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

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
 For the quarterly period ended September 30, 2009.March 31, 2010.
OR 
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
 For the transition period from __________ to __________.
  
 Commission File Number 1-7978

Black Hills Power, Inc.
Incorporated in South DakotaIRS Identification Number 46-0111677
625 Ninth Street, Rapid City, South Dakota  57701
  
Registrant’sRegistrant'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.

 Yesx Noo 

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).

 Yeso Noo 

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 filero Accelerated filero 

 Non-accelerated filerx Smaller reporting companyo 

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 Yeso Nox 

As of OctoberApril 30, 2009,2010, there were issued and outstanding 23,416,396 shares of the Registrant’sRegistrant's common stock, $1.00 par value, all of which were held beneficially and of record by Black Hills Corporation.

Reduced Disclosure

The Registrant meets the conditions set forth in General Instruction H (1) (a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.

 
 
 

TABLE OF CONTENTS

  Page
   
 GLOSSARY OF TERMS AND ABBREVIATIONS3
   
PART 1.FINANCIAL INFORMATION 
   
Item 1.Financial Statements 
   
 
Condensed Statements of Income –
unaudited
Three and Nine Months Ended September 30,March 31, 2010 and 2009 and 2008
4
   
 
Condensed Balance Sheets –
September 30, 2009- unaudited
March 31, 2010 and December 31, 20082009
5
   
 
Condensed Statements of Cash Flows –
Nine- unaudited
Three Months Ended September 30,March 31, 2010 and 2009 and 2008
6
   
 Notes to Condensed Financial Statements - unaudited7-167-15
   
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations17-2316-22
   
Item 4.Controls and Procedures2423
   
PART II.OTHER INFORMATION 
   
Item 1.Legal Proceedings2524
   
Item 1A.Risk Factors25-2724
   
Item 6.Exhibits2825
   
 Signatures2926
   
 Exhibit Index3027


 
2
 

GLOSSARY OF TERMS

The following terms and abbreviations appear in the text of this report and have the definitions described below:

AFUDCAllowance for Funds Used During Construction
ASC 105ASC 105, “FASB Accounting Standards Codification and the Hierarchy of
Generally Accepted Accounting Principles – a replacement of FASB
Standard No. 162”
ASC 715ASC 715, “Compensation – Retirement Benefits”
ASC 810-10-15ASC 810-10-15, “Consolidation"Consolidation of Variable Interest Entities”
ASC 815ASC 815, “Derivative and Hedging”Entities"
ASC 820ASC 820, “Fair"Fair Value Measurements and Disclosures”
ASC 825ASC 825, “Financial Instruments”
ASC 855ASC 855, “Subsequent Events”Measurements"
BHCBlack Hills Corporation, the Parent Company
Black Hills EnergyThe name used to conduct the business activities of Black Hills Utility Holdings, Inc.,
a direct subsidiary of the Parent Company
Black Hills WyomingBlack Hills Wyoming, LLC, an indirect subsidiary of the Parent Company
Cheyenne LightCheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of the
Parent Company
CO2
Carbon dioxide
EnsercoEnserco Energy, Inc., an indirect subsidiary of the Parent Company
EPAU.S. Environmental Protection Agency
FASFinancial Accounting Standard
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FSPFASB Staff Position
FSP FAS 107-1FSP FAS 107-1, “Interim Disclosure About Fair Value of Financial Instruments”
FSP FAS 132(R)-1FSP FAS 132(R)-1, “Employer’s Disclosures about Pensions and Other
Postretirement Benefits” (Revised)
GAAPGenerally Accepted Accounting Principles
GHGGreenhouse gas
LIBORLondon Interbank Offered Rate
MEANMunicipal Energy Agency of Nebraska
MDUMDU Resources Group, Inc.
MMBtuOne million British thermal units
MWMegawatts
MWhMegawatt-hours
PPAPurchase Power Agreement
SDPUCSouth Dakota Public Utilities Commission
SECU.S. Securities and Exchange Commission
SFASStatement of Financial Accounting Standards
SFAS 157SFAS 157, “Fair Value Measurements”
SFAS 161SFAS 161, “Disclosure about Derivative Instruments and Hedging Activities – an
amendment of FASB Statement No. 133”
SFAS 165SFAS 165, “Subsequent Events”
SFAS 167SFAS 167, “Amendment to FASB Interpretation No. 46(R)”
SFAS 168SFAS 168, “FASB Accounting Standards Codification and the Hierarchy of Generally
Accepted Accounting Principles – a replacement of FASB Standard No. 162”
Silver SageSilver Sage Wind Power, LLC, a subsidiary of Duke Energy Corporation
WPSCWyoming Public Service Commission
WRDCWyodak Resources Development Corp., an indirect subsidiary of the Parent
Company

 
3
 

BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF INCOME
(unaudited)

