non-current derivative liability
  $  
Pre-tax accumulated other comprehensive income
  $ 42  
Unrealized gain
  $  
__________________________________
*
Gas in MMBtus


 
35

 

Financing Activities

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

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

   
September 30, 2009
   
December 31, 2008
   
September 30, 2008
 
   
Designated
Interest Rate
Swaps
   
Interest Rate
Swaps*
   
Designated
Interest Rate
Swaps
   
Interest Rate
Swaps*
   
Designated
Interest Rate
Swaps
   
Designated
Interest Rate
Swaps
 
                                     
Current notional amount
  $ 150,000     $ 250,000     $ 150,000     $ 250,000     $ 150,000     $ 250,000  
Weighted average fixed
                                               
interest rate
    5.04 %     5.67 %     5.04 %     5.67 %     5.04 %     5.67 %
Maximum terms in
                                               
years
    7.25       1.25     $ 8.00     $ 1.00     $ 8.00     $ 0.25  
Current derivative assets
  $     $     $     $     $     $  
Non-current derivative
                                               
assets
  $     $     $     $     $     $  
Current derivative
                                               
liabilities
  $ 6,513     $ 46,332     $ 5,740     $ 94,440     $ 2,588     $ 28,097  
Non-current derivative
                                               
liabilities
  $ 12,941     $ 10,333     $ 22,495     $     $ 5,586     $  
Pre-tax accumulated
                                               
other comprehensive
                                               
loss included in
                                               
balance sheet
  $ (19,454 )   $     $ (28,235 )   $     $ (8,174 )   $ (28,097 )
Pre-tax gain/(loss)
                                               
included in Income
                                               
Statement
  $     $ 37,775     $     $ (94,440 )   $     $  
_________________________
*
The $250 million notional amount interest rate swaps represent the interest rate swaps that we de-designated as hedges in the fourth quarter of 2008 as disclosed in Note 2 of the Notes to our Consolidated Financial Statements in our 2008 Annual Report on Form 10-K.
 
Based on September 30, 2009 market interest rates and balances related to our $150 million in designated interest rate swaps, a loss of approximately $6.5 million would be realized and reported in pre-tax earnings during the next twelve months.  Estimated and realized losses will likely change during the next twelve months as market interest rates change.  Note 14 provides further information related to the $250 million notional swaps that are not designated as hedges for accounting purposes.


 
36

 

Foreign Exchange Contracts

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

The outstanding forward exchange contracts, which had a fair value of $0.1 million, $(0.2) million and $0.4 million at September 30, 2009, December 31, 2008 and September 30, 2008, respectively, have been recorded as Derivative assets or Derivative liabilities on the accompanying Condensed Consolidated Balance Sheets.  For the three and nine months ended September 30, 2009, the unrealized foreign exchange gain was $0.3 million and $0.3 million, respectively, while for the three and nine months ended September 30, 2008, the amount of unrealized foreign exchange gain was $0.1 million and $0.9 million, respectively.  For the three and nine months ended September 30, 2009, the realized foreign currency gain was $0.9 million and $1.7 million, respectively, while for the three and nine months ended September 30, 2008, the amount of foreign currency (loss) gain was $(0.3) million and $0.1 million, respectively.  Currency gains or losses on transactions executed in Canadian dollars are recorded in Operating revenues on the accompanying Condensed Consolidated Statements of Income as incurred.

All forward exchange contracts outstanding at September 30, 2009 will settle by December 24, 2009 and were as follows (dollars, in thousands):

 
Outstanding at
 
Outstanding at
 
Outstanding at
 
 
September 30, 2009
 
December 31, 2008
 
September 30, 2008
 
       
Latest
       
Latest
       
Latest
 
 
Notional
   
Expiration
 
Notional
   
Expiration
 
Notional
   
Expiration
 
 
Amounts
   
(months)
 
Amounts
   
(months)
 
Amounts
   
(months)
 
                                     
Canadian dollars
                                   
purchased
  $ 2,500       1     $ 52,000       1     $ 25,000       1  
Canadian dollars
                                               
sold
  $ 13,000       3     $           $ 3,000       1  


 
37

 


(14)
QUANTITATIVE DISCLOSURES RELATED TO DERIVATIVES

Fair values within the following tables are presented on a gross basis and do not reflect the netting of asset and liability positions.  Further, the amounts do not include net cash collateral of $6.7 million on deposit in margin accounts at September 30, 2009 to collateralize certain financial instruments, which is included in Derivative assets – current.  Therefore, the gross balances are not indicative of either our actual credit exposure or net economic exposure.  Additionally, the amounts below will not agree with the amounts presented on our Condensed Consolidated Balance Sheets, nor will they agree to the fair value measurements presented in Note 13 and Note 15.  The following table presents the fair value and balance sheet classification of our derivative instruments as of September 30, 2009 (in thousands):

Fair Value as of September 30, 2009
 
   
     
Fair Value
   
Fair Value
 
     
of Asset
   
of Liability
 
 
Balance Sheet Location
 
Derivatives
   
Derivatives
 
               
Derivatives designated as hedges:
             
Commodity derivatives
Derivative assets – current
  $ 6,914     $ 4,762  
Commodity derivatives
Derivative assets – non-current
    7        
Commodity derivatives
Derivative liabilities – current
          645  
Commodity derivatives
Derivative liabilities – non-current
          9  
Interest rate swaps
Derivative liabilities – current
          6,513  
Interest rate swaps
Derivative liabilities – non-current
          12,941  
Total derivatives designated as hedges
    $ 6,921     $ 24,870  
                   
Derivatives not designated as hedges:
                 
Commodity derivatives
Derivative assets – current
  $ 201,011     $ 152,933  
Commodity derivatives
Derivative assets – non-current
    11,407       5,976  
Commodity derivatives
Derivative liabilities – current
    10,672       25,803  
Commodity derivatives
Derivative liabilities – non-current
    1,201       5,742  
Interest rate swap
Derivative liabilities – current
          46,332  
Interest rate swap
Derivative liabilities – non-current
          10,333  
Foreign currency derivative
Derivative asset – current
    52        
Foreign currency derivatives
Derivative liabilities – current
    58       71  
Total derivatives not designated as hedges
    $ 224,401     $ 247,190  


 
38

 

Our derivative activities are discussed in Note 13.  The following tables present the impact that derivatives had on our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2009.

Fair Value Hedges

The impact of commodity contracts designated as fair value hedges and the related hedged items on our accompanying Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2009 is presented as follows:

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Income
 
for the Three and Nine Months Ended September 30, 2009
 
   
Fair Value Hedges
 
(in thousands)
 
           
   
Three Months Ended
 
Nine Months Ended
 
   
September 30, 2009
 
September 30, 2009
 
 
Location of
Amount of
 
Amount of
 
Derivatives in
Gain/(Loss) on
Gain/(Loss) on
 
Gain/(Loss) on
 
Fair Value
Derivatives Recognized
Derivatives Recognized
 
Derivatives Recognized
 
Hedging Relationships
in Income
in Income
 
in Income
 
           
Commodity derivatives
Operating revenue
  $ 3,868     $ 10,749  
Fair value adjustment for natural
                 
gas inventory designated as
                 
the hedged item
Operating revenue
    (2,552 )     (8,092 )
      $ 1,316     $ 2,657  


 
39

 

Cash Flow Hedges

The impact of cash flow hedges on our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2009 is presented as follows:

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Income
and the Balance Sheet for the Three Months Ended September 30, 2009
 
Cash Flow Hedges
(in thousands)
 
   
Location
 
Location of
 
 
Amount of
of Gain/
Amount of
Gain/
Amount of
 
Gain/ (Loss)
(Loss)
Gain/(Loss)
 (Loss)
Gain/(Loss)
 
Recognized
Reclassified
Reclassified
Recognized
Recognized in
Derivatives in
in AOCI
from AOCI
from AOCI
in Income
Income on
Cash Flow
Derivative
into Income
into Income
on Derivative
Derivative
Hedging
(Effective
(Effective
(Effective
(Ineffective
(Ineffective
Relationships
Portion)
Portion)
Portion)
Portion)
Portion)
           
Interest rate swaps
  $(2,941)
Interest expense
  $(582)     $—
Commodity derivatives
 
(7,781)
Operating revenue
 
5,976
Operating revenue
 
(147)
Total
  $(10,722)     $5,394     $(147)


The Effect of Derivative Instruments on the Condensed Consolidated Statements of Income
and the Balance Sheet for the Nine Months Ended September 30, 2009
 
Cash Flow Hedges
(in thousands)
 
   
Location
 
Location of
 
 
Amount of
of Gain/
Amount of
Gain/
Amount of
 
Gain/ (Loss)
(Loss)
Gain/(Loss)
 (Loss)
Gain/(Loss)
 
Recognized
Reclassified
Reclassified
Recognized
Recognized in
Derivatives in
in AOCI
from AOCI
from AOCI
in Income
Income on
Cash Flow
Derivative
into Income
into Income
on Derivative
Derivative
Hedging
(Effective
(Effective
(Effective
(Ineffective
(Ineffective
Relationships
Portion)
Portion)
Portion)
Portion)
Portion)
           
Interest rate swaps
  $8,780
Interest expense
  $(2,540)     $—
Commodity derivatives
 
(16,289)
Operating revenue
 
19,157
Operating revenue
 
(1,241)
Total
  $(7,509)     $16,617     $(1,241)

 
40

 

Derivatives Not Designated as Hedge Instruments

The impact of derivative instruments that have not been designated as hedges on our Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2009 is presented below.

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Income
 
for the Three and Nine Months Ended September 30, 2009
 
   
Derivatives Not Designated as Hedging Instruments
 
(in thousands)
 
           
   
Three Months Ended
 
Nine Months Ended
 
   
September 30, 2009
 
September 30, 2009
 
 
Location of
Amount of
 
Amount of
 
 
Gain/(Loss) on
Gain/(Loss) on
 
Gain/(Loss) on
 
Derivatives Not Designated
Derivatives Recognized
Derivatives Recognized
 
Derivatives Recognized
 
as Hedging Instruments
in Income
in Income
 
in Income
 
           
Commodity derivatives
Operating revenue
  $ (8,531 )   $ (25,895 )
Interest rate swap
Interest rate swap –
               
 
unrealized (loss) gain
    (8,694 )     37,775  
Foreign currency contracts
Operating revenue
    374       267  
      $ (16,851 )   $ 12,147  


 
41

 


(15)
DERIVATIVE FINANCIAL INSTRUMENTS AND FAIR VALUE MEASUREMENTS

Derivative Financial Instruments

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

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

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

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

The following tables set forth by level within the fair value hierarchy our assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2009, December 31, 2008 and September 30, 2008.  Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the placement within the fair value hierarchy levels.


Recurring Fair Value
At Fair Value as of September 30, 2009
 
Measures (in thousands)
   
             
Counterparty
     
             
Netting
     
             
and Cash
     
 
Level 1
 
Level 2
 
Level 3
 
Collateral(a)
 
Total
 
Assets:
                             
Commodity derivatives
  $     $ 213,296     $ 11,519     $ (162,537 )   $ 62,278  
Money market funds
    6,005                         6,005  
Foreign currency derivatives
          111                   111  
    $ 6,005     $ 213,407     $ 11,519     $ (162,537 )   $ 68,394  
                                         
Liabilities:
                                       
Commodity derivatives
  $     $ 183,566     $ 5,908     $ (169,206 )   $ 20,268  
Foreign currency derivatives
          71                   71  
Interest rate swaps
          76,119                   76,119  
Total
  $     $ 259,756     $ 5,908     $ (169,206 )   $ 96,458  


 
42

 


Recurring Fair Value
At Fair Value as of December 31, 2008
 
Measures (in thousands)
   
             
Counterparty
     
             
Netting
     
             
and Cash
     
 
Level 1
 
Level 2
 
Level 3
 
Collateral(a)
 
Total
 
Assets:
                             
Commodity derivatives
  $     $ 267,932     $ 28,407     $ (208,952 )   $ 87,387  
                                         
Liabilities:
                                       
Commodity derivatives
  $     $ 211,672     $ 12,009     $ (201,381 )   $ 22,300  
Foreign currency
                                       
derivatives
          227                   227  
Interest rate swaps
          122,675                   122,675  
Total
  $     $ 334,574     $ 12,009     $ (201,381 )   $ 145,202  


Recurring Fair Value
At Fair Value as of September 30, 2008
 
Measures (in thousands)
   
             
Counterparty
     
             
Netting
     
             
and Cash
     
 
Level 1
 
Level 2
 
Level 3
 
Collateral(a)
 
Total
 
Assets:
                             
Short-term investments
  $     $     $ 6,310     $     $ 6,310  
Commodity derivatives
          261,456       19,368       (194,989 )     85,835  
Foreign currency
                                       
derivatives
          423                   423  
Total
  $     $ 261,879     $ 25,678     $ (194,989 )   $ 92,568  
                                         
Liabilities:
                                       
Commodity derivatives
  $     $ 225,831     $ 13,048     $ (205,950 )   $ 32,929  
Interest rate swaps
          36,272                   36,272  
Total
  $     $ 262,103     $ 13,048     $ (205,950 )   $ 69,201  
________________________
(a)
A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.  When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between us and a counterparty.  Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim or the obligation to return cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement.  Cash collateral on deposit in margin accounts at September 30, 2009, December 31, 2008 and September 30, 2008 totaled a net $6.7 million, $(7.6) million and $11.0 million, respectively.


 
43

 

The following tables present the changes in level 3 recurring fair value for the three and nine months ended September 30, 2009 and 2008, respectively (in thousands):

 
Three Months
 
Nine Months
 
 
Ended
 
Ended
 
 
September 30, 2009
 
September 30, 2009
 
         
 
Commodity
 
Commodity
 
 
Derivatives
 
Derivatives
 
             
Balance as of beginning of period
  $ 5,153     $ 16,398  
Realized and unrealized losses
    (2,628 )     (4,183 )
Purchases, issuance and settlements
    2,590       (3,464 )
Transfers in and/or out of level 3(a)
    496       (3,140 )
Balances as of September 30, 2009
  $ 5,611     $ 5,611  
                 
Changes in unrealized losses
               
relating to instruments still held as of
               
September 30, 2009
  $ 3,556     $ (6,899 )
____________________________
(a)
Transfers into level 3 represent existing assets and liabilities that were previously categorized as a higher level for which the inputs became unobservable.  Transfers out of level 3 represent existing assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.

 
Three Months Ended
 
 
September 30, 2008
 
     
 
Commodity
 
Short-term
     
 
Derivatives
 
Investments
 
Total
 
                 
Balance as of July 1, 2008
  $ 11,332     $ 7,309     $ 18,641  
Realized and unrealized losses
    (3,142 )     (49 )     (3,191 )
Purchases, issuance and settlements
    (1,869 )     (950 )     (2,819 )
Balances as of September 30, 2008
  $ 6,321     $ 6,310     $ 12,631  
                         
Changes in unrealized gains
                       
relating to instruments still held as of
                       
September 30, 2008
  $ (4,579 )   $ (49 )   $ (4,628 )


 
44

 


 
Nine Months Ended
 
 
September 30, 2008
 
     
 
Commodity
 
Short-term
     
 
Derivatives
 
Investments
 
Total
 
                 
Balance as of January 1, 2008
  $ 6,422     $     $ 6,422  
Realized and unrealized gains (losses)
    3,688       (215 )     3,473  
Purchases, issuance and settlements
    (3,789 )     6,525       2,736  
Balances as of September 30, 2008
  $ 6,321     $ 6,310     $ 12,631  
                         
Changes in unrealized losses
                       
relating to instruments still held as of
                       
September 30, 2008
  $ (4,641 )   $ (215 )   $ (4,856 )

Gains and losses (realized and unrealized) for level 3 commodity derivatives are included in Operating revenues on the accompanying Condensed Consolidated Statements of Income.  We believe an analysis of commodity derivatives classified as level 3 needs to be undertaken with the understanding that these items may be economically hedged as part of a total portfolio of instruments that may be classified in level 1 or 2, or with instruments that may not be accounted for at fair value.  Accordingly, gains and losses associated with level 3 balances may not necessarily reflect trends occurring in the underlying business.  Further, unrealized gains and losses for the period from level 3 items may be offset by unrealized gains and losses in positions classified in level 1 or 2, as well as positions that have been realized during the quarter.  Short-term investments included in level 3 represent auction rate securities held at September 30, 2008.  The unrealized losses for these investments are recognized in Accumulated other comprehensive loss on the accompanying Condensed Consolidated Balance Sheets.

Fair Value of Financial Instruments

The estimated fair value of our financial instruments at September 30, 2009 is as follows (in thousands):

   
Carrying Amount
   
Fair Value
 
             
Cash, cash equivalents and restricted cash
  $ 137,687     $ 137,687  
Derivative financial instruments – assets
  $ 62,389     $ 62,389  
Derivative financial instruments – liabilities
  $ 96,458     $ 96,458  
Notes payable
  $ 350,500     $ 350,500  
Long-term debt, including current maturities
  $ 751,306     $ 848,900   

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

Cash, Cash Equivalents and Restricted Cash

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


 
45

 

Derivative Financial Instruments

These instruments are carried at fair value.  The Company’s fair value measurements are developed using a variety of inputs by its risk management group, which is independent of the trading function.  These inputs include unadjusted quoted prices where available; prices published by various third-party providers; and, when necessary, internally developed adjustments.  In many cases, the internally developed prices are corroborated with external sources.  Some of the Company’s transactions take place in markets with limited liquidity and limited price visibility.  Additionally, descriptions of the various instruments we use and the valuation method employed are included in Notes 13 and 15.

Notes Payable

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

Long-Term Debt

The fair value of our long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings.

(16)
COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We are subject to various legal proceedings, claims and litigation as described in Note 18 of the Notes to our Consolidated Financial Statements in our 2008 Annual Report on Form 10-K.  Except as described below, there have been no material developments in any previously reported proceedings or any new material proceedings that have developed or material proceedings that have terminated during the first nine months of 2009.

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations.  We believe the amounts provided in our consolidated financial statements are adequate in light of the probable and estimable contingencies.  However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our consolidated financial statements.  As such, costs, if any, that may be incurred in excess of those amounts provided as of September 30, 2009, cannot be reasonably determined and could have a material adverse effect on our results of operations or financial position.


 
46

 

FERC Compliance Investigation

During 2007, following an internal review of natural gas marketing activities conducted within the Energy Marketing segment, we identified possible instances of noncompliance with regulatory requirements applicable to those activities.  We notified the enforcement staff of FERC of our findings and shared information with the purpose of resolving any potential enforcement concerns.  On August 24, 2009, FERC entered its Order approving a stipulation and consent agreement between the FERC Office of Enforcement and Enserco Energy Inc., which settled all matters presented to FERC in the 2007 self-report.  Pursuant to the Agreement and Order, we agreed to pay a civil penalty of $1.4 million, and submit semi-annual monitoring reports to FERC’s Office of Enforcement for one year.  No further enforcement action was taken or is expected relative to the matters presented to the Office of Enforcement.  The settlement of this matter, including the payment of a civil penalty by Enserco Energy Inc., did not have a material impact upon our overall consolidated results of operations.

Partial Sale of Wygen I to MEAN

During August 2008, we entered into a definitive agreement to sell a 23.5% ownership interest in the Wygen I plant to MEAN.  The sale was completed in January 2009 for a price of $51.0 million, which was based on the then-current replacement cost for the coal-fired plant.  We realized an after-tax gain of $16.9 million on the sale, and our property, plant and equipment was reduced by $26.2 million.  We retain responsibility for operations of the plant, and at closing entered into a site lease, and operating agreements with MEAN for coal supply and operations.  In addition, we terminated a 10-year power purchase contract requiring MEAN to purchase 20 MW of power annually from Wygen I.

Partial Sale of Wygen III to MDU

On April 9, 2009, Black Hills Power sold to MDU a 25% ownership interest in its Wygen III generation facility currently under construction.  At closing, MDU made a payment to us for its 25% share of the costs to date on the ongoing construction of the facility.  Proceeds of $32.8 million were received of which $30.2 million was used to pay down a portion of the Acquisition Facility.  MDU will continue to reimburse Black Hills Power for its 25% of the total costs paid to complete the project.  In conjunction with the sales transaction, we also modified the 2004 PPA between Black Hills Power and MDU under which Black Hills Power supplied MDU with 74 MW of capacity and energy through 2016.  The power purchase agreement with MDU now provides that once online, the first 25 MW of MDU’s required 74 MW will be supplied from its ownership interest in Wygen III.  During periods of reduced production at Wygen III, or during periods when Wygen III is offline, we will provide MDU with its 25 MW from our other generation facilities or from system purchases.


 
47

 

Long-Term Power Sales Agreement

In March 2009, our 10-year power sales contract between MEAN and Black Hills Power that originally would have expired in 2013 was re-negotiated and extended until 2023.  Under the new contract, MEAN will purchase 20 MW of unit-contingent capacity from the Neil Simpson II and Wygen III plants, with capacity purchase decreasing to 15 MW in 2018, 12 MW in 2020 and 10 MW in 2022.  The unit-contingent capacity amounts from Wygen III and Neil Simpson II plants are as follows:

2009-2017
20 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019
15 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021
12 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023
10 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

Power Purchase Agreement

In April 2009, Cheyenne Light entered into an agreement to purchase 30 MW of renewable energy from Duke Energy’s Silver Sage wind site through a 20-year PPA.  Commercial operations commenced on October 1, 2009.  Under a separate inter-company agreement, Cheyenne Light has agreed to sell 20 MW of energy from Silver Sage to Black Hills Power.

Extension of Long-Term Power Purchase Agreement

On September 29, 2009, FERC approved an extension of the PPA between Black Hills Wyoming and Cheyenne Light.  The 60 MW of capacity and energy from Black Hills Wyoming’s Wygen I generating facility, which was scheduled to expire in 2013, has been extended through December 31, 2022.  In addition to establishing rates, terms and conditions for the sale of capacity and energy in this extension, the PPA grants Cheyenne Light an option to purchase Black Hills Wyoming’s ownership in the Wygen I facility during years one to seven of the ten year term of the PPA.  The purchase price related to the option is fixed at $2.55 million per MW which is the equivalent of the estimated price of new construction of the Wygen III plant.  This price is reduced annually by an amount of annual depreciation.


 
48

 


(17)
ACQUISITION

Aquila Transaction

On July 14, 2008, we completed the acquisition of a regulated electric utility in Colorado and four regulated gas utilities in Colorado, Kansas, Nebraska and Iowa.  See Note 21 of the Notes to our Consolidated Financial Statements in our 2008 Annual Report on Form 10-K for additional information.

This acquisition has been accounted for under the purchase method of accounting, and accordingly, the purchase price has been allocated to the acquired assets and liabilities based on preliminary estimates of the fair values of the assets purchased and liabilities assumed as of the date of acquisition.  Adjustments to the purchase price allocation during the nine months ended September 30, 2009 included working capital and tax adjustments of $5.4 million.  Allocation of the purchase price as of September 30, 2009 is as follows (in thousands):

Current assets
  $ 113,486  
Property, plant and equipment
    542,094  
Derivative assets
    4,695  
Goodwill
    339,028  
Intangible assets
    4,884  
Deferred assets
    76,143  
    $ 1,080,330  
         
Current liabilities
  $ 95,257  
Deferred credits and other
    54,550  
liabilities
       
    $ 149,807  
         
Net assets
  $ 930,523  

After finalization of the working capital adjustment, the allocation of the purchase price resulted in $339.0 million of goodwill and $4.9 million of intangible assets.  Goodwill of $245.0 million was allocated to the Electric Utility and $94.0 million was allocated to the Gas Utilities.

The results of operations of the acquired regulated utilities have been included in the accompanying Condensed Consolidated Financial Statements since the acquisition date.


 
49

 

The following pro-forma consolidated results of operations have been prepared as if the acquisition of the regulated utilities had occurred on January 1, 2008 (in thousands, except per share amounts):

   
Three Month
   
Nine Month
 
   
Period Ended
   
Period Ended
 
   
September 30,
   
September 30,
 
   
2008
   
2008
 
             
Operating revenues
  $ 314,090     $ 1,140,913  
Income from continuing operations
    19,890       68,809  
Net income available for common stock
    165,279       228,295  
Earnings per share –
               
Basic:
               
Continuing operations
  $ 0.52     $ 1.80  
Total
  $ 4.32     $ 5.99  
Diluted:
               
Continuing operations
  $ 0.52     $ 1.79  
Total
  $ 4.30     $ 5.94  

The above pro-forma information is presented for informational purposes only and is not necessarily indicative of the results of operations that would have been achieved had the acquisition been consummated at that time; nor is it intended to be a projection of future results.

(18)
INCOME TAXES

Our effective tax rate for the nine months ended September 30, 2009 was lower than previous periods as a result of a positive adjustment in the first quarter of 2009 for a previously recorded tax position.  We recorded a $3.8 million reduction in tax expense in our Oil and Gas segment due to a re-measurement of this position.

 
50

 


(19)
DISCONTINUED OPERATIONS

Results of operations and the related charges for discontinued operations have been classified as “Income from discontinued operations, net of taxes” in the accompanying Condensed Consolidated Statements of Income.  Assets and liabilities of the discontinued operations have been reclassified and reflected on the accompanying Condensed Consolidated Balance Sheets as “Assets of discontinued operations” and “Liabilities of discontinued operations.”  For comparative purposes, all prior periods presented have been restated to reflect the reclassifications on a consistent basis.

Sale of IPP Assets

On April 29, 2008, we entered into a definitive agreement to sell seven of our IPP plants to affiliates of Hastings and IIF for $840 million, subject to certain working capital adjustments.  The transaction was completed July 11, 2008.  Under the agreement, we received net pre-tax cash proceeds of $756 million, including the effects of estimated working capital adjustments and other costs and the required payoff of approximately $67.5 million of associated project level debt.  The after-tax gain recorded on the asset sale, after finalization of the working capital and tax adjustments, was $142.2 million, of which $2.4 million was recorded in 2009 and $139.7 million was recorded in 2008 in discontinued operations.

Revenues and net income from the discontinued operations associated with the divested IPP plants were as follows (in thousands):

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
      2008*       2009       2008*  
                               
Operating revenues
  $     $ 5,507     $     $ 59,572  
                                 
Pre-tax income from discontinued operations
          5,288       1,190       27,141  
Gain on sale
          235,671             235,671  
Income tax (expense) benefit
    1,673       (95,849 )     1,249       (103,803 )
                                 
Net income from discontinued operations
  $ 1,673     $ 145,110     $ 2,439     $ 159,009  
________________________
*
In accordance with GAAP, during the second quarter of 2008, the Company ceased recording depreciation and amortization expense on the IPP facilities.

The indirect corporate costs and inter-segment interest expense related to the IPP assets sold and not reclassified to discontinued operations were $0 million and $7.7 million after-tax for the three and nine months ended September 30, 2008, respectively.  These allocated costs remain in the Power Generation segment.

Interest expenses included within the operations of the discontinued entities were recorded pursuant to accounting standards for discontinued operations and include interest expense on debt which was required to be repaid as a result of the sale transaction.  Interest expense was allocated to discontinued operations based on the ratio of the assets sold to total Company net assets, excluding the known debt repayment.  For the three and nine months ended September 30, 2008, respectively, interest expense allocated to discontinued operations was $0 million and $4.7 million.

 
51

 


(20)
IMPAIRMENT OF LONG-LIVED ASSETS

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.  The lower prices at March 31, 2009 resulted in a $43.3 million pre-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.

(21)
SUBSEQUENT EVENTS

Black Hills Power Bond Issuance

On October 27, 2009, our regulated utility, Black Hills Power, completed a $180 million first mortgage bond issuance.  The bonds were priced at 99.931% of par and a reoffer yield of 6.13%.  The bonds mature November 1, 2039 and carry an annual interest rate of 6.125%, which will be paid semi-annually.  We received proceeds of $178.3 million net of underwriting fees which were used to repay borrowings under the Corporate Credit Facility.  Estimated deferred finance costs of $1.9 million were capitalized and will be amortized over the life of the bonds.


 
52

 

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

We are a diversified energy company operating principally in the United States with two major business groups – Utilities and Non-regulated Energy. We report our business groups in the following reportable operating segments:

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

Our Utilities Group consists of our electric and gas utility segments.  Our Electric Utilities generate, transmit and distribute electricity to approximately 202,100 customers in South Dakota, Wyoming, Colorado and Montana.  In addition, Cheyenne Light, which is also reported within the Electric Utilities segment, provides natural gas to approximately 33,300 customers in Wyoming.  Our Gas Utilities segment serves approximately 524,000 natural gas customers in Colorado, Nebraska, Iowa and Kansas.  Our Non-regulated Energy Group engages in the production of coal, natural gas and crude oil primarily in the Rocky Mountain region; the production of electric power through ownership of a portfolio of generating plants and the sale of electric power and capacity primarily under long-term contracts; and the marketing of natural gas, crude oil and related services.

See Forward-Looking Information in the Liquidity and Capital Resources section of this Item 2, beginning on Page 90.
Significant Events

Wygen III Power Plant Project and Partial Sale of Wygen III to MDU

We are currently constructing Wygen III, a 110 MW coal-fired base load electric generating facility located near Gillette, Wyoming.  Construction is currently expected to be completed by April 1, 2010.  The expected cost of construction is approximately $247 million, which includes estimates for AFUDC.

A 2004 Power Purchase Agreement between Black Hills Power and MDU included an option for MDU to purchase an ownership interest in Wygen III.  MDU exercised this option, and under an agreement entered into in April 2009, we will retain an undivided ownership of 75% of the facility with MDU owning the remaining 25%.  At closing we received proceeds of $32.8 million as MDU reimbursed us for its 25% of the total costs incurred to date on the ongoing construction of the facility.  We will retain responsibility for operations of the facility with a life-of-plant site lease and agreements with MDU for operations and coal supply.  In conjunction with the sales transaction, we also modified the 2004 PPA under which Black Hills Power supplied MDU with 74 MW of capacity and energy through 2016.  The PPA with MDU now provides that once online, the first 25 MW of MDU’s required 74 MW will be supplied from its ownership interest in Wygen III.  During periods of reduced production at Wygen III, or during periods when Wygen III is offline, we will provide MDU with its first 25 MW from our other generation facilities or from system purchases.