 Three Months Ended  Nine Months Ended  
Three Months Ended
March 31,
 
 September 30,  September 30,  2010  2009 
 2009  2008  2009  2008  (in thousands) 
 (in thousands)       
            
Operating revenue $53,086  $59,358  $154,380  $174,968 
Operating revenues $54,489  $54,458 
                        
Operating expenses:                        
Fuel and purchased power  24,254   30,119   66,769   85,844   24,236   22,762 
Operations and maintenance  7,460   7,604   23,584   23,615   8,026   7,638 
Administrative and general  6,385   4,538   19,628   14,612   6,192   6,271 
Depreciation and amortization  4,708   5,275   14,761   15,805   4,734   5,047 
Taxes, other than income taxes  1,359   1,594   5,007   5,002   1,940   2,035 
  44,166   49,130   129,749   144,878   45,128   43,753 
                        
Operating income  8,920   10,228   24,631   30,090   9,361   10,705 
                        
Other income (expense):                        
Interest expense  (2,837)  (2,751)  (8,246)  (7,957)  (3,866)  (2,585)
Interest income  48   171   211   290   395   112 
Allowance for funds used                
during construction – equity  2,593   1,183   5,270   2,072 
AFUDC - equity  2,007   1,401 
Other income, net  17   17   814   185   120   289 
  (179)  (1,380)  (1,951)  (5,410)  (1,344)  (783)
                        
Income before income taxes  8,741   8,848   22,680   24,680   8,017   9,922 
Income taxes  (1,575)  (2,477)  (5,445)  (7,482)  (2,083)  (2,958)
                        
Net income $7,166  $6,371  $17,235  $17,198  $5,934  $6,964 


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


 
4
 

BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS
(unaudited)

 September 30,  December 31, 
 2009  2008  
March 31,
2010
  
December 31,
2009
 
 (in thousands)  (in thousands) 
ASSETS            
Current assets:            
Cash and cash equivalents $1,150  $4  $2,560  $1,709 
Receivables, net –        
Customers  19,025   23,881 
Affiliates  2,236   12,619 
Other  4,071   2,111 
Receivables – customers, net  20,678   19,991 
Receivables – affiliates, net  3,036   4,146 
Other receivables, net  2,543   5,293 
Money pool note receivable  10,770   57,737 
Materials, supplies and fuel  18,836   19,309   19,483   18,825 
Regulatory assets, current  7,908   7,467 
Other current assets  9,422   5,730   4,539   1,639 
  54,740   63,654 
Total current assets  71,517   116,807 
                
Investments  4,156   3,999   4,318   4,197 
                
Property, plant and equipment  919,746   843,691   972,466   950,577 
Less accumulated depreciation  (292,610)  (281,220)
  627,136   562,471 
Less accumulated depreciation and amortization  (296,989)  (293,823)
Total property, plant and equipment, net  675,477   656,754 
                
Other assets:                
Regulatory assets  26,965   33,818 
Other  1,546   2,842 
Regulatory assets – non-current  31,118   31,305 
Other, non-current assets  6,556   3,730 
Total other assets  37,674   35,035 
TOTAL ASSETS $788,986  $812,793 
  28,511   36,660         
 $714,543  $666,784 
LIABILITIES AND STOCKHOLDER’S EQUITY        
        
LIABILITIES AND STOCKHOLDER'S EQUITY        
Current liabilities:                
Current maturities of long-term debt $32,023  $2,016  $20,053  $32,025 
Accounts payable  24,568   26,567   19,729   24,175 
Accounts payable – affiliates  5,895   10,411 
Notes payable – affiliates  104,898   70,184 
Accounts payable – affiliate  8,968   10,030 
Accrued liabilities  16,618   15,151   19,634   17,892 
Deferred income taxes  1,043   732 
  185,045   125,061 
Regulatory liability, current  1,238   1,238 
Deferred income tax liability - current  2,078   1,853 
Total current liabilities  71,700   87,213 
                
Long-term debt, net of current maturities  117,186   149,193   276,481   297,044 
                
Deferred credits and other liabilities:                
Deferred income taxes  90,088   85,504 
Regulatory liabilities  14,791   13,573 
Deferred income tax liability – non-current  101,830   96,207 
Regulatory liabilities, non-current  15,367   14,955 
Benefit plan liabilities  26,057   29,904   29,179   28,224 
Other  9,214   8,626 
Other, deferred credits and other liabilities  10,074   10,952 
Total deferred credits and other liabilities  156,450   150,338 
  140,150   137,607         
Stockholder’s equity:        
Common stock $1 par value; 50,000,000 shares authorized;        
23,416,396 shares issued  23,416   23,416 
Stockholder's equity:        
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued  23,416   23,416 
Additional paid-in capital  39,575   39,575   39,575   39,575 
Retained earnings  210,516   193,281   222,354   216,420 
Accumulated other comprehensive loss  (1,345)  (1,349)  (990)  (1,213)
  272,162   254,923 
 $714,543  $666,784 
Total stockholder's equity
  284,355   278,198 
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY
 $788,986  $812,793 

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


 
5
 

BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF CASH FLOWS
(unaudited)

  Nine Months Ended 
  September 30, 
  2009  2008 
  (in thousands) 
Operating activities:      
Net income $17,235  $17,198 
Adjustments to reconcile net income to cash        
provided by operating activities:        
Depreciation and amortization  14,761   15,805 
Provision for valuation allowances  (111)  172 
Deferred income tax  5,304   6,580 
Allowance for funds used during construction –        
equity  (5,270)  (2,072)
Change in operating assets and liabilities –        
Accounts receivable and other current assets  13,494   4,088 
Accounts payable and other current liabilities  (9,249)  (1,048)
Regulatory assets and liabilities  6,517   (3,811)
Other operating activities  (2,668)  1,959 
   40,013   38,871 
Investing activities:        
Property, plant and equipment additions  (106,150)  (97,475)
Proceeds from sale of ownership interest in plant  32,783   — 
Change in money pool notes receivable from        
affiliate, net  —   10,304 
Other investing activities  1,786   (183)
   (71,581)  (87,354)
Financing activities:        
Long-term debt – repayments  (2,000)  (1,995)
Change in money pool note payable to        
affiliate, net  34,714   49,796 
   32,714   47,801 
Increase (decrease) in cash and        
cash equivalents  1,146   (682)
         
Cash and cash equivalents:        
Beginning of period  4   2,033 
End of period $1,150  $1,351 
         
Supplemental disclosure of cash flow information:        
         
Non-cash investing and financing activities:        
Property, plant and equipment acquired        
with accrued liabilities $19,344  $15,750 
         
Cash paid during the period for:        
Interest (net of amounts capitalized) $9,098  $9,833 
Income taxes paid $494  $3,396 
  
Three Months Ended
March 31,
 
  2010  2009 
  (in thousands) 
Operating activities:      
Net income $5,934  $6,964 
Adjustments to reconcile net income to cash provided by operating activities:        
Depreciation and amortization  4,734   5,047 
Deferred income tax  5,855   1,867 
Employee benefits  1,021   1,090 
AFUDC – equity  (2,007)  (1,401)
Other non-cash adjustments  92   75 
Change in operating assets and liabilities -        
Accounts receivable and other current assets  3,164   14,322 
Accounts payable and other current liabilities  (2,147)  (9,684)
Regulatory assets  (441)  30 
Regulatory liabilities  -   (74)
Other operating activities  (3,474)  334 
Net cash provided by operating activities  12,731   18,570 
         
Investing activities:        
Property, plant and equipment additions  (22,648)  (33,336)
Change in money pool note receivable from affiliate, net  46,967   - 
Other investing activities  (3,344)  (93)
Net cash provided by (used in) investing activities  20,975   (33,429)
         
Financing activities:        
Long-term debt - repayments  (32,535)  (14)
Change in money pool note payable to affiliate, net  -   15,489 
Other financing activities  (320)  - 
Net cash (used in) provided by financing activities  (32,855)  15,475 
         
Increase in cash and cash equivalents  851   616 
         
Cash and cash equivalents:        
Beginning of period  1,709   4 
End of period $2,560  $620 
         
See Note 11 for supplemental cash flow information        


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


 
6
 

BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements
(unaudited)
(Reference is made to Notes to Financial Statements
included in our 20082009 Annual Report on Form 10-K)

(1)MANAGEMENT’SMANAGEMENT'S STATEMENT

The condensed financial statements included herein have been prepared by Black Hills Power, Inc., (the “Company,” “we,” “us,” “our”"Company," "we," "us," "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 financial statements should be read in conjunction with the financial statements and the notes thereto, included in our 20082009 Annual Report on Form 10-K filed with the SEC.  These financial statements include consideration of events through November 11, 2009.

Accounting methods historically employed require certain estimates as of interim dates.  The information furnished in the accompanying financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the September 30, 2009,March 31, 2010, December 31, 20082009 and September 30, 2008March 31, 2009 financial information and are of a normal recurring nature.  The results of operations for the three and nine months ended September 30, 2009March 31, 2010 and our financial condition as of September 30, 2009March 31, 2010 and December 31, 20082009 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

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

FASBRecently Adopted 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-grandfathered non-SEC accounting literature not included 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.

Fair Value Measurements and Disclosures, ASC 820 (SFAS 157)

The ASC for Fair Value Measurements and Disclosures defines fair value, establishes a framework for measuring fair value in GAAP and expands 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.  The adoption of this standard did not have a material impact on the Company’s financial position, results of operations or cash flows.