 
53

 

Partial Sale of Wygen I to MEAN

In August 2008, we entered into a definitive agreement to sell a 23.5% ownership interest in the Wygen I plant to MEAN.  The sale was completed in January 2009 for a price of $51.0 million, which was based on the then current replacement cost for the coal-fired plant.  We realized an after-tax gain of $16.9 million on the sale, and our property, plant and equipment was reduced by $26.2 million.  We retain responsibility for operations of the plant, and at closing entered into a site lease and operating agreements with MEAN for coal supply and operations.  In addition, we terminated a 10-year power purchase contract requiring MEAN to purchase 20 MW of power annually from Wygen I.

Extension of Long-Term Power Sales Agreement with MEAN

In March 2009, our 10-year power sales contract between MEAN and Black Hills Power that originally expired in 2013 was re-negotiated and extended until 2023.  Under the new contract, MEAN will purchase 20 MW of unit-contingent capacity from the Neil Simpson II and the Wygen III plants with capacity purchase decreasing to 15 MW in 2018, 12 MW in 2020 and 10 MW in 2022.  The unit-contingent capacity amounts from Wygen III and Neil Simpson II plants are as follows:

2009-2017
20 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019
15 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021
12 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023
10 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

Colorado Electric Resource Plan

In August 2008, Black Hills Energy filed a long-term Electric Resource Plan with the CPUC proposing to build five natural gas-fired power generation facilities totaling 350 MW to support the customers of Colorado Electric.  In the first quarter of 2009, Colorado Electric received approval from the CPUC to build two power generation facilities representing approximately 90 MW each.  The power generation facilities are part of a plan to replace the capacity and energy supplied under Colorado Electric’s current PPA with PSCo, which expires on December 31, 2011.  The initial decision of the CPUC waived the competitive bidding process for the two turbines; the remaining capacity and energy needs of the utility were to be acquired from other power producers through a competitive bid process.  Our Power Generation segment was allowed to participate in the competitive bidding process.  On September 29, 2009, our Power Generation segment was awarded the bid to provide 200 MW of power to Black Hills Energy through a 20-year PPA.  The PPA is subject to approval by FERC.  The 200 MW natural gas-fired electric generation facilities will be built in Colorado and are expected to be completed by December 31, 2011.

Silver Sage Wind Site

In April 2009, Cheyenne Light entered into an agreement to purchase 30 MW of renewable energy from Duke Energy’s Silver Sage wind site through a 20-year PPA.  Commercial operations commenced October 1, 2009.  Under a separate inter-company agreement, Cheyenne Light has agreed to sell 20 MW of energy from Silver Sage to Black Hills Power.

Power Purchase Agreement with MEAN

In July 2009, Black Hills Power entered into a five-year PPA with MEAN.  The contract commences the month following the onset of commercial operations at Wygen III.  Under this contract, MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III.


 
54

 

Extension of Long-Term Power Purchase Agreement

On September 29, 2009, FERC approved an extension of the PPA between Black Hills Wyoming and Cheyenne Light.  The 60 MW of capacity and energy from Black Hills Wyoming’s Wygen I generating facility, which was scheduled to expire in 2013, has been extended through December 31, 2022.  In addition to establishing rates, terms and conditions for the sale of capacity and energy in this extension, the PPA grants Cheyenne Light an option to purchase Black Hills Wyoming’s ownership in the Wygen I facility during years one to seven of the ten year term of the PPA. The purchase price related to the option is fixed at $2.55 million per MW which is the equivalent of the estimated price of new construction of the Wygen III plant.  This price is reduced annually by an amount of annual depreciation.

Results of Operations

Executive Summary

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008.
Loss from continuing operations for the three month period ended September 30, 2009 was $3.9 million, or $0.10 per share, compared to income from continuing operations of $19.5 million, or $0.51 per share, reported for the same period in 2008.  For the three month period ended September 30, 2009, net loss available for common stock was $2.2 million or $0.06 per share, compared to net income available for common stock of $164.9 million, or $4.29 per share, for the same period in 2008.

Included in 2009 are a full quarter of results from the utilities acquired from Aquila on July 14, 2008 and the impact of a $5.7 million after-tax non-cash loss, resulting from an unrealized net mark-to-market loss for certain interest rate swaps entered into in 2007.

The Utilities Group includes a full quarter of results of the electric and gas utilities acquired from Aquila on July 14, 2008.  Earnings at our Electric Utilities reflect the impact of lower margins from off-system sales due to lower energy prices, lower retail sales due to milder summer weather, and higher interest expense, partially offset by the impact of AFUDC related to the Wygen III construction and increased retail margins from an approved rate case for transmission rates.  Increased losses at our Gas Utilities reflect a full quarter of seasonal operations compared to the same period in 2008 and increased depreciation and property tax expense.

Earnings from the Oil and Gas segment decreased for the quarter due to a decrease in operating revenues resulting from lower oil and gas prices and lower production, partially offset by lower production taxes reflecting lower oil and gas prices.  Average oil prices received, net of hedges, decreased 28% and average gas prices received, net of hedges, decreased 14%.

Increased earnings from the Coal Mining segment resulted from site lease income, higher volumes sold and lower diesel fuel costs, partially offset by lower average sales prices and increased depreciation.

Decreased earnings from the Energy Marketing segment reflect decreased unrealized mark-to-market margins, partially offset by increased realized natural gas and crude oil margins that were primarily impacted by differing market conditions between years.

Earnings from the Power Generation segment were impacted by lower margins due to the net earnings impact of replacing MEAN’s 20 MW PPA with operating and site lease agreements related to their purchase of a 23.5% ownership interest in Wygen I, partially offset by operating fees charged to MEAN.  For the three months ended September 30, 2008, results included the sale of nitrogen oxide Reclaim Trading Credits allocated to our Ontario facility which has been decommissioned.


 
55

 

Income from discontinued operations was $1.7 million, or $0.04 per share, for the three month period ended September 30, 2009, compared to $145.4 million, or $3.78 per share, for the same period in 2008.  The Income from discontinued operations in 2009 relates to tax adjustments related to the sale in the IPP Transaction.  The income from discontinued operations in 2008 relates primarily to the IPP Transaction in which we sold seven of our IPP plants.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008.
Income from continuing operations for the nine month period ended September 30, 2009 was $46.4 million, or $1.20 per share, compared to $44.5 million, or $1.16 per share, reported for the same period in 2008.  For the nine month period ended September 30, 2009, net income available for common stock was $48.8 million or $1.26 per share, compared to $203.9 million, or $5.31 per share, for the same period in 2008.

Included in the 2009 results are the earnings from the utilities acquired from Aquila on July 14, 2008 and impacts from the following notable items:

· $16.9 million after-tax gain from the sale of a 23.5% interest in the Wygen I generation facility on January 22, 2009;
 
· $24.6 million after-tax non-cash gain, resulting from an unrealized net mark-to-market gain for certain interest rate swaps entered into in 2007; and
 
· Non-cash impairment charge of oil and gas assets totaling $27.8 million after-tax, driven by lower natural gas and crude oil prices at the end of the first quarter of 2009.

The Utilities Group’s 2009 results include a full nine months of earnings from the electric and gas utilities acquired from Aquila on July 14, 2008.  Earnings at our Electric Utilities reflect the impact of increased margins from an approved rate case for transmission rates and the impact of AFUDC related to the Wygen III construction partially offset by lower margins from off-system sales due to lower energy prices, and higher interest expense.

Earnings from the Oil and Gas segment decreased from 2008 due to a decrease in operating revenues reflecting lower oil and gas prices and lower production and a first quarter of 2009 impairment charge, partially offset by lower production taxes and LOE costs compared to 2008.  Average oil prices received, net of hedges, decreased 36% and average gas prices received, net of hedges, decreased 33%.

Lower earnings from the Coal Mining segment in 2009 resulted from lower volumes on coal sales, increased depreciation and coal taxes, partially offset by revenue increases from higher average sale prices, site lease income and lower diesel fuel costs.

Lower earnings from the Energy Marketing segment in 2009 reflect unrealized mark-to-market losses, partially offset by higher realized natural gas and crude oil margins received.  Realized natural gas margins and crude oil margins were primarily impacted by differing market conditions between years.

Increased earnings from the Power Generation segment in 2009 were impacted by a $16.9 million after-tax gain on the sale of a 23.5% ownership interest in the Wygen I power generation facility to MEAN and partially offset by increased interest expense and lower margins due to the net earnings impact of replacing the 20 MW PPA with operating and site lease agreements related to MEAN’s purchase of the 23.5% ownership interest in Wygen I.  In addition, for the nine months ended September 30, 2008, results included $11.8 million of pre-tax allocated indirect corporate costs and inter-segment net interest expense not classified to discontinued operations for the IPP Transaction, as well as the sale of nitrogen oxide Reclaim Trading Credits allocated to our Ontario facility which has been decommissioned.

 
56

 

Income from discontinued operations was $2.4 million, or $0.06 per share, for the nine month period ended September 30, 2009, compared to $159.5 million, or $4.15 per share, for the same period in 2008.  The Income from discontinued operations in 2009 relates to working capital and tax adjustments and the related impact of the gain on sale from the IPP Transaction.

Consolidated Results

The following business group and segment information does not include intercompany eliminations or results of discontinued operations.  Amounts are presented on a pre-tax basis unless otherwise indicated.

Revenues and Income (loss) from continuing operations provided by each business group were as follows (in thousands):

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
Revenues
                       
                         
Utilities
  $ 191,634     $ 220,581     $ 796,973     $ 413,449  
Non-regulated Energy
    34,165       71,311       124,117       184,566  
    $ 225,799     $ 291,892     $ 921,090     $ 598,015  
                                 
Income (loss) from
                               
continuing operations
                               
                                 
Utilities
  $ 7,053     $ 8,911     $ 38,618     $ 28,631  
Non-regulated Energy
    (1,796 )     12,672       (5,470 )     23,800  
Corporate
    (9,110 )     (2,061 )     13,205       (7,889 )
    $ (3,853 )   $ 19,522     $ 46,353     $ 44,542  

Income from continuing operations decreased $23.4 million for the three months ended September 30, 2009 reflecting the following:

Utilities

·  
A $0.2 million decrease in Electric Utilities earnings

·  
A $1.6 million decrease in the Gas Utilities segment

Non-regulated Energy

·  
A $1.7 million decrease in Oil and Gas earnings

·  
A $1.2 million increase in Coal Mining earnings
 
·  
An $11.3 million decrease in Energy Marketing earnings

·  
A $2.6 million decrease in Power Generation earnings

Corporate

·  
A $7.0 million decrease in corporate earnings

 
57

 

Income from continuing operations increased $1.8 million for the nine months ended September 30, 2009 reflecting the following:

Utilities

·  
A $6.1 million decrease in Electric Utilities earnings

·  
A $16.1 million increase in the Gas Utilities segment

Non-regulated Energy

·  
A $37.0 million decrease in Oil and Gas earnings

·  
A $0.6 million decrease in Coal Mining earnings

·  
An $8.7 million decrease in Energy Marketing earnings
 
·  
A $16.7 million increase in Power Generation earnings

Corporate
 
 
·  
A $21.1 million increase in corporate earnings

 
See the following discussion under the captions “Utilities Group” and “Non-regulated Energy Group” for more detail on our results of operations by business segment.


 
58

 


 
Utilities Group

We acquired from Aquila a regulated electric utility in Colorado and four regulated gas utilities operating in Colorado, Nebraska, Iowa and Kansas.  Operations from the acquired utilities have been included in the Utilities Group results from the July 14, 2008 acquisition date.

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

Electric Utilities

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
   
(in thousands)
 
                         
Revenue – electric
  $ 126,025     $ 131,193     $ 361,198     $ 295,946  
Revenue – gas
    3,141       5,785       24,062       34,570  
Total revenue
    129,166       136,978       385,260       330,516  
                                 
Fuel and purchased power – electric
    66,994       74,162       190,831       152,364  
Purchased gas
    912       3,596       13,873       24,051  
Total fuel and purchased power
    67,906       77,758       204,704       176,415  
                                 
Gross margin – electric
    59,031       57,031       170,367       143,582  
Gross margin – gas
    2,229       2,189       10,189       10,519  
Total gross margin
    61,260       59,220       180,556       154,101  
                                 
Operating expenses
    42,493       38,561       128,703       95,654  
Operating income
  $ 18,767     $ 20,659     $ 51,853     $ 58,447  
                                 
Income from continuing operations
                               
and net income available for
                               
common stock
  $ 10,537     $ 10,765     $ 24,395     $ 30,485  


 
59

 

The following tables summarize regulated sales revenues, quantities generated and purchased, sales quantities and degree days for our Electric Utilities segment.  Included in 2009 reported amounts for the periods are the operations of Colorado Electric, acquired July 14, 2008 as part of the Aquila Transaction:

Sales Revenues
 
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
   
(in thousands)
 
                         
Residential:
                       
Black Hills Power
  $ 11,132     $ 13,189     $ 35,804     $ 35,784  
Cheyenne Light
    6,512       6,967       21,093       23,800  
Colorado Electric
    18,586       17,182       50,274       17,182  
Total Residential
    36,230       37,338       107,171       76,766  
                                 
Commercial:
                               
Black Hills Power
    15,694       16,581       44,888       43,804  
Cheyenne Light
    13,424       13,669       38,050       38,018  
Colorado Electric
    15,088       15,322       42,259       15,322  
Total Commercial
    44,206       45,572       125,197       97,144  
                                 
Industrial:
                               
Black Hills Power
    4,714       5,500       14,494       16,338  
Cheyenne Light
    2,888       2,620       8,179       7,038  
Colorado Electric
    8,021       8,153       23,074       8,153  
Total Industrial
    15,623       16,273       45,747       31,529  
                                 
Municipal:
                               
Black Hills Power
    778       802       2,074       2,069  
Cheyenne Light
    230       240       701       711  
Colorado Electric
    1,179       1,197       3,351       1,197  
Total Municipal
    2,187       2,239       6,126       3,977  
                                 
Contract Wholesale:
                               
Black Hills Power
    6,488       6,862       18,672       20,063  
                                 
Off-system Wholesale:
                               
Black Hills Power
    9,625       13,213       24,610       47,548  
Cheyenne Light
    1,863       1,497       5,795       4,368  
Colorado Electric
    2,697       4,352       9,724       4,352  
Total Off-system Wholesale
    14,185       19,062       40,129       56,268  
                                 
Other:
                               
Black Hills Power
    4,655       3,211       13,838       9,362  
Cheyenne Light
    253       98       466       299  
Colorado Electric
    2,198       538       3,852       538  
Total Other
    7,106       3,847       18,156       10,199  
                                 
Total Sales Revenues
  $ 126,025     $ 131,193     $ 361,198     $ 295,946  


 
60

 


Quantities Generated and Purchased
 
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
   
(in MWh)
 
Generated –
                       
Coal-fired:
                       
Black Hills Power
    465,068       450,884       1,251,276       1,268,514  
Cheyenne Light
    200,489       196,937       577,217       586,635  
Colorado Electric
    63,760       79,793       187,091       79,793  
Total Coal
    729,317       727,614       2,015,584       1,934,942  
                                 
Gas and Oil-fired:
                               
Black Hills Power
    28,251       11,856       35,076       53,687  
Cheyenne Light
                       
Colorado Electric
    2,297       525       2,496       525  
Total Gas and Oil
    30,548       12,381       37,572       54,212  
                                 
Total Generated:
                               
Black Hills Power
    493,319       462,740       1,286,352       1,322,201  
Cheyenne Light
    200,489       196,937       577,217       586,635  
Colorado Electric
    66,057       80,318       189,587       80,318  
Total Generated
    759,865       739,995       2,053,156       1,989,154  
                                 