7

Derivative and Hedging, 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 comparative disclosures for periods subsequent to January 1, 2009 are provided in Note 9.

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 8.

(3)RECENTLY ISSUED ACCOUNTING STANDARDS

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 requirealso requires additional disclosures about the involvement with variable interest entities and any significant changes in risk exposure due to that involvement.  This standard iswas effective for annual periods that begin after November 15, 2009.  We are currently assessing the impact that theThe adoption of this standard will havehad no impact on our financial condition,statements.

Fair Value Measurements, ASC 820

In January 2010, the FASB issued guidance related to improving disclosures about fair value measurements.  The guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers.  In the reconciliation for Level 3, fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements shall be presented separately.  These disclosures are required for interim and annual reporting periods and were effective for the Company on January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011.  The guidance will require additional disclosures, but will not impact our financial position, results of operations andor 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.

 
87
 

Recently Issued Accounting Standards and Legislation

Patient Protection and Affordable Care Act (HR 3590)

On March 23, 2010, the President of the United States signed into law comprehensive healthcare reform legislation under the Patient Protection and Affordable Care Act, as amended by the Healthcare and Education Reconciliation Act.  Included among the provisions of the law is a change in the tax treatment of the Medicare Part D subsidy (the "subsidy") which could have an effect on our Non-Pension Postretirement Benefit Plan.  Internal Revenue Code Section 139A has been amended to eliminate the deduction of the subsidy in reducing income for years beginning after December 31, 2012.  The application of this legislation resulted in an adjustment to Regulatory assets and is not expected to have a significant impact on our financial position or results of operations.

(4)(3)ALLOWANCE FOR DOUBTFUL ACCOUNTS

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,  
March 31,
2010
  
December 31,
2009
 
 2009  2008       
      
Accounts receivable – customers $19,284  $24,251 
Accounts receivable trade $16,718  $14,703 
Unbilled revenues  4,216   5,547 
Total accounts receivable - customers  20,934   20,250 
Allowance for doubtful accounts  (259)  (370)  (256)  (259)
Net accounts receivable $19,025  $23,881  $20,678  $19,991 

(4)REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands):

 Recovery Period 
March 31, 2010
  
December 31, 2009
 
        
Regulatory assets:       
Unamortized loss on reacquired debt14 years $2,258  $2,207 
AFUDCUp to 45 years  7,106   7,579 
Defined benefit postretirement plansUp to 17 years  21,024   21,024 
Deferred energy costsLess than one year  7,908   7,467 
Other   730   495 
Total regulatory assets  $39,026  $38,772 
          
Regulatory liabilities:         
Cost of removal for utility plantUp to 53 years $14,160  $13,678 
Other   2,445   2,515 
Total regulatory liabilities  $16,605  $16,193 


8

Regulatory assets are primarily recorded for the probable future revenue to recover the costs associated with defined benefit postretirement plans, future income taxes related to the deferred tax liability for the equity component of AFUDC of utility assets and unamortized losses on reacquired debt.  To the extent that energy costs are under-recovered or over-recovered during the year, they are recorded as a regulatory asset or liability, respectively.  Regulatory liabilities include the probable future decrease in rate revenues related to a decrease in deferred tax liabilities for prior reductions in statutory federal income tax rates, gains associated with regulated utilities' defined benefit postretirement plans and the cost of removal for utility plant, recovered through our electric utility rates.  Regulatory assets are included in Regulatory assets, current and Regulatory assets, non-current on the accompanying Condensed Balance Sheet.  Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Condensed Balance Sheet.

(5)OTHER COMPREHENSIVE INCOME

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

  Three Months Ended 
  September 30, 
  2009  2008 
       
Net income $7,166  $6,371 
Other comprehensive income (loss), net of tax:        
Fair value adjustment on derivatives        
designated as cash flow hedges (net of        
tax of $15 and $0, respectively)  (27)  — 
Reclassification adjustments included in        
net income (net of tax of $(6) and $(6),        
respectively)  10   10 
Total comprehensive income $7,149  $6,381 
  
Three Months Ended
March 31,
 
  2010  2009 
       
Net income $5,934  $6,964 
Other comprehensive income, net of tax:        
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $115)  212   - 
Reclassification adjustments included in net income (net of tax of $(6) and $(6), respectively)  11   11 
Comprehensive income $6,157  $6,975 


  Nine Months Ended 
  September 30, 
  2009  2008 
       
Net income $17,235  $17,198 
Other comprehensive income (loss), net of tax:        
Fair value adjustment on derivatives        
designated as cash flow hedges (net of        
tax of $15 and $(18), respectively  (27)  30 
Reclassification adjustments included        
in net income (net of tax of $(17) and $60,        
respectively)  31   (109)
Total comprehensive income $17,239  $17,119 


9

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

 September 30,  December 31, 
 2009  2008  
March 31,
2010
  
December 31,
2009
 
            
Derivatives designated as cash flow hedges $(928) $(932) $(670) $(893)
        
Employee benefit plans $(417) $(417)  (320)  (320)
        
Total $(1,345) $(1,349)
Accumulated other comprehensive loss $(990) $(1,213)


9


(6)RELATED-PARTY TRANSACTIONS

Receivables and Payables

We have accounts receivable balances related to transactions with other BHC subsidiaries.  The balances were $2.2$3.0 million and $12.6$4.1 million as of September 30, 2009March 31, 2010 and December 31, 2008,2009, respectively.  We also have accounts payable balances related to transactions with other BHC subsidiaries.  The balances were $5.9$9.0 million and $10.4$10.0 million as of September 30, 2009March 31, 2010 and December 31, 2008,2009, respectively.

Money Pool Notes Receivable and Notes Payable

We have entered into a Utility Money Pool Agreement (the "Agreement") with BHC, Cheyenne Light and Black Hills Energy.  Under the agreement, we may borrow from theour Parent.  The Agreement restricts us from loaning funds to theour Parent or to any of the Parent’sour Parent's non-utility subsidiaries; the Agreement does not restrict us from making dividends to theour Parent.  Borrowings under the agreement bear interest at the daily cost of external funds as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one month LIBOR rate plus 100 basis points.

Through the Utility Money Pool, we had net note payable balances and interest payablereceivable balance of $105.1$10.8 million and $70.2$57.7 million as of September 30, 2009March 31, 2010 and December 31, 2008,2009, respectively.  Advances under this note bear interest at 0.70 percent0.70% above the daily LIBOR rate (which equates to 0.95% at September 30, 2009)March 31, 2010).  Net interest expense of less than $0.1 million and $1.1$0.2 million was recorded for the three months ended March 31, 2010 and nine months ended September 30, 2009, respectively.  Netnet interest expense was approximately $0.4 million and $0.4 million for the three and nine months ended September 30, 2008, respectively.March 31, 2009.

Other Balances and Transactions

We also received revenues of approximately $0.2 million and $0.3$0.2 million for the three months ended September 30,March 31, 2010 and 2009, and 2008, respectively; and $0.7 million and $1.0 million for the nine months ended September 30, 2009 and 2008, respectively, from Black Hills Wyoming for the transmission of electricity.

We received revenues of approximately $0.6$0.5 million and $0.4$0.3 million for the three months ended September 30,March 31, 2010 and 2009, and 2008, respectively; and $1.3 million and $1.5 million for the nine months ended September 30, 2009 and 2008, respectively, from Cheyenne Light for the sale of electricity and dispatch services.

We recorded revenues of $0.2 million for the nine months ended September 30, 2008 relating to payments received pursuant to a natural gas swap entered into with Enserco, with a third party transacted by Enserco on our behalf.

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We purchase coal from WRDC.  The amount purchased during the three months ended September 30,March 31, 2010 and 2009 and 2008 was $4.2$4.1 million and $4.9$3.9 million, respectively; and $11.3 million and $10.8 million for the nine months ended September 30, 2009 and 2008, respectively.

We purchase excess power generated by Cheyenne Light.  The amount purchased during the three months and nine months ended September 30, 2009March 31, 2010 was $1.9$2.6 million and $5.8 million, respectively and includes $0.3 million and $1.5$1.2 million for wind-generated power for the three and nine months ended September 30, 2009, respectively.power.  The amount purchased for the three and nine month periodsperiod ended September 30, 2008March 31, 2009 was $1.5$2.0 million and $4.6includes $0.8 million respectively.  On August 28, 2008, we entered into a contract with Cheyenne Light under which Cheyenne Light sells up to 20 MW of wind-generated renewable energy to us until 2028.power.

In order to fuel our combustion turbine, we purchase natural gas from Enserco.  The amount purchased during the three months ended September 30,March 31, 2010 and 2009 and 2008 was $0.9$0.5 million and $3.0$0.1 million, respectively; and $1.5 million and $6.6 million for the nine months ended September 30, 2009 and 2008, respectively.  These amounts are included in Fuel and purchased power on the accompanying Condensed Statements of Income.

In addition, we also pay theour Parent for allocated corporate support service cost incurred on our behalf.  Corporate costs allocated from theour Parent were $3.8$4.0 million and $2.8$3.6 million for the three months ended September 30,March 31, 2010 and 2009, and 2008, respectively; and $11.3 million and $8.9 million for the nine months ended September 30, 2009 and 2008, respectively.