Purchased:
                               
Black Hills Power
    420,332       404,148       1,304,362       1,256,835  
Cheyenne Light
    151,992       140,843       464,265       404,390  
Colorado Electric
    514,980       473,019       1,495,825       473,019  
Total Purchased
    1,087,304       1,018,010       3,264,452       2,134,244  
                                 
Total Generated and Purchased:
                               
Black Hills Power
    913,651       866,888       2,590,714       2,579,036  
Cheyenne Light
    352,481       337,780       1,041,482       991,025  
Colorado Electric
    581,037       553,337       1,685,412       553,337  
Total Generated and
                               
Purchased
    1,847,169       1,758,005       5,317,608       4,123,398  


 
61

 


Quantity Sold
 
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
   
(in MWh)
 
Residential:
                       
Black Hills Power
    113,266       120,888       395,865       398,028  
Cheyenne Light
    59,384       60,986       189,610       193,653  
Colorado Electric
    166,993       140,945       444,223       140,945  
Total Residential
    339,643       322,819       1,029,698       732,626  
                                 
Commercial:
                               
Black Hills Power
    207,939       195,661       553,150       531,433  
Cheyenne Light
    152,376       153,615       439,476       440,382  
Colorado Electric
    187,959       168,422       507,123       168,422  
Total Commercial
    548,274       517,698       1,499,749       1,140,237  
                                 
Industrial:
                               
Black Hills Power
    80,222       107,380       260,190       319,077  
Cheyenne Light
    45,447       38,798       131,694       108,569  
Colorado Electric
    121,789       110,492       342,206       110,492  
Total Industrial
    247,458       256,670       734,090       538,138  
                                 
Municipal:
                               
Black Hills Power
    9,894       10,228       25,556       26,073  
Cheyenne Light
    742       809       2,449       2,571  
Colorado Electric
    11,705       10,713       29,696       10,713  
Total Municipal
    22,341       21,750       57,701       39,357  
                                 
Contract Wholesale:
                               
Black Hills Power
    161,796       165,872       473,723       494,457  
                                 
Off-system Wholesale:
                               
Black Hills Power
    309,770       241,546       784,173       753,057  
Cheyenne Light
    72,771       63,202       216,822       184,151  
Colorado Electric
    71,886       79,685       272,694       79,685  
Total Off-system Wholesale
    454,427       384,433       1,273,689       1,016,893  
                                 
Total Quantity Sold:
                               
Black Hills Power
    882,887       841,575       2,492,657       2,522,125  
Cheyenne Light
    330,720       317,410       980,051       929,326  
Colorado Electric
    560,332       510,257       1,595,942       510,257  
Total Quantity Sold
    1,773,939       1,669,242       5,068,650       3,961,708  
                                 
Losses and Company Use:
                               
Black Hills Power
    30,764       25,313       98,057       56,911  
Cheyenne Light
    21,761       20,370       61,431       61,699  
Colorado Electric
    20,705       43,080       89,470       43,080  
Total Losses and Company Use
    73,230       88,763       248,958       161,690  
                                 
Total Energy
    1,847,169       1,758,005       5,317,608       4,123,398  


 
62

 


Degree Days
 
Three Months Ended
 
   
September 30,
 
   
2009
   
2008
 
                         
         
Variance
         
Variance
 
         
from
         
from
 
Heating Degree Days:
 
Actual
   
Normal
   
Actual
   
Normal
 
Actual –
                       
Black Hills Power
    178       (22 )%     223       (2 )%
Cheyenne Light
    298       (9 )%     317       (3 )%
Colorado Electric
    104       13 %     75       (18 )%
                                 
Cooling Degree Days:
                               
Actual –
                               
Black Hills Power
    303       (39 )%     453       (8 )%
Cheyenne Light
    179       (23 )%     345       49 %
Colorado Electric
    620       (12 )%     560       (2 )%


Degree Days
 
Nine Months Ended
 
   
September 30,
 
   
2009
   
2008
 
                         
         
Variance
         
Variance
 
         
from
         
from
 
Heating Degree Days:
 
Actual
   
Normal
   
Actual
   
Normal
 
Actual –
                       
Black Hills Power
    4,705       4 %     4,814       6 %
Cheyenne Light
    4,383       (7 )%     4,859       3 %
Colorado Electric
    3,053       (10 )%     75       (18 )%
                                 
Cooling Degree Days:
                               
Actual –
                               
Black Hills Power
    354       (41 )%     482       (19 )%
Cheyenne Light
    203       (26 )%     372       36 %
Colorado Electric
    804       (13 )%     560       (2 )%


 
63

 


   
Electric Utilities Power Plant Availability
 
       
   
Three Months Ended September 30,
   
Nine Months Ended September 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Coal-fired plants
    94.5 %     96.4 %     92.0 %**     93.2 %*
Other plants
    77.9 %***     98.7 %     90.6 %***     92.6 %
Total availability
    88.3 %     97.3 %     91.4 %     93.0 %
_________________________
  *
Reflects major maintenance outages at our Ben French, Neil Simpson I and Osage coal-fired plants.  The Ben French outage was scheduled for 25 days and was subsequently extended to accelerate major maintenance originally scheduled for 2009.  The actual outage was 88 days and resulted in the plant’s output being restored to its full rated capacity.  The Osage outage was originally scheduled for approximately 10 days and lasted 52 days as a result of additional unplanned required maintenance.  All the plants were online by the end of the second quarter of 2008.
**
Reflects major maintenance outages at Neil Simpson I and Neil Simpson II coal-fired plants.  The Neil Simpson I outage was scheduled for 31 days and was subsequently extended to 39 days.  The Neil Simpson II outage was scheduled for 18 days and was subsequently extended to 27 days.  The outages were extended on both units for major rotor damage discovered during the overhauls.
***
Reflects unplanned outage at Pueblo Unit 5 gas-fired plant.

Cheyenne Light Natural Gas Distribution

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

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Sales Revenues (in thousands):
                       
Residential
  $ 2,053     $ 3,419     $ 14,699     $ 20,262  
Commercial
    657       1,526       6,716       9,919  
Industrial
    266       656       2,073       3,799  
Other
    165       184       574       590  
Total Sales Revenues
  $ 3,141     $ 5,785     $ 24,062     $ 34,570  
                                 
Sales Margins (in thousands):
                               
Residential
  $ 1,624     $ 1,588     $ 6,990     $ 7,244  
Commercial
    379       368       2,296       2,357  
Industrial
    61       49       329       328  
Other
    165       184       574       590  
Total Sales Margins
  $ 2,229     $ 2,189     $ 10,189     $ 10,519  
                                 
Volumes Sold (Dth):
                               
Residential
    176,996       183,594       1,745,760       1,944,705  
Commercial
    120,348       116,840       1,037,984       1,112,664  
Industrial
    79,161       61,050       462,276       461,792  
Total Volumes Sold
    376,505       361,484       3,246,020       3,519,161  


 
64

 

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008.  Income from continuing operations for the Electric Utilities decreased $0.2 million from the prior period primarily due to the following:

· A $2.2 million decrease in margins from off-system sales reflecting the lower margins available in the current low energy price environment; and
 
· A $1.5 million increase in net interest expense due to additional debt associated with the acquisition of Colorado Electric.
 
Partially offsetting these were the following:
 
· A $1.5 million increase in other margins primarily related to an increase in transmission rates effective January 1, 2009 at Black Hills Power;
 
· Higher retail margins resulting from a full quarter of operations at Colorado Electric, which was purchased on July 14, 2008, which were partially offset by milder summer weather.  Cooling degree days were below normal for the quarter; and
 
· Increased AFUDC of $1.8 million primarily due to construction of Wygen III and construction at Colorado Electric in 2009.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008.  Income from continuing operations for the Electric Utilities decreased $6.1 million from the prior period primarily due to the following:

· A $6.1 million decrease in margins from off-system sales reflecting the lower margins available in the current low energy price environment;
 
· A $10.6 million increase in net interest expense due to additional debt associated with the acquisition of Colorado Electric; and
 
· A $2.5 million increase in employee benefit costs primarily associated with pension costs.
 
Partially offsetting these were the following:
 
· A $4.5 million increase in other margins primarily due to an increase in transmission rate effective January 1, 2009 at Black Hills Power; and
 
· Increased AFUDC of $4.7 million primarily due to construction of Wygen III and construction at Colorado Electric in 2009.


 
65

 

Gas Utilities

Operating results for the Gas Utilities are as follows:

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
      2008 *     2009       2008 *
   
(in thousands)
 
                               
Revenue:
                             
Natural gas – regulated
  $ 56,854     $ 75,465     $ 392,595     $ 75,465  
Other – non-regulated services
    5,837       8,472       19,771       8,472  
Total sales
    62,691       83,937       412,366       83,937  
                                 
Cost of sales:
                               
Natural gas – regulated
    23,376       47,364       251,252       47,364  
Other – non-regulated services
    2,894       5,823       11,295       5,823  
Total cost of sales
    26,270       53,187       262,547       53,187  
                                 
Gross margin
    36,421       30,750       149,819       30,750  
                                 
Operating expenses
    37,656       29,777       116,568       29,777  
Operating (loss) income
  $ (1,235 )   $ 973     $ 33,251     $ 973  
                                 
(Loss) income from continuing
                               
operations and net income
                               
(loss) available for common
                               
stock
  $ (3,484 )   $ (1,854 )   $ 14,223     $ (1,854 )
__________________________
*
Gas utilities were purchased on July 14, 2008.

 
66

 

The following table summarizes regulated Gas Utilities’ sales revenues:

Sales Revenues
 
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
      2008 *     2009       2008 *
   
(in thousands)
 
                               
Residential:
                             
Colorado
  $ 5,127     $ 5,503     $ 43,277     $ 5,503  
Nebraska
    12,552       13,518       90,698       13,518  
Iowa
    9,773       11,423       81,184       11,423  
Kansas
    7,703       8,367       49,591       8,367  
Total Residential
    35,155       38,811       264,750       38,811  
                                 
Commercial:
                               
Colorado
    1,131       1,408       9,444       1,408  
Nebraska
    2,896       5,425       31,219       5,425  
Iowa
    3,950       6,436       36,325       6,436  
Kansas
    1,976       2,413       15,542       2,413  
Total Commercial
    9,953       15,682       92,530       15,682  
                                 
Industrial:
                               
Colorado
    450       1,341       1,159       1,341  
Nebraska
    345       686       2,435       686  
Iowa
    307       487       958       487  
Kansas
    5,764       13,926       10,349       13,926  
Total Industrial
    6,866       16,440       14,901       16,440  
                                 
Transportation:
                               
Colorado
    115       107       477       107  
Nebraska
    1,519       1,488       7,441       1,488  
Iowa
    793       533       2,837       533  
Kansas
    1,251       1,160       4,047       1,160  
Total Transportation
    3,678       3,288       14,802       3,288  
                                 
Other:
                               
Colorado
    24       17       82       17  
Nebraska
    406       371       1,592       371  
Iowa
    109       132       802       132  
Kansas
    663       724       3,136       724  
Total Other
    1,202       1,244       5,612       1,244  
                                 
Total Regulated
    56,854       75,465       392,595       75,465  
                                 
Non-regulated Services
    5,837       8,472       19,771       8,472  
                                 
Total
  $ 62,691     $ 83,937     $ 412,366     $ 83,937  
__________________________
*
Gas utilities were purchased on July 14, 2008.


 
67

 


 



The following table summarizes regulated Gas Utilities’ sales margins:



Sales Margins
 
Three Months Ended
Nine Months Ended
   
September 30,
September 30,
     
2009
2008*
  2009   2008*  
   
(in thousands)
                       
Residential:
                     
Colorado
  $ 2,895   $ 1,670    $ 11,577    $ 1,670  
Nebraska
    7,637     5,847     31,767     5,847  
Iowa
    7,075      4,512      31,237     4,512  
Kansas
    5,433      6,442     20,781     6,442  
Total Residential
    23,040      18,471     95,362     18,471  
                           
Commercial:
                         
Colorado
    515      297     2,130      297  
Nebraska
    1,357      1,544     8,298     1,544  
Iowa
    1,706      833     9,022     833  
Kansas
    1,021      1,339     4,516     1,339  
Total Commercial
    4,599      4,013     23,966     4,013  
                           
Industrial:
                         
Colorado
    141      195     325     195  
Nebraska
    64      27     276     27  
Iowa
    26      863     116     863  
Kansas
    834      66     1,584     66  
Total Industrial
    1,065      1,151     2,301     1,151  
                           
Transportation:
                         
Colorado
    114      107     476     107  
Nebraska
    1,520      533     7,441     533  
Iowa
    793      1,160     2,838     1,160  
Kansas
    1,251      1,488     4,048     1,488  
Total Transportation
    3,678      3,288     14,803     3,288  
                           
Other:
                         
Colorado
    25      17     82     17  
Nebraska
    404      132     1,591     132  
Iowa
    110      662     803     662  
Kansas
    559      371     2,496     371  
Total Other
    1,098      1,182     4,972     1,182  
                           
Total Regulated
    33,480      28,105     141,404     28,105  
                           
Non-regulated Services
    2,941      2,645     8,415     2,645  
                           
Total
  $ 36,421   $ 30,750    $ 149,819    $ 30,750  


__________________________
*
Gas utilities were purchased on July 14, 2008.


 
68

 

The following table summarizes regulated Gas Utilities’ volumes sold:

Volumes Sold
 
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
      2008 *     2009       2008 *
   
(in Dth)
 
                               
Residential:
                             
Colorado
    505,857       448,358       3,998,997       448,358  
Nebraska
    909,794       735,153       8,349,868       735,153  
Iowa
    605,788       582,043       7,558,458       582,043  
Kansas
    542,182       414,348       4,551,485       414,348  
Total Residential
    2,563,621       2,179,902       24,458,808       2,179,902  
                                 
Commercial:
                               
Colorado
    142,070       131,333       945,349       131,333  
Nebraska
    366,579       433,634       3,567,604       433,634  
Iowa
    499,487       495,976       4,233,967       495,976  
Kansas
    230,693       174,908       1,759,774       174,908  
Total Commercial
    1,238,829       1,235,851       10,506,694       1,235,851  
                                 
Industrial:
                               
Colorado
    110,474       151,168       241,267       151,168  
Nebraska
    79,710       93,031       394,475       93,031  
Iowa
    63,646       45,728       154,329       45,728  
Kansas
    1,401,415       1,465,835       2,402,633       1,465,835  
Total Industrial
    1,655,245       1,755,762       3,192,704       1,755,762  
                                 
Transportation:
                               
Colorado
    110,158       123,564       541,958       123,564  
Nebraska
    5,222,591       5,776,382       18,637,020       5,776,382  
Iowa
    3,069,669       2,171,780       10,375,438       2,171,780  
Kansas
    3,756,752       4,083,444       10,774,330       4,083,444  
Total Transportation
    12,159,170       12,155,170       40,328,746       12,155,170  
                                 
Other:
                               
Colorado
                       
Nebraska
    5       4       1,140       4  
Iowa
    3,833       2,898       52,341       2,898  
Kansas
    21,360       7,245       98,878       7,245  
Total Other
    25,198       10,147       152,359       10,147  
                                 
Total Regulated
    17,642,063       17,336,832       78,639,311       17,336,832  
__________________________
*
Gas utilities were purchased on July 14, 2008.