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We have funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $2.0 million as of September 30, 2009March 31, 2010 and $1.9$2.0 million as of December 31, 2008,2009, respectively, which is included in Other, Deferred credits and other liabilities on the accompanying Condensed Balance Sheets.  Interest on the funds accrues quarterly at an average quarterly prime rate (3.25% at September 30, 2009).March 31, 2010) and was less than $0.1 million at March 31, 2010 and 2009, respectively.

(7)EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

We have a noncontributory defined benefit pension plan (the “Plan”"Plan") covering the employees who meet certain eligibility requirements.

In July 2009, the Board of Directors approved a resolution, effective January 1, 2010, to freeze our Defined Benefit Pension Plan to new participants and to transfer certain existing participants to an age and service based defined contribution plan.  Plan assets and obligations were revalued July 31, 2009 in conjunction with the curtailment of these plans and we recognized curtailment expense of approximately $0.2 million in the three months ended September 30, 2009.


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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 plan:

  Defined Benefit 
  Pension Plans 
  July 31, 2009 
  (in thousands) 
    
Change in benefit obligation:   
    
Projected benefit obligation at   
December 31, 2008 $51,965 
     
Service cost  682 
Interest cost  1,831 
Actuarial gain  (88)
Benefits paid  (1,317)
Benefits curtailed  (1,048)
Change in discount rate  (335)
Net increase (decrease)  (275)
Projected benefit obligation at    
July 31, 2009 $51,690 

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

 Three Months Ended  Nine Months Ended 
 September 30,  September 30,  Three Months Ended March 31, 
 2009  2008  2009  2008  2010  2009 
                  
Service cost $287  $279  $871  $837  $304  $292 
Interest cost  786   758   2,357   2,274   820   785 
Expected return on plan assets  (718)  (1,094)  (2,032)  (3,282)  (752)  (657)
Prior service cost  18   28   74   84   15   28 
Net loss  377   —   1,236   —   344   430 
Curtailment expense  189   —   189   — 
                        
Net periodic benefit cost (gain) $939  $(29) $2,695  $(87)
Net periodic benefit cost $731  $878 

A contribution totaling less than $0.1 million wasThere were no contributions made to the Plan in the first quarter of 2009.2010.  There are no further contributions expected to be made to the Plan in 2009.


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Supplemental Nonqualified Defined Benefit Plans

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

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

 Three Months Ended Nine Months Ended 
 September 30, September 30, 
 2009 2008 2009 2008 
             
Interest cost $25  $30  $75  $90 
Net loss  11   11   33   33 
                 
Net periodic benefit cost $36  $41  $108  $123 

We anticipate that we will make contributions to the Supplemental Plans for the 2009 fiscal year of approximately $0.1 million.  Contributions are expected to be in the form of benefit payments.2010.

Non-pension Defined Benefit Postretirement Plans

Employees who are participants in the Postretirement Healthcare Plans (“Healthcare Plans”(the "Healthcare Plans") and who meet certain eligibility requirements are entitled to postretirement healthcare benefits.

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

 Three Months Ended  Nine Months Ended 
 September 30,  September 30,  Three Months Ended March 31, 
 2009  2008  2009  2008  2010  2009 
                  
Service cost $54  $52  $162  $156  $94  $54 
Interest cost  111   104   333   312   149   111 
Amortization of prior service cost  (42)  - 
Net loss  56   - 
Net transition obligation  13   13   39   39   -   13 
                        
Net periodic benefit cost $178  $169  $534  $507  $257  $178 

We anticipate that we will make contributions to the Healthcare Plan for the 20092010 fiscal year of approximately $0.2$0.3 million.  Contributions are expected to be made in the form of benefit payments.

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It has been determined that the 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 less than $0.1 million.


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

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

  
Three Months Ended
March 31,
 
  2010  2009 
       
Interest cost $25  $25 
Net loss  7   11 
         
Net periodic benefit cost $32  $36 

We anticipate that we will make contributions to the Supplemental Plans for the 2010 fiscal year of approximately $0.1 million.  Contributions are expected to be in the form of benefit payments.

(8)FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments at September 30 are as follows (in thousands):

 2009  March 31, 2010  December 31, 2009 
 Carrying Amount  Fair Value  Carrying Amount  Fair Value  Carrying Amount  Fair Value 
                  
Cash and cash equivalents $1,150  $1,150  $2,560  $2,560  $1,709  $1,709 
Derivative financial instruments – liabilities $42  $42 
Derivative financial instruments – other current assets $322  $322  $-  $- 
Derivative financial instruments – accrued liabilities $-  $-  $5  $5 
Long-term debt, including current maturities $149,209  $171,273  $296,534  $313,991  $329,069  $344,942 

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

Cash and Cash Equivalents

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

Derivative Financial Instruments

These instruments are carried at fair value.  Pricing is based on quoted prices for identical or similar assets and liabilities in active and inactive markets, inputs other than quoted prices that are observable and inputs that are derived principally from, or corroborated by, observable market data by correlation or other means.