 
69

 


   
Three Months Ended
   
Nine Months Ended
 
Degree Days
 
September 30, 2009
   
September 30, 2009
 
         
Variance From
         
Variance From
 
Heating Degree Days:
 
Actual
   
Normal
   
Actual
   
Normal
 
                         
Colorado
    224       20 %     3,735       (1 )%
Nebraska
    100       10 %     3,645       3 %
Iowa
    142       (8 )%     4,353       3 %
Kansas*
    67       68 %     2,765       (10 )%
Combined Gas Utilities
                               
Heating Degree Days
    141       5 %     3,831       (5 )%


   
Three Months Ended
   
Nine Months Ended
 
Degree Days
 
September 30, 2008**
   
September 30, 2008**
 
         
Variance From
         
Variance From
 
Heating Degree Days:
 
Actual
   
Normal
   
Actual
   
Normal
 
                         
Colorado
    183       (2 )%     183       (2 )%
Nebraska
    65       (29 )%     65       (29 )%
Iowa
    102       (34 )%     102       (34 )%
Kansas*
    47       18 %     47       18 %
Combined Gas Utilities
                               
Heating Degree Days
    116       (13 )%     116       (13 )%
_________________________
  *
Kansas Gas has a 30-year weather normalization adjustment mechanism in place that neutralized the impact of weather on revenues at Kansas Gas.
**
Results from the Gas Utilities for the three and nine month periods ended September 30, 2009 reflect operations from the gas utilities acquired from Aquila on July 14, 2008.

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


 
70

 

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008.  Income from continuing operations for the Gas Utilities decreased $1.6 million from the prior period primarily due to the following:

·  
2009 reflects a full quarter of summer season operations for the Gas Utilities purchased on July 14, 2008;

·  
A $1.3 million increase in depreciation and property tax expense due to increased asset base; and

·  
A $0.2 million increase in net interest expense due to additional debt associated with the acquisition of the Gas Utilities.

Nine months ended September 30, 2009 reflects a full three quarters of operations for our Gas Utilities compared with 2008 when operations commenced on July 14, 2008.

 
71

 

Regulatory Matters – Utilities Group

The following summarizes our recent rate case activity:
 

 
 
Type of
 
Date
   
Date
   
Amount
   
Amount
 
In millions
Service
 
Requested
   
Effective
   
Requested
   
Approved
 
Nebraska Gas (1)
Gas
    11/2006       9/2007     $ 16.3     $ 9.2  
Iowa Gas (2)
Gas
    6/2008    
7/27/09
    $ 13.6     $ 10.8  
Colorado Gas (3)
Gas
    6/2008       4/2009     $ 2.7     $ 1.4  
Kansas Gas (4)
Gas
    5/2009    
10/02/09
    $ 0.5     $ 0.5  
Black Hills Power (5)
Electric
    9/2008       1/2009     $ 4.5     $ 3.8  
Black Hills Power (6)
Electric
    9/2009    
Pending
    $ 32.0    
Pending
 
Black Hills Power (7)
Electric
    10/2009    
Pending
    $ 3.8    
Pending
 

 (1)
In November 2006, Nebraska Gas filed for a $16.3 million rate increase.  Interim rates were implemented in February 2007 and, in July 2007, the NPSC granted a $9.2 million increase in annual revenues based on an equity return of 10.4% on a capital structure of 51% equity and 49% debt.  Nebraska Gas appealed the decision, and the district court affirmed the NPSC order in February 2008.  Because Nebraska Gas collected interim rates subject to refund, it was required to refund to customers the difference between the higher interim rates and the final rates plus interest (approximately $5.6 million).  The NPA appealed one aspect of our refund plan worth approximately $0.8 million.  On April 15, 2009, the District Court affirmed the NPSC refund plan order, and thereby rejected NPA’s appeal.

 (2)
On June 3, 2009, Iowa Gas received approval from the IUB to implement new natural gas service rates for its Iowa residential, commercial and industrial customers.  The rates went into effect on July 27, 2009.  The approved rates allow Iowa Gas to recover capital investments made in its natural gas distribution system and offset increasing operating costs due to inflation since the last rate increase in March 2006.  The new rates represent approximately $10.8 million in additional revenue.  The increase is based on a return on equity of 10.1%, with a capital structure of 51.4% equity and 48.6% debt.

(3)
In June 2008, Colorado Gas filed for a $2.7 million rate increase.  The increase was based on a proposed equity return of 11.5% on a capital structure of 50% equity and 50% debt.  Interim rates were not available for collection in Colorado.  On September 19, 2008, Colorado Gas filed the second phase of its rate request.  On January 29, 2009, a settlement agreement was filed with the CPUC and a settlement was approved with new rates effective on April 1, 2009.  The new rates included an increase in annual revenues of $1.4 million, which was based on a 10.25% return on equity with a capital structure of 50.48% equity and 49.52% debt.

(4)
Kansas Gas has requested a GSRS in the amount of $0.5 million annually.  The KCC staff recommended approval of all projects submitted, the filed GSRS revenue requirement of $0.5 million, and that Kansas Gas be allowed to continue collecting its current GSRS amount of $0.3 million.  The KCC issued an order on September 14, 2009 approving the request for $0.5 million and allowing Kansas Gas to continue collecting the $0.3 million previously authorized.  The new rates had an effective date of October 1, 2009.

(5)
On February 10, 2009, the FERC approved a formulaic approach to the method used to determine the revenue component of Black Hills Power’s open access transmission tariff, and increased the utility’s annual transmission revenue requirement by approximately $3.8 million.  The revenue requirement is based on an equity return of 10.8%, and a capital structure consisting of 57% equity and 43% debt.  The new rates had an effective date of January 1, 2009.

 
72

 

(6)
On September 29, 2009, Black Hills Power filed a rate case with the SDPUC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred during the past four years.  Black Hills Power is seeking a 26.6% increase in annual utility revenues and anticipates that the new rates will be effective for our South Dakota customers on or around April 1, 2010.  The proposed rate increase is subject to approval by the SDPUC.

(7)
On October 19, 2009, Black Hills Power filed a rate case with the WPSC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred since 1995.  Black Hills Power is seeking a 38.95% increase in annual utility revenues and anticipates that the new rates will be effective for our Wyoming customers on or around April 1, 2010, although recovery could be delayed until August 2010 as part of the regulatory process.  The proposed rate increase is subject to approval by the WPSC.

Non-regulated Energy Group

An analysis of results from our Non-regulated Energy Group’s operating segments follows:

Oil and Gas

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
   
(in thousands)
 
                         
Revenue
  $ 17,887     $ 25,438     $ 52,227     $ 85,770  
Operating expenses*
    17,057       21,285       95,564       63,692  
Operating income (loss)
  $ 830     $ 4,153     $ (43,337 )   $ 22,078  
                                 
(Loss) income from continuing
                               
operations and net income (loss)
                               
available for common
                               
stock
  $ (149 )   $ 1,517     $ (25,740 )   $ 11,266  
__________________________
*
Nine months ended September 30, 2009 operating expenses include a $43.3 million pre-tax ceiling test impairment charge.



 
73

 

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

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
Fuel production:
                       
Bbls of oil sold
    91,091       95,248       286,405       298,035  
Mcf of natural gas sold
    2,574,036       2,873,353       7,916,515       8,293,364  
Mcf equivalent sales
    3,120,582       3,444,841       9,634,945       10,081,574  


   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Average price received: (a)
                       
Gas/Mcf (b)
  $ 4.50     $ 5.26     $ 4.44 (c)   $ 6.58 (c)
Oil/Bbl
  $ 60.43     $ 83.86     $ 56.25     $ 88.07  
                                 
Depletion expense/Mcfe
  $ 2.07     $ 2.58     $ 2.08     $ 2.40  
________________________
(a)
Net of hedge settlement gains/losses
(b)
Exclusive of gas liquids
(c)
Does not include the negative revenue impacts of a $1.2 million and $2.1 million royalty settlement accrual through September 30, 2009 and 2008, respectively, resulting in a $0.17/Mcf and $0.27/Mcf price impact

The following are summaries of LOE/Mcfe:

 
Three Months Ended
 
Three Months Ended
 
 
September 30, 2009
 
September 30, 2008
 
     
Gathering,
         
Gathering,
     
     
Compression
         
Compression
     
     
and
         
and
     
Location
LOE
 
Processing
 
Total
 
LOE
 
Processing
 
Total
 
                                     
New Mexico
  $ 1.47     $ 0.31     $ 1.78     $ 1.62     $ 0.25     $ 1.87  
Colorado
    1.07       0.41       1.48       1.22       0.71       1.93  
Wyoming
    1.29             1.29       1.21             1.21  
All other properties
    0.83       0.13       0.96       0.71       0.12       0.83  
                                                 
All locations
  $ 1.24     $ 0.20     $ 1.44     $ 1.26     $ 0.20     $ 1.46  


 
74

 


 
Nine Months Ended
 
Nine Months Ended
 
 
September 30, 2009
 
September 30, 2008
 
     
Gathering,
         
Gathering,
     
     
Compression
         
Compression
     
     
and
         
and
     
Location
LOE
 
Processing
 
Total
 
LOE
 
Processing
 
Total
 
                                     
New Mexico
  $ 1.29     $ 0.28     $ 1.57     $ 1.51     $ 0.29     $ 1.80  
Colorado
    1.02       0.41       1.43       1.17       0.80       1.97  
Wyoming
    1.41             1.41       1.54             1.54  
All other properties
    0.83       0.27       1.10       0.89       0.10       0.99  
                                                 
All locations
  $ 1.19     $ 0.22     $ 1.41     $ 1.33     $ 0.21     $ 1.54  

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008.  Income from continuing operations decreased $1.7 million for the three months ended September 30, 2009 compared to the same period in 2008 primarily due to:

 ·  
Revenue decreased $7.6 million due to a 28% decrease in the average hedged price of oil received, a 14% decrease in average hedged price of gas received, and a 10% decrease in production of gas and a 4% decrease in production of oil.  The gas production decrease reflects our decision to shut-in production at properties with the highest operating costs, impact of normal production declines, and lower levels of capital spending than in prior periods.  Shut-ins reduced production for the three months ended September 30, 2009 by approximately 0.2 Bcfe.
 
Partially offsetting these were the following:
 
 ·  
Decreased depletion and depreciation expense of $2.3 million primarily reflecting a reduced depletion rate caused by a lower asset base resulting from previous asset impairment charges and commodity price impacts on oil and gas reserve quantities; and
 
 ·  
A $2.2 million decrease in production taxes reflecting lower commodity prices.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008.  Income from continuing operations decreased $37.0 million for the nine months ended September 30, 2009 compared to the same period in 2008 primarily due to:

·  
A $27.8 million after-tax non-cash ceiling test impairment charge for the quarter ended March 31, 2009 due to a ceiling test valuation of our natural gas and crude oil properties resulting from low quarter-end natural gas prices.  The write-down of gas and oil properties was based on March 31, 2009 period-end NYMEX prices of $3.63 per Mcf, adjusted to $2.23 per Mcf at the wellhead, for natural gas; and $49.66 per barrel, adjusted to $45.32 per barrel at the wellhead, for crude oil; and

 
75

 


·  
A $33.5 million decrease in revenue due to a 36% decrease in the average hedged price of oil received, a 33% decrease in average hedged price of gas received, a 4% decrease in oil production and a 5% decrease in gas production.  The gas production decrease reflects our decision to shut-in production at properties with the highest operating costs, the impact of normal production declines and lower levels of capital spending than in prior periods.  Shut-ins reduced production for the nine months ended September 30, 2009 by approximately 0.4 Bcfe.

Partially offsetting these were the following:

·  
A $1.9 million decrease in LOE as compared to 2008 due to cost reduction efforts;

·  
A $7.3 million decrease in production taxes reflecting lower commodity prices; and

·  
A $3.8 million income tax benefit related to an adjustment of a previously recorded tax position.

Coal Mining

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
   
(in thousands)
 
                         
Revenue
  $ 15,187     $ 16,031     $ 43,082     $ 41,925  
Operating expenses
    14,167       14,210       42,836       38,556  
Operating income
  $ 1,020     $ 1,821     $ 246     $ 3,369  
                                 
Income from continuing
                               
operations and net income
                               
available for common stock
  $ 2,256     $ 1,092     $ 2,575     $ 3,217  

The following table provides certain operating statistics for our Coal Mining segment:

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
   
(in thousands)
 
                         
Tons of coal sold
    1,591       1,521       4,460       4,518  
Cubic yards of overburden
                               
moved
    4,187       3,368       10,822       9,021  


 
76

 

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008.
Income from continuing operations from our Coal Mining segment for the three months ended September 30, 2009 increased $1.2 million compared to the same period in the prior year.  Results were impacted by the following:

·  
A $2.1 million increase from rental income from a recently entered into lease agreement associated with the mine property site leased to the owners of Wygen III.  The agreement provides for a March 2008 start date reflecting the commencement of construction on Wygen III; and

·  
Operating expenses were comparable for the three months ended September 30, 2009 to the same period in the prior year primarily due to increases in depreciation expense of $0.8 million due to an increased asset base offsetting decreases in diesel fuel costs of $0.9 million.  Cubic yards of overburden moved increased 24%.

Partially offsetting these was the following:

·  
Revenue decreased $0.8 million, or 5%, for the three month period ended September 30, 2009 primarily due to a decrease in average price received, partially offset by higher volumes sold.  The lower average price received includes the impact of sales prices to our regulated utility subsidiaries that are determined in part by a return on investment base.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008.
Income from continuing operations from our Coal Mining segment for the nine months ended September 30, 2009 decreased $0.6 million compared to the same period in the prior year.  Results were impacted by the following:

 ·  
Operating expenses increased $4.3 million, or 11%, during the nine months ended September 30, 2009 primarily due to increased depreciation expense of $4.6 million due to increased equipment usage and an increased asset base, and increased coal taxes of $1.2 million due to higher coal prices, partially offset by decreased diesel fuel cost of $1.9 million.  Cubic yards of overburden moved increased 20%.
 
Partially offsetting the increased expenses were the following:
 
 ·  
Revenue increased $1.2 million, or 3%, for the nine month period ended September 30, 2009 compared to the same period in 2008 primarily due to an increase in average price received, partially offset by lower volumes sold.  The higher average price received includes the impact of sales prices to our regulated utility subsidiaries that are determined in part by a return on investment base; and
 
 ·  
A $2.4 million increase from rental income associated with the mine property leased to the owners of Wygen III.


 
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Energy Marketing

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
   
(in thousands)
 
                         
Revenue –
                       
Realized gas marketing
                       
gross margin
  $ 262     $ (4,477 )   $ 22,617     $ 3,384  
Unrealized gas marketing
                               
gross margin
    (5,252 )     26,889       (12,230 )     24,418  
Realized oil marketing
                               
gross margin
    1,525       (1,856 )     9,633       2,472  
Unrealized oil marketing
                               
gross margin
    (1,794 )     (1,360 )     (10,721 )     191  
      (5,259 )     19,196       9,299       30,465  
                                 
Operating expenses
    604       9,026       10,036       19,506  
Operating (loss) income
  $ (5,863 )   $ 10,170     $ (737 )   $ 10,959  
                                 
(Loss) income from continuing
                               
operations and net (loss) income
                               
available for common stock
  $ (4,404 )   $ 6,902     $ (1,156 )   $ 7,565  

The following is a summary of average daily volumes marketed:

   
Three Months Ended
 
Nine Months Ended
   
September 30,
 
September 30,
   
2009
   
2008
   
2009
2008
 
                 
Natural gas physical sales – MMBtus
    2,206,300       1,854,100     2,013,900     1,749,600  
                             
Crude oil physical sales – Bbls
    13,300       7,800     12,100     7,300  

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008.  Income from continuing operations decreased $11.3 million for the three months ended September 30, 2009 compared to the same period in 2008, primarily due to:

· A $32.6 million decrease in unrealized marketing margins.  The decrease results from the market circumstances that produced a substantial mark-to-market gain in the third quarter of the prior year.
 