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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.

(9)RISK MANAGEMENT ACTIVITIES AND DERIVATIVES

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,instruments in managing these risks.

As of March 31, 2010 and recorded in Accrued liabilities and Accumulated other comprehensive loss on the accompanying Condensed Balance Sheet.  Gains or losses on these transactions will be recorded in gross margins upon settlement.

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On September 30,December 31, 2009, we had the following swaps and related balances (dollars, in thousands):

 Natural Gas Swaps 
   
 Natural Gas Swaps  March 31, 2010  December 31, 2009 
         
Notional*  232,500   232,500   232,500 
Maximum terms in months  12   7   10 
Current derivative asset $—  $322  $- 
Non-current derivative asset $—  $-  $- 
Current derivative liability $42  $-  $5 
Non-current derivative liability $—  $-  $- 
Pre-tax accumulated other comprehensive    
income (loss) $(42)
Pre-tax accumulated other comprehensive income (loss) $327  $(5)
Unrealized gain/(loss) $—  $-  $- 
___________________________
*Gas in MMBtus.

Additionally,
(10)LONG-TERM DEBT

In February 2010, our Series AC bonds matured.  These were paid in full for $30.0 million plus accrued interest of $1.2 million.

In February 2010, we engageprovided notice to the bondholders of our intent to call our Series Y bonds in activities to manage risk associated with changesfull.  These bonds were originally due in 2018.  The balance of $2.7 million was paid on March 31, 2010, which includes the balance of $2.5 million plus accrued interest rates.  We occasionally enter into floating-to-fixed interest rate swap agreements to minimize our exposure to interest rate fluctuations associated with our floating rateand an early redemption premium of 2.6%.  The early redemption premium was recorded in unamortized loss on reacquired debt obligations.  These swaps were designated as cash flow hedgeswhich is included in accordance with generally accepted accounting for derivatives, and accordingly the resulting gain or loss is carried in Accumulated other comprehensive lossRegulatory assets on the accompanying Condensed Balance Sheets and will be amortized over the liferemaining term of the related debt.  For the nine months ended September 30, 2009 and 2008, respectively, we amortized less than $0.1 million from Accumulated other comprehensive loss to Interest expense related to a settled interest rate swap designated as a cash flow hedge.original bonds.


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(11)SUPPLEMENTAL CASH FLOWS INFORMATION


  
Three Months
Ended
March 31, 2010
  
Three Months
Ended
March 31, 2009
 
  (in thousands) 
Non-cash investing and financing activities -      
Property, plant and equipment financed with accrued liabilities $8,467  $22,524 
         
Supplemental disclosure of cash flow information:        
Cash (paid) refunded during the period for -        
Interest (net of amounts capitalized) $(3,851) $(4,017)
Income taxes refunded $1,018  $218 

(10)(12)COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We are subject to various legal proceedings, claims and litigation as described in Note 1112 of the Notes to our Financial Statements in our 20082009 Annual Report on Form 10-K.  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 ninethree months of 2009.2010.

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 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 financial statements.  As such, costs, if any, that may be incurred in excess of those amounts provided as of September 30, 2009,March 31, 2010, cannot be reasonably determined and could have a material adverse effect on our results of operations, financial position or cash flows.

Purchase Power Agreement

In March 2010, we entered into a seven-year PPA and Purchase Option Agreement with the City of Gillette, Wyoming effective April 2010 that replaces a previous agreement.  The PPA provides for 23 MW of system-firm electricity capacity and 23 MWh of electric energy per hour on a take-or-pay basis.  This PPA also provides the City of Gillette with an option to purchase a 23% ownership interest in our Wygen III facility which commenced commercial operations on April 1, 2010.  As an incentive for the City of Gillette to complete the purchase, the capacity rate is structured to escalate commencing July 2010.  In addition, the purchase price would increase on January 1, 2011, and escalate each year throughout the term of the PPA.  If the City of Gillette exercises the option, the PPA will terminate upon the closing of the transaction.

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(13)SUBSEQUENT EVENT

In April 2010, we provided notice to the bondholders of our intent to call our Series Z bonds in full.  These bonds were originally due in 2021.  The principal amount due has been reclassified to Current maturities of long-term debt on the accompanying Condensed Balance Sheet.  A payment of $19.2 million for principal of $18.3 million, accrued interest and an early redemption premium of 4.675% will be made on May 31, 2010.  The call premium will be recorded in unamortized loss on reacquired debt, which is included in Regulatory assets on the accompanying Condensed Balance Sheets and will be amortized over the remaining term of the original bonds.  The call premium will be recorded in Regulatory assets and amortized over the remaining original term of the bonds.