Partially offsetting this decrease were the following:
 
· An $8.1 million increase in realized marketing margins primarily due to higher volumes and margin.  In addition, gross margins from crude oil were higher due to the impact of increased volumes marketed; and
 
· Lower operating expenses of $8.4 million primarily due to lower provision for incentive compensation expense.


 
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Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008.  Income from continuing operations decreased $8.7 million for the nine months ended September 30, 2009 compared to the same period in 2008, primarily due to:

· A $4.7 million decrease in unrealized marketing margins; and
 
· Lower operating expenses of $9.5 million primarily due to lower provision for incentive compensation expenses.
 
Partially offsetting these decreases was the following:
 
· A $26.4 million increase in realized marketing margins primarily due to higher volumes and margin.  In addition, gross margins from crude oil were higher due to the impact of increasing commodity prices and increased volumes marketed.

Power Generation

 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2009
 
2008
 
2009
 
2008
 
 
(in thousands)
 
                         
Revenue
  $ 7,538     $ 11,704     $ 22,372     $ 29,079  
Operating expense (gains)
    3,890       4,338       (13,888 )     18,877  
Operating income
  $ 3,648     $ 7,366     $ 36,260     $ 10,202  
                                 
Income from continuing
                               
operations
  $ 575     $ 3,197     $ 18,487     $ 1,828  

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

   
Three Months Ended
   
Nine Months Ended
 
   
September 30,
   
September 30,
 
   
2009
   
2008
   
2009
   
2008
 
                         
Contracted power plant fleet availability:
                       
Coal-fired plant
    98.7%       96.8%       95.6%       95.6%  
Natural gas-fired plants
    99.7%       99.4%       98.8%       93.6%  
Total availability
    99.1%       97.8%       96.9%       94.8%  


 
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Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008.  Income from continuing operations decreased $2.6 million for the three months ended September 30, 2009 compared to the same period in 2008, and was primarily impacted by:

· The sale of excess emission credits in 2008 for $2.7 million resulting from the decommissioning of the Ontario facility;
 
· A decrease of $0.8 million reflecting the net earnings impact of replacing MEAN’s 20 MW power purchase agreement with operating and site lease agreements related to their purchase of a 23.5% ownership interest in Wygen I; and
 
· An increase of $0.5 million in net interest expense related to intersegment debt restructuring.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008.  Income from continuing operations increased $16.7 million for the nine months ended September 30, 2009 compared to the same period in 2008, and was primarily impacted by:

· A $16.9 million after-tax gain on the sale to MEAN of a 23.5% ownership interest in the Wygen I power generation facility.  In conjunction with the sale, MEAN will make payments for costs associated with coal supply, plant operations and administrative services.  In addition, a 10-year power purchase contract under which MEAN was obligated to buy from us 20 MW of power annually was terminated; and
 
· 2008 results reflect $11.8 million of allocated indirect corporate costs and inter-segment net interest expense related to the IPP assets sold and not reclassified to discontinued operations.
 
Partially offsetting were the following:
 
· A decrease of $2.9 million reflecting the net earnings impact of replacing MEAN’s 20 MW power purchase agreement with operating and site lease agreements related to their purchase of a 23.5% ownership interest in Wygen I;
 
· An $8.5 million increase in net interest expense primarily due to a change in inter-segment debt to equity capital structure; and
 
· The sale of excess emission credits in 2008 for $2.7 million resulting from the decommissioning of the Ontario facility.


 
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Corporate

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008.  Loss from continuing operations increased $7.0 million primarily due to unrealized net, mark-to-market losses for the quarter ended September 30, 2009 of approximately $5.7 million after-tax on certain interest rate swaps and a $2.1 million after-tax increase in net interest expense.  In addition, 2008 results included approximately $0.6 million after-tax for transition and integration costs related to the Aquila Transaction.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008.  Income from continuing operations increased $21.1 million primarily due to unrealized net, mark-to-market gains for the nine months ended September 30, 2009 of approximately $24.6 million after-tax on certain interest rate swaps, partially offset by a $9.1 million after-tax increase in net interest expense.  In addition, 2008 results include $4.2 million after-tax for transition and acquisition costs related to the Aquila Transaction.

Discontinued Operations

Earnings from discontinued operations were $1.7 million and $2.4 million for the three and nine month periods ended September 30, 2009, respectively, compared to $159.5 million for the same period in 2008.  The income from discontinued operations in 2009 relates to the working capital and tax adjustments for the IPP Transaction.  The income from discontinued operations in 2008 relates primarily to the IPP Transaction with a gain on the sale of $139.7 million.

Critical Accounting Policies

There have been no material changes in our critical accounting policies from those reported in our 2008 Annual Report on Form 10-K filed with the SEC.  For more information on our critical accounting policies, see Part II, Item 7 of our 2008 Annual Report on Form 10-K.


 
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Liquidity and Capital Resources

Cash Flow Activities

During the nine month period ended September 30, 2009, we generated sufficient cash flow from operations to meet our operating needs, fund a portion of our property, plant and equipment additions and to pay dividends on our common stock.  We received proceeds of $51.9 million for the sale of a 23.5% interest in the Wygen I power plant to MEAN and $32.8 million for the sale to MDU of a 25% interest in the 110 MW Wygen III power plant under construction near Gillette, Wyoming.  We plan to fund future property and investment additions including our share of the construction costs of the Wygen III power plant and generation for Colorado Electric from internally generated cash resources and external financings.

Cash flows from operations of $270.9 million for the nine month period ended September 30, 2009 represent a $190.8 million increase compared to the same period in the prior year.  The increase in cash provided by operating activities for the current period was due to an increase of $1.8 million in our income from continuing operations and changes in working capital as follows:

· A $132.6 million increase in cash flows from working capital changes.  This increase primarily resulted from a $70.6 million increase in cash flows from lower materials, supplies and fuel, a $45.5 million increase from lower accounts receivable and other current assets and a $16.5 million increase from lower accounts payable and other current liabilities.  Changes in materials, supplies and fuel primarily relate to natural gas held in storage by Energy Marketing and the Gas Utilities which fluctuates based on seasonal trends and economic decisions reflecting current market conditions;
 
and adjusted for non-cash charges and other changes in operating items as follows:
 
       · A $71.4 million decrease in cash flows related to changes in deferred income taxes which is primarily a result of the deferred tax liability related to tax planning strategies implemented in connection with the IPP Transaction that occurred in 2008 and the deferred tax benefit associated with a non-cash ceiling test impairment charge applicable to our crude oil and natural gas properties recorded in 2009;
 
       · A $46.5 million increase in cash flows from the net change in derivative assets and liabilities primarily from derivatives associated with normal operations of our gas and oil marketing business and our Oil and Gas segment related to commodity price fluctuations;
 
· A $21.5 million increase in depreciation, depletion and amortization expense;
 
· A $43.3 million increase to adjust for the non-cash effect of the ceiling test impairment;
 
· A $26.0 million decrease to adjust for the non-cash effect of the gain on sale of operating assets.  This gain relates to the sale of the 23.5% interest in the Wygen I power plant to MEAN for which we received $51.9 million included in investing activities;
 
· A $37.8 million decrease to adjust for the non-cash effect of unrealized mark-to-market gains on interest rate swaps; and
 
·An $84.5 million increase in regulatory assets and liabilities primarily resulting from deferred gas adjustments for our Gas Utilities segment and employee benefit liabilities at our Electric Utilities and Gas Utilities.

 
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During the nine months ended September 30, 2009, we had cash outflows from investing activities of
$151.4 million, which were primarily due to the following:

· Cash outflows of $245.1 million for property, plant and equipment additions.  These outflows include approximately $35.7 million related to the construction of our Wygen III power plant, approximately $34.1 million at our Gas Utilities primarily for distribution, approximately $20.2 million in oil and gas property maintenance capital and development drilling, and approximately $140.6 million of distribution, transmission and generation at our Electric Utilities, which includes new transmission at Colorado Electric and a plant air condenser upgrade at Black Hills Power;
 
· Cash inflows of $51.9 million of proceeds from the sale of the 23.5% interest in the Wygen I power plant to MEAN;
 
· Cash inflows of $32.8 million of proceeds from the sale of the 25% interest in the Wygen III power plant to MDU; and
 
·Cash inflows of $7.1 million for working capital adjustments on the purchase price allocation of the Aquila Transaction.

During the nine months ended September 30, 2009, we had net cash outflows from financing activities of $150.4 million primarily resulting from:

· $353.3 million outflow for net re-payments on the Corporate Credit Facility and the Acquisition Facility;
 
· $41.3 million outflow for payments of cash dividends on common stock; and
 
·$248.5 million inflow from proceeds from issuance of senior unsecured five year notes.

Dividends

Dividends paid on our common stock totaled $41.3 million during the nine months ended September 30, 2009, or $0.355 per share.  On October 29, 2009, our Board of Directors declared a quarterly dividend of $0.355 per share payable December 1, 2009, which is equivalent to an annual dividend rate of $1.42 per share.  The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facilities and our future business prospects.


 
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Financing Transactions and Short-Term Liquidity

Our principal sources of short-term liquidity are our revolving credit facility and cash provided by operations.  As of September 30, 2009, we had approximately $137.7 million of cash unrestricted for operations.

Corporate Credit Facility

Our $525.0 million revolving credit facility expires on May 4, 2010.  The cost of borrowings or letters of credit issued under the facility is determined based on our credit ratings.  At our current ratings levels, the facility has an annual facility fee of 17.5 basis points, and has a borrowing spread of 70 basis points over LIBOR (which equates to a 0.95% one-month borrowing rate as of September 30, 2009).

Our revolving credit facility can be used to fund our working capital needs and for general corporate purposes.  At September 30, 2009, we had borrowings of $350.5 million and $37.7 million of letters of credit issued on our revolving credit facility.  Available capacity remaining on our revolving credit facility was approximately $136.8 million at September 30, 2009.

The credit facility includes customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and maintenance of the following financial covenants:

· A consolidated net worth in an amount of not less than the sum of $625 million and 50% of our aggregate consolidated net income beginning January 1, 2005;
 
· A recourse leverage ratio not to exceed 0.65 to 1.00; and
 
· An interest expense coverage ratio of not less than 2.5 to 1.0.

If these covenants are violated, it would be considered an event of default entitling the lenders to terminate the remaining commitment and accelerate all principal and interest outstanding.

In addition to covenant violations, an event of default under the credit facility may be triggered by other events, such as a failure to make payments when due or a failure to make payments when due in respect of, or a failure to perform obligations relating to, other debt obligations of $20 million or more.  Subject to applicable cure periods (none of which apply to a failure to timely pay indebtedness), an event of default would permit the lenders to restrict our ability to further access the credit facility for loans or new letters of credit, and could require both the immediate repayment of any principal and interest outstanding and the cash collateralization of outstanding letter of credit obligations.

The credit facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result, after giving effect to such action.

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 were required to maintain under the credit facility.  At September 30, 2009, our long-term debt ratio was 40.4%, our total debt 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.


 
84

 


 
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 participating banks: Calyon, Rabobank and RZB Finance.  This credit facility expires on May 7, 2010.  The facility 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.  At September 30, 2009, $71.7 million of letters of credit were issued under this facility and there were no cash borrowings outstanding.

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.

Acquisition Facility

In July 2008, in conjunction with the closing of the Aquila Transaction, we borrowed $382.8 million under our $1 billion bridge acquisition credit facility dated May 7, 2007.  The Acquisition Facility was structured as a single-draw term loan facility for the sole purpose of financing the Aquila Transaction.

On April 9, 2009, we received proceeds of $30.2 million for the sale of 25% of the Wygen III plant to MDU.  The net proceeds were used to pay down a portion of the Acquisition Facility.

On May 14, 2009, we received proceeds from a $250 million public debt offering.  The net proceeds were used to pay down a portion of the Acquisition Facility.

On June 15, 2009, we paid off the remaining $104.6 million balance of the Acquisition Facility by borrowing on our Corporate Credit Facility.


 
85

 

Public 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 notes.

Black Hills Power Bond Issuance

On October 27, 2009, our regulated utility, Black Hills Power, completed a $180 million first mortgage bond issuance.  The bonds were priced at 99.931% of par and a reoffer yield of 6.13%.  The bonds mature November 1, 2039 and carry an annual interest rate of 6.125%, which will be paid semi-annually.  We received proceeds of $178.3 million net of underwriting fees, which were used to repay borrowings under the Corporate Credit Facility.  Estimated deferred finance costs of $1.9 million were capitalized and will be amortized over the life of the bonds.

Future Financing Plans

We have an effective shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities.  Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our finance arrangements and restrictions imposed by federal and state regulatory authorities.

 
We continue to evaluate the debt capital markets and prepare for additional long-term debt issuances to refinance other short-term debt and fund our power generation construction projects.

In the unlikely event we are unable to complete debt financing on acceptable terms, we will consider implementing alternative measures to conserve or raise capital.  These alternatives could include deferring our planned capital expenditure program, implementing asset sales, issuing equity, reducing or eliminating our dividend payments, or curtailing certain business activities, including our marketing operations.

Interest Rate Swaps

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


 
86

 

We have interest rate swaps with a notional amount of $250.0 million that are not designated as hedge instruments.  Accordingly, mark-to-market changes in value on the swaps are recorded within the income statement.  For the three months ended September 30, 2009, we recorded an $8.7 million pre-tax unrealized mark-to-market non-cash loss and for the nine months ended September 30, 2009, we recorded a $37.8 million pre-tax unrealized mark-to-market non-cash gain on the swaps.  The mark-to-market value on these swaps was a liability of $56.7 million at September 30, 2009.  Subsequent mark-to-market adjustments could have a significant impact on our results of operations.  A one basis point move in the interest rate curves over the term of the swaps would have a pre-tax impact of approximately $0.3 million. These swaps are for terms of ten and twenty years and have amended mandatory early termination dates ranging from December 15, 2009 to December 15, 2010.  We have continued to maintain these swaps in anticipation of our upcoming financing needs, particularly as they relate to our planned capital requirements to build gas-fired power generation facilities to serve our Colorado Electric customers, and because of our upcoming holding company debt maturities, which are $225 million and $250 million in years 2013 and 2014, respectively.  Alternatively, we may choose to cash settle these swaps at their fair value prior to their mandatory early termination dates, or unless these dates are extended, we will cash settle these swaps for an amount equal to their fair value on the termination dates.

In addition, we have $150.0 million notional amount floating-to-fixed interest rate swaps, having a maximum term of 7.25 years.  These swaps have been designated as cash flow hedges and accordingly, their mark-to-market adjustments are recorded in Accumulated other comprehensive loss on the accompanying Condensed Consolidated Balance Sheets.  The mark-to-market value of these swaps was a liability of $19.5 million at September 30, 2009.