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


  
Three Months Ended
March 31,
 
  2010  2009 
  (in thousands) 
       
Revenues $54,489  $54,458 
Fuel and purchased power  24,236   22,762 
Gross margin  30,253   31,696 
         
Operating expenses  20,892   20,991 
Operating income  9,361   10,705 
         
Interest expense, net  (3,471)  (2,473)
Other income  2,127   1,690 
Income tax expense  (2,083)  (2,958)
Net income $5,934  $6,964 

The following tables provide certain operating statistics:

  
Electric Revenue
(in thousands)
 
    
  Three Months Ended March 31, 
Customer Base 2010  Percentage Change  2009 
          
Commercial $14,539      (1)%  $14,643 
Residential  14,479   1   14,281 
Industrial  4,637   (2)   4,750 
Municipal sales  653   3   636 
Total retail sales  34,308   -   34,310 
Contract wholesale  6,718   3   6,553 
Wholesale off system  8,716   (5)   9,220 
Total electric sales  49,742   (1)   50,083 
Other revenues  4,747   9   4,375 
Total revenues $54,489      -%  $54,458 


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  Megawatt Hours Sold 
    
  Three Months Ended March 31, 
Customer Base 2010  Percentage Change  2009 
          
Commercial  184,438        5%   175,256 
Residential  174,535     7   163,476 
Industrial  86,663     1   85,984 
Municipal sales  8,226     2   8,095 
Total retail sales  453,862     5   432,811 
Contract wholesale  168,465     -   168,679 
Wholesale off system  231,047     (5)   243,786 
Total electric sales  853,374     1   845,276 
Losses and company use  9,719   (63)   26,191 
Total energy  863,093        (1)%   871,467 


 Electric Utility Power Plant Availability
  
 Three Months Ended March 31,
 20102009
   
Coal-fired plants93.9%96.5%
Other plants99.8%99.5%
Total availability96.5%97.8%


  Megawatt Hours Generated and Purchased 
    
  Three Months Ended March 31, 
Resources 2010  Percentage Change  2009 
          
Coal  430,573          (2)%   437,551 
Gas  2,838   164   1,075 
   433,411       (1)   438,626 
             
MWhs purchased  429,682       (1)   432,839 
Total resources  863,093       (1)   871,465 


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 Heating Degree Days
  
 
Three Months Ended
March 31,
 20102009
Heating and cooling degree days:  
Actual  
Heating degree days3,3923,254
   
Variance from normal  
Heating degree days3%(1)%

Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009.  Net income decreased $1.0 million from the prior period primarily due to the following:

Gross margin:  Gross margin decreased $1.4 million primarily due to a decrease in retail margins of Long-Term$2.4 million as a result of increased purchased power costs not recoverable through the energy cost adjustment and $0.3 million decrease from lower margins and 5% decrease in MWh sold from off-system sales.

Operating expenses:  Operating expenses were comparable to the same period in the prior year.

Interest expense, net:  Interest expense, net increased $1.0 million primarily due to a higher interest expense of $2.3 million on the bonds offset by a $0.9 million increase in AFUDC associated with the borrowed funds from the construction at Wygen III.

Other income, net:  Other income increased $0.4 million primarily due to an increase in AFUDC-equity.

Income tax, expense:  Income tax expense decreased $0.9 million primarily due to a $1.9 million decrease in earnings before taxes and a favorable tax impact as a result of the increase in AFUDC-equity.

Significant Events

Purchase Power Sales Agreement with MEAN

In March 2009, our 10-year power sales contract between MEAN2010, we entered into a seven-year PPA and Purchase Option Agreement with the City of Gillette, Wyoming to provide 23 MW of system-firm electricity capacity and 23 MWh of electric energy per hour, on a take-or-pay basis.  The Agreement replaces a previous agreement that originally expired in 2013 was re-negotiated and extended until 2023.  UnderApril 2010.  This PPA also provides the new contract, MEAN willCity of Gillette with an option to 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:

2009-201720 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-201915 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-202112 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-202310 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

Partial Sale of Wygen III to MDU

On April 9, 2009, we sold to MDU a 25%23% ownership interest in our Wygen III facility which commenced commercial operations on April 1, 2010.  As an incentive for the City of Gillette to complete the purchase, the capacity rate is structured to escalate commencing July 2010.  In addition, the purchase price would increase on January 1, 2011 and escalate each year throughout the term of the PPA.  If the City of Gillette exercises the option, the PPA will terminate upon the closing of the transaction.


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Smart Grid Funding

In April 2010, we reached an agreement with the Department of Energy for smart grid funding through grants totaling $9.6 million.  The funds are made available through the American Recovery and Reinvestment Act of 2009 and, combined with matching investment funds from us, will enable us to install 69,000 smart meters and related communications infrastructure and information technology software and equipment.

Wygen III Power Plant Project

Construction of our 110 MW coal-fired base load electric generation facility, currently under construction.Wygen III, was completed