There have been no other material changes in our financing transactions and short-term liquidity from those reported in Item 7 of our 2008 Annual Report on Form 10-K filed with the SEC.

Credit Ratings

Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements.  As of September 30, 2009, our senior unsecured credit ratings, as assessed by the three major credit rating agencies, were as follows:

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

In addition, the first mortgage bonds issued by Black Hills Power were rated at September 30, 2009 as follows:

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

In August 2009, Moody’s upgraded the senior secured debt rating for Black Hills Power to A3.

 
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Capital Requirements

During the nine months ended September 30, 2009, capital expenditures were approximately $245.1 million for property, plant and equipment additions, which were partially financed through approximately $31.2 million of accrued liabilities.  We currently expect total capital expenditures in 2009 to approximate $340.7 million.  This sum includes, but is not limited to:  $62.1 million for our share of the Wygen III power plant located near Gillette, Wyoming in which we retain a 75% ownership interest; $62.9 million related to growth and maintenance capital for our Black Hills Energy utility properties, and $25.0 million within our Oil and Gas segment primarily for maintenance capital and development drilling.

Actual and forecasted capital requirements for maintenance capital and development capital are as follows:

 
Nine Months
             
 
Ended
             
 
September 30,
 
Total
 
Total
 
Total
 
 
2009
 
2009 Planned
 
2010 Planned
 
2011 Planned
 
 
Expenditures
 
Expenditures
 
Expenditures
 
Expenditures
 
 
(in thousands)
 
Utilities:
                       
Electric Utilities – Wygen III(1)
  $ 35,700     $ 62,100     $ 12,600     $  
Electric Utilities (2) (3)
    143,037       157,400       256,900       259,400  
Gas Utilities
    33,907       39,600       56,450       56,070  
Non-regulated Energy:
                               
Oil and Gas(4)
    20,243       25,000       38,340       63,810  
Power Generation(5)
    4,452       30,242       82,690       147,820  
Coal Mining
    6,792       13,160       17,630       17,260  
Energy Marketing
    128       811       400        
Corporate
    855       12,340       16,290       10,400  
    $ 245,114     $ 340,653     $ 481,300     $ 554,760  
__________________________
(1)  
Actual and forecasted expenditures for the Wygen III coal-fired plant reflect our 75% ownership interest in the plant.
(2)  
Electric Utilities capital requirements include approximately $22.3 million for transmission projects in 2009.
(3)  
The 2009 total planned expenditures include capital requirements associated with our plans to build gas-fired power generation facilities to serve our Colorado Electric customers.  In February 2009, the CPUC authorized Colorado Electric to build two natural gas-fired combustion turbine facilities.  We expect to spend capital of $47.9 million in 2009 particularly related to the commitment to purchase the turbine generators from GE.  The total construction cost is expected to be approximately $225 million to $275 million to be completed by the end of 2011. The mid-point of this estimate is included in the forecast above.
(4)  
Development capital for our oil and gas properties is expected to be limited to no more than the cash flows produced by those properties.  Continued low commodity prices could further reduce our planned development capital expenditures.
(5)  
Our Power Generation segment was awarded the bid to provide 200 MW of power for a twenty year period to Colorado Electric.  The total construction cost is expected to be approximately $240 million to $265 million which is expected to be completed by the end of 2011.  We expect to spend approximately $26.5 million in 2009.  The mid-point of this estimate is included in the forecast above.


 
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As a result of our desire to preserve liquidity in light of the current global credit crisis we are continually evaluating all of our forecasted capital expenditures, and if determined prudent, may defer some of these expenditures for a period of time.  Future projects are dependent upon the availability of attractive economic opportunities, and as a result, actual expenditures may vary significantly from forecasted estimates.

Contractual Obligations

Unconditional purchase obligations for firm transportation and storage fees for our Energy Marketing segment decreased $0.3 million from $93.5 million at December 31, 2008 to $93.2 million at September 30, 2009.  Approximately $56.3 million of the firm transportation and storage fee obligations relate to the 2009-2011 period with the remaining occurring thereafter.

In June 2009, we entered into a ten and a half year lease obligation to relocate our office located in Golden, Colorado to Denver, Colorado.  Total obligations over the ten and a one-half year lease are $14.7 million.  This lease contained certain landlord incentives including rent abatement, relocation and tenant finishes.

Guarantees

See Note 7 to our Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

New Accounting Pronouncements

Other than the new pronouncements reported in our 2008 Annual Report on Form 10-K filed with the SEC and those discussed in Notes 2 and 3 of the Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q, there have been no new accounting pronouncements that affect us.


 
89

 

FORWARD-LOOKING INFORMATION

This report contains forward-looking information.  All statements, other than statements of historical fact, included in this report that address activities, events, or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements.  These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business.  Forward-looking information involves risks and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated.  In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potential,” or “continue” or the negative of these terms or other similar terminology.  There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurance that such indicated results will be realized.  The forward-looking statements include the factors discussed above, the risk factors described in Item 1A. of our 2008 Annual Report on Form 10-K previously filed with the SEC, and other reports that we file with the SEC from time to time, and the following:

· We are evaluating financing options including first mortgage bonds, term loans, project financing and equity issuance.  Some important factors that could cause actual results to differ materially from those anticipated include:
 
    § Our ability to access the bank loan and debt capital markets depends on market conditions beyond our control.  If the credit markets deteriorate, we may not be able to permanently refinance some short-term debt and fund our power generation projects on reasonable terms, if at all.
 
    § Our ability to raise capital in the debt capital markets depends upon our financial condition and credit ratings, among other things.  If our financial condition deteriorates unexpectedly, or our credit ratings are lowered, we may not be able to refinance some short-term debt and fund our power generation projects on reasonable terms, if at all.
 
· We anticipate that our existing credit capacity and available cash will be sufficient to fund our working capital needs and our maintenance capital requirements.  Some important factors that could cause actual results to differ materially from those anticipated include:
 
    § Our access to revolving credit capacity depends on maintaining compliance with loan covenants.  If we violate these covenants, we may lose revolving credit capacity and not have sufficient cash available for our peak winter needs and other working capital requirements, and our forecasted capital expenditure requirements.
 
    § Counterparties may default on their obligations to supply commodities, return collateral to us, or otherwise meet their obligations under commercial contracts, including those designed to hedge against movements in commodity prices.
 
    § We expect to fund a portion of our capital requirements for the planned regulated and non-regulated generation additions to supply our Colorado Electric subsidiary through a combination of long-term debt and issuance of equity.


 
90

 


      · We expect contributions to our defined benefit pension plans to be approximately $0 million and $7.7 million for the remainder of 2009 and for 2010, respectively.  Some important factors that could cause actual contributions to differ materially from anticipated amounts include:
 
    § The actual value of the plans’ invested assets.
 
    § The discount rate used in determining the funding requirement.
 
· We expect the goodwill related to our utility assets to fairly reflect the long-term value of stable, long-lived utility assets.  Some important factors that could cause us to revisit the fair value of this goodwill include:
 
    § A significant, sustainable deterioration of the market value of our common stock.
 
    § Negative regulatory orders or other events that materially impact our Utilities’ ability to generate stable cash flow over an extended period of time.
 
· We expect to make approximately $340.7 million, $481.3 million and $554.8 million of capital expenditures in 2009, 2010 and 2011, respectively.  Some important factors that could cause actual costs to differ materially from those anticipated include:
 
    § The timing of planned generation, transmission or distribution projects for our Utilities is influenced by state and federal regulatory authorities and third parties.  The occurrence of events that impact (favorably or unfavorably) our ability to make planned or unplanned capital expenditures could cause our forecasted capital expenditures to change.
 
    § Forecasted capital expenditures associated with our Oil and Gas segment are driven, in part, by current market prices.  A continued decline in crude oil and natural gas prices may cause us to change our planned capital expenditures related to our oil and gas operations.
 
    § Our ability to complete the planning, permitting, construction, start-up and operation of power generation facilities in a cost-efficient and timely manner.
 
       · The timing, volatility, and extent of changes in energy and commodity prices, supply or volume, the cost and availability of transportation of commodities, changes in interest or foreign exchange rates, and the demand for our services, any of which can affect our earnings, our financial liquidity and the underlying value of our assets including the possibility that we may be required to take future impairment charges under the SEC’s full cost ceiling test for natural gas and oil reserves.
 
· Federal and state laws concerning climate change and air emissions, including emission reduction mandates, carbon emmissions and renewable energy portfolio standards, may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.



 
91

 

ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK

Utilities

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

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

   
September 30,
   
December 31,
   
September 30,
 
   
2009
   
2008
   
2008
 
                   
Net derivative assets (liabilities)
  $ 3,210     $ (7,444 )   $ 9,424  
Cash collateral
    1,840       8,744       12,750  
                         
    $ 5,050     $ 1,300     $ 22,174  


 
92

 

Non Regulated Trading Activities

The following table provides a reconciliation of activity in our natural gas and crude oil marketing portfolio that has been recorded at fair value including market value adjustments on inventory positions that have been designated as part of a fair value hedge during the nine months ended September 30, 2009 (in thousands):

Total fair value of energy marketing positions marked-to-market at December 31, 2008
  $ 28,447 (a)
Net cash settled during the period on positions that existed at December 31, 2008
    (34,477 )
Unrealized gain on new positions entered during the period and still existing at
       
September 30, 2009
    5,423  
Realized gain on positions that existed at December 31, 2008 and were settled during
       
the period
    (4,563 )
Change in cash collateral
    21,144  
Unrealized gain on positions that existed at December 31, 2008 and still exist at
       
September 30, 2009
    10,646  
         
Total fair value of energy marketing positions at September 30, 2009
  $ 26,620 (a)
_____________________________
(a)  
The fair value of energy marketing positions consists of derivative assets/liabilities held at fair value in accordance with accounting standards for fair value measurements and market value adjustments to natural gas inventory that has been designated as a hedged item as part of a fair value hedge in accordance with accounting standards for derivatives and hedges, as follows (in thousands):

   
September 30,
   
June 30,
   
March 31,
   
December 31,
 
   
2009
   
2009
   
2009
   
2008
 
                         
Net derivative assets
  $ 23,054     $ 32,352     $ 39,843     $ 54,117  
Cash collateral
    4,829       9,267       (3,673 )     (16,315 )
Market adjustment recorded
                               
in material, supplies and fuel
    (1,263 )     (3,815 )     (2,399 )     (9,355 )
                                 
    $ 26,620     $ 37,804     $ 33,771     $ 28,447  

To value the assets and liabilities for our outstanding derivative contracts, we use the fair value methodology outlined in ASC 820.  See Note 3 of the Notes to Consolidated Financial Statements in our 2008 Annual Report on Form 10-K and Note 12, Note 13 and Note 14 of the accompanying Notes to Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.

 
93

 

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

Source of Fair Value
 
Maturities
 
of Energy Marketing Positions
 
Less than 1 year
   
1 – 2 years
   
Total Fair Value
 
                   
Cash collateral
  $ 4,829     $     $ 4,829  
Level 2
    15,893       3,845       19,738  
Level 3
    3,375       (59 )     3,316  
Market value adjustment for inventory
                       
 (see footnote (a) above)
    (1,263 )           (1,263 )
                         
Total fair value of our energy
                       
marketing positions
  $ 22,834     $ 3,786     $ 26,620  

GAAP restricts mark-to-market accounting treatment primarily to only those contracts that meet the definition of a derivative under ASC 815.  Therefore, the above reconciliation does not present a complete picture of our overall portfolio of trading activities or our expected cash flows from energy trading activities.  In our natural gas and crude oil marketing operations, we often employ strategies that include utilizing derivative contracts along with inventory, storage and transportation positions to accomplish the objectives of our producer services, end-use origination and wholesale marketing groups.  Except in circumstances when we are able to designate transportation, storage or inventory positions as part of a fair value hedge, accounting standards for derivatives generally does not allow us to mark our inventory, transportation or storage positions to market.  The result is that while a significant majority of our energy marketing positions are fully economically hedged, we are required to mark some parts of our overall strategies (the derivatives) to market value, but are generally precluded from marking the rest of our economic hedges (transportation, inventory or storage) to market.  Volatility in reported earnings and derivative positions should be expected given these accounting requirements.  The table below references non-GAAP measures that quantify these positions.

The following table presents a reconciliation of our September 30, 2009 energy marketing positions recorded at fair value under GAAP to a non-GAAP measure of the fair value of our energy marketing forward book wherein all forward trading positions are marked-to-market (in thousands):

Fair value of our energy marketing positions marked-to-market in accordance with GAAP
     
(see footnote (a) above)
  $ 26,620  
Market value adjustments for inventory, storage and transportation positions that are
       
part of our forward trading book, but that are not marked-to-market under GAAP
    (4,556 )
Fair value of all forward positions (non-GAAP)
    22,064  
Cash collateral included in GAAP marked-to-market fair value
    (4,829 )
Fair value of all forward positions excluding cash collateral (non-GAAP) *
  $ 17,235  
_____________________________
* We consider this measure a Non-GAAP financial measure.  This measure is presented because we believe it provides a more comprehensive view to our investors of our energy trading activities and thus a better understanding of these activities than would be presented by GAAP measure alone.

There have been no material changes in market risk compared to those reported in our 2008 Annual Report on Form 10-K filed with the SEC.  For more information on market risk, see Part II, Items 7 and 7A. in our 2008 Annual Report on Form 10-K, and Note 13 of the Notes to our Condensed Consolidated Financial Statements in this Quarterly Report on Form 10-Q.


 
94

 

Activities Other Than Trading

We have entered into agreements to hedge a portion of our estimated 2009, 2010 and 2011 natural gas and crude oil production from the Oil and Gas segment.  The hedge agreements in place are as follows:

Natural Gas

Location
Transaction Date
Hedge Type
Term
 
Volume
   
Price
 
         
(MMBtu/day)
       
AECO
09/07/2007
Swap
04/08 – 10/09
    1,000     $ 6.89  
San Juan El Paso
10/29/2007
Swap
10/09 – 12/09
    5,000     $ 7.53  
CIG
10/29/2007
Swap
10/09 – 12/09
    1,500     $ 7.07  
NWR
11/16/2007
Swap
01/09 – 12/09
    1,500     $ 6.87  
San Juan El Paso
12/13/2007
Swap
10/09 – 12/09
    1,500     $ 7.39  
San Juan El Paso
12/13/2007
Swap
10/09 – 12/09
    1,500     $ 7.41  
CIG
01/03/2008
Swap
01/10 – 03/10
    2,000     $ 7.49  
NWR
01/03/2008
Swap
01/10 – 03/10
    1,500     $ 7.50  
AECO
01/03/2008
Swap
11/09 – 03/10
    1,000     $ 8.07  
San Juan El Paso
01/23/2008
Swap
01/10 – 03/10
    5,000     $ 7.50  
San Juan El Paso
02/28/2008
Swap
01/10 – 03/10
    3,000     $ 8.55  
San Juan El Paso
04/09/2008
Swap
04/10 – 06/10
    5,000     $ 7.26  
San Juan El Paso
04/30/2008
Swap
04/10 – 06/10
    2,500     $ 7.65  
AECO
08/20/2008
Swap
04/10 – 06/10
    1,000     $ 7.73  
San Juan El Paso
08/20/2008
Swap
07/10 – 09/10
    5,000     $ 7.74  
AECO
08/20/2008
Swap
07/10 – 09/10
    1,000     $ 7.88  
AECO
10/24/2008
Swap
10/10 – 12/10
    1,000     $ 7.05  
San Juan El Paso
12/19/2008
Swap
10/09 – 12/09
    1,000     $ 5.12  
San Juan El Paso
12/19/2008
Swap
04/10 – 06/10
    1,500     $ 5.39  
San Juan El Paso
12/19/2008
Swap
07/10 – 09/10
    3,000     $ 5.95  
San Juan El Paso
12/19/2008
Swap
10/10 – 12/10
    5,000     $ 5.89  
CIG
01/26/2009
Swap
04/10 – 06/10
    2,000     $ 4.45  
CIG
01/26/2009
Swap
07/10 – 09/10
    2,000     $ 4.47  
CIG
01/26/2009
Swap
10/10 – 12/10
    2,000     $ 4.68  
CIG
01/26/2009
Swap
01/11 – 03/11
    2,000     $ 6.00  
NWR
01/26/2009
Swap
01/11 – 03/11
    2,000     $ 6.05  
San Juan El Paso
01/26/2009
Swap
01/11 – 03/11
    5,000     $ 6.38  
San Juan El Paso
02/13/2009
Swap
01/11 – 03/11
    2,500     $ 6.16  
San Juan El Paso
02/13/2009
Swap
10/10 – 12/10
    3,000     $ 5.35  
NWR
02/13/2009
Swap
04/10 – 12/10
    1,000     $ 4.20  
AECO
03/04/2009
Swap
01/11 – 03/11
    1,000     $ 5.95  
NWR
03/04/2009
Swap
04/10 – 06/10
    1,000     $ 4.06  
NWR
03/04/2009
Swap
07/10 – 09/10
    1,000     $ 4.12  
NWR
03/04/2009
Swap
10/10 – 12/10
    1,000     $ 4.55  
NWR
03/20/2009
Swap
01/10 – 03/10
    500     $ 4.58  
San Juan El Paso
03/20/2009
Swap
01/10 – 03/10
    1,000     $ 4.87  
San Juan El Paso
06/02/2009
Swap
04/11 – 06/11
    5,000     $ 5.99  
San Juan El Paso
06/02/2009
Swap
10/09 – 12/09
    1,500     $ 4.14  
AECO
06/02/2009
Swap
04/11 – 06/11
    800     $ 5.89  
NWR
06/02/2009
Swap
10/09 – 12/09
    500     $ 3.95  
NWR
06/02/2009
Swap
04/11 – 06/11
    1,500     $ 5.54  
San Juan El Paso
06/25/2009
Swap
04/11 – 06/11
    2,500     $ 5.55  
CIG
06/25/2009
Swap
04/11 – 06/11
    1,750     $ 5.33  
CIG
09/02/2009
Swap
07/11 – 09/11
    500     $ 5.32  
NWR
09/02/2009
Swap
07/11 – 09/11
    500     $ 5.32  

 
95

 

Natural Gas

Location
Transaction Date
Hedge Type
Term
 
Volume
   
Price
 
         
(MMBtu/day)
       
San Juan El Paso
09/02/2009
Swap
07/11 – 09/11
    2,500     $ 5.54  
CIG
09/25/2009
Swap
07/11 – 09/11
    500     $ 5.59  
NWR
09/25/2009
Swap
07/11 – 09/11
    1,000     $ 5.59  
AECO
09/25/2009
Swap
07/11 – 09/11
    500     $ 5.76  
San Juan El Paso
09/25/2009
Swap
07/11 – 09/11
    5,000     $ 5.91  
San Juan El Paso
10/09/2009
Swap
01/10 – 03/10
    2,000     $ 5.42  
San Juan El Paso
10/09/2009
Swap
04/10 – 06/10
    750     $ 5.29  
San Juan El Paso
10/09/2009
Swap
07/10 – 09/10
    1,000     $ 5.65  
San Juan El Paso
10/09/2009
Swap
10/10 – 12/10
    1,000     $ 5.90  
San Juan El Paso
10/23/2009
Swap
10/11 – 12/11
    2,500     $ 6.23  
NWR
10/23/2009
Swap
10/11 – 12/11
    1,500     $ 6.12  
San Juan El Paso
10/23/2009
Swap
01/11 – 03/11
    1,000     $ 6.59  


 
96

 

Crude Oil

Location
Transaction Date
Hedge Type
Term
 
Volume
   
Price
 
         
(Bbls/month)
       
                   
NYMEX
10/29/2007
Put
10/09 – 12/09
    5,000     $ 75.00  
NYMEX
10/29/2007
Swap
10/09 – 12/09
    5,000     $ 80.75  
NYMEX
11/16/2007
Put
10/09 – 12/09
    5,000     $ 75.00  
NYMEX
01/03/2008
Put
01/10 – 03/10
    5,000     $ 80.00  
NYMEX
01/03/2008
Swap
01/10 – 03/10
    5,000     $ 88.70  
NYMEX
01/23/2008
Swap
10/09 – 12/09
    5,000     $ 83.10  
NYMEX
01/23/2008
Swap
01/10 – 03/10
    5,000     $ 82.90  
NYMEX
02/28/2008
Put
01/10 – 03/10
    5,000     $ 85.00  
NYMEX
04/09/2008
Swap
04/10 – 06/10
    5,000     $ 99.60  
NYMEX
04/30/2008
Put
04/10 – 06/10
    5,000     $ 85.00  
NYMEX
05/29/2008
Put
04/10 – 06/10
    5,000     $ 105.00  
NYMEX
07/16/2008
Swap
04/10 – 06/10
    5,000     $ 135.10  
NYMEX
07/16/2008
Swap
07/10 – 09/10
    5,000     $ 134.90  
NYMEX
08/20/2008
Put
07/10 – 09/10
    5,000     $ 90.00  
NYMEX
09/03/2008
Put
07/10 – 09/10
    5,000     $ 90.00  
NYMEX
10/24/2008
Put
07/10 – 09/10
    5,000     $ 60.00  
NYMEX
12/05/2008
Swap
10/10 – 12/10
    5,000     $ 65.20  
NYMEX
01/26/2009
Swap
10/10 – 12/10
    5,000     $ 60.15  
NYMEX
01/26/2009
Swap
01/11 – 03/11
    5,000     $ 60.90  
NYMEX
02/13/2009
Swap
01/11 – 03/11
    5,000     $ 60.05  
NYMEX
03/04/2009
Swap
10/10 – 12/10
    5,000     $ 55.80  
NYMEX
03/04/2009
Swap
01/11 – 03/11
    5,000     $ 57.00  
NYMEX
04/08/2009
Swap
04/11 – 06/11
    5,000     $ 68.80  
NYMEX
04/23/2009
Swap
04/11 – 06/11
    5,000     $ 65.10  
NYMEX
06/02/2009
Swap
10/10 – 12/10
    5,000     $ 74.30  
NYMEX
06/02/2009
Swap
01/11 – 03/11
    5,000     $ 75.05  
NYMEX
06/02/2009
Swap
04/11 – 06/11
    5,000     $ 75.86  
NYMEX
06/04/2009
Put
04/11 – 06/11
    5,000     $ 67.00  
NYMEX
09/02/2009
Swap
07/11 – 09/11
    5,000     $ 75.10  
NYMEX
09/02/2009
Put
07/11 – 09/11
    5,000     $ 63.00  
NYMEX
09/29/2009
Swap
07/11 – 09/11
    5,000     $ 74.00  
NYMEX
10/06/2009
Put
07/11 – 09/11
    5,000     $ 65.00  
NYMEX
10/09/2009
Swap
10/11 – 12/11
    5,000     $ 79.35  
NYMEX
10/23/2009
Put
10/11 – 12/11
    5,000     $ 75.00  



 
97

 

ITEM 4.
CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) as of September 30, 2009.  Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

There have been no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2009 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.


 
98

 

BLACK HILLS CORPORATION

Part II – Other Information

Item 1.
Legal Proceedings

For information regarding legal proceedings, see Note 18 in Item 8 of our 2008 Annual Report on Form 10-K and Note 16 in Item 1 of Part I of this Quarterly Report on Form 10-Q, which information from Note 16 is incorporated by reference into this item.

Item 1A.
Risk Factors

Except to the extent updated or described below, our Risk Factors are documented in Item IA. of Part I in our Annual Report on Form 10-K for the year ended December 31, 2008.

Federal and state laws concerning climate change and air emissions, including emission reduction mandates and renewable energy portfolio standards, may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.
 
We own and operate regulated and non-regulated fossil-fuel generating plants in South Dakota, Wyoming, Colorado and Idaho. We are constructing another fossil-fuel generating plant in Wyoming. Air emissions of fossil-fuel generating plants are subject to federal, state and tribal regulation. Recent developments under federal and state laws and regulation governing air emissions from fossil-fuel generating plants will likely result in more stringent emission limitations.

On April 2, 2007, the U.S. Supreme Court issued a decision in the case of Massachusetts v. U.S. Environmental Protection Agency, holding that CO2 and other GHG emissions are pollutants subject to regulation under the motor vehicle provisions of the Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or alternatively, to explain why GHG emissions should not be regulated.  On April 17, 2008, the EPA issued its proposed endangerment finding under Section 202 of the Clean Air Act. Although this proposal does not specifically address stationary sources, such as power generation plants, the general endangerment finding relative to GHG’s could support such a proposal by the EPA for stationary sources. On March 10, 2009, the EPA released proposed rules regarding a mandatory GHG reporting regimen, the purpose of which would be to collect data to inform future policy and regulatory decisions.  Finally, federal legislation is currently under consideration in the U.S. Congress, including H.R. 2454, “the American Clean Energy and Security Act of 2009”, which was approved by the U.S. House of Representatives on June 26, 2009. This legislation would affect electric generation and electric and natural gas distribution companies. H.R. 2454 would establish mandatory GHG reduction targets, utilizing a Federal emissions cap-and-trade program. H.R.2454 also proposes a national renewable electricity standard, which would implement a phased process ultimately mandating that 20% of electricity sold by retail suppliers be met by energy efficiency improvements and renewable energy resources by 2020. The Senate is expected to consider its own version of the legislation later in 2009 or in 2010.


 
99

 

In addition, the EPA published in the October 27, 2009 Federal Register a proposed rule that would tailor the major source applicability thresholds for GHG emissions under the Prevention of Significant Deterioration (PSD) and Title V programs of the Clean Air Act and set a PSD significance level for GHG emissions.  EPA states this rule is necessary because they expect to soon promulgate regulations under the Clean Air Act to control GHG emissions and as a result, trigger PSD and Title V applicability requirements.  This proposed rule would phase in the applicability thresholds for both the PSD and Title V programs for sources of GHG emissions.  The first phase, which would last 6 years, would establish a temporary level for the PSD and Title V applicability thresholds at 25,000 tons per year on a carbon dioxide equivalent basis and would also establish temporary PSD significance levels.  All our generating units would exceed this threshold and if the pending rule to control GHG emissions is published and finalized, we would be required upon Title V permit renewal, to evaluate options for reducing GHG emissions, to possibly include a Best Available Control Technology review that could result in more stringent emissions control practices and technologies.  In the second phase of this proposed rule, EPA would within 5 years of the rule being final, review the first phase and promulgate revised applicability and significance level thresholds as appropriate.

Due to the uncertainty as to the final outcome of federal climate change legislation, or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG regulation on our results of operations, cash flows or financial position. The impact of GHG legislation or regulation upon our company will depend upon many factors, including but not limited to the timing of implementation, the GHG sources that are regulated, the overall GHG emissions cap level, and the availability of technologies to control or reduce GHG emissions. If a “cap and trade” structure is implemented, the impact will also be affected by the degree to which offsets are allowed, the allocation of emission allowances to specific sources, and the affect of carbon regulation on natural gas and coal prices.

More stringent GHG emissions limitations or other energy efficiency requirements, however, could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, and the closure of certain generating facilities. To the extent our regulated fossil-fuel generating plants are included in rate base, we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by our non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.
 
We own electric utilities that serve customers in Colorado, Montana, South Dakota and Wyoming. To varying degrees, Colorado and Montana have each adopted mandatory renewable portfolio standards that require electric utilities to supply a minimum percentage of the power delivered to customers from renewable resources (e.g., wind, solar, biomass) by a certain date in the future. These renewable energy portfolio standards have increased the power supply costs of our electric operations. If these states increase their renewable energy portfolio standards, or if similar standards are imposed by the other states in which we operate electric utilities, our power supply costs will further increase. Although we will seek to recover these higher costs in rates, any unrecovered costs could have a material negative impact on our results of operations and financial condition.

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

Issuer Purchases of Equity Securities

                 
Maximum
 
             
Total
 
Number (or
 
             
Number
 
Approximate
 
             
of Shares
 
Dollar
 
   
Total
       
Purchased as
 
Value) of Shares
 
   
Number
       
Part of Publicly
 
That May Yet Be
 
   
of
 
Average
   
Announced
 
Purchased Under
 
   
Shares
 
Price Paid
   
Plans
 
the Plans
 
Period
 
Purchased(1)
 
per Share
   
or Programs
 
or Programs
 
                         
July 1, 2009 –
                       
July 31, 2009
    143     $ 22.99              
                                 
August 1, 2009 –
                               
August 31, 2009
    3,551     $ 26.48              
                                 
September 1, 2009 –
                               
September 30, 2009
        $              
                                 
Total
    3,694     $ 26.34              
__________________________
 
(1)
Shares were acquired from certain officers and key employees under the share withholding provisions of the Omnibus Incentive Plan for the payment of taxes associated with the vesting of shares of Restricted Stock.


 
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Item 6.
Exhibits
 
 
Exhibit 4
Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon, as Trustee to Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (previously filed as Exhibit 4.21 to the Company’s Post-Effective Amendment No. 2 to the Registration Statement on Form S-3 (File No. 333-150669) and incorporated by reference herein).
     
 
Exhibit 10
First Amendment to Third Amended and Restated Credit Agreement effective August 25, 2009, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, Societe Generale, BNP Paribas, and each of the other financial institutions which are parties thereto.
     
 
Exhibit 31.1
Certification of Chief Executive Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.
     
 
Exhibit 31.2
Certification of Chief Financial Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.
     
 
Exhibit 32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.
     
 
Exhibit 32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.



 
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BLACK HILLS CORPORATION

Signatures

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

 
BLACK HILLS CORPORATION
   
   
 
/s/ David R. Emery
 
David R. Emery, Chairman, President and
 
Chief Executive Officer
   
   
 
/s/ Anthony S. Cleberg
 
Anthony S. Cleberg, Executive Vice President
 
and Chief Financial Officer
   
   
Dated:  November 9, 2009
 



 
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EXHIBIT INDEX


Exhibit Number
Description
   
Exhibit 4
Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon, as Trustee to Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (previously filed as Exhibit 4.21 to the Company’s Post-Effective Amendment No. 2 to the Registration Statement on Form S-3 (File No. 333-150669) and incorporated by reference herein).
   
Exhibit 10
First Amendment to Third Amended and Restated Credit Agreement effective August 25, 2009, among Enserco Energy Inc., the borrower, Fortis Capital Corp., as administrative agent, document agent and collateral agent, Societe Generale, BNP Paribas, and each of the other financial institutions which are parties thereto.
   
Exhibit 31.1
Certification of Chief Executive Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.
   
Exhibit 31.2
Certification of Chief Financial Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.
   
Exhibit 32.1
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.
   
Exhibit 32.2
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.


 
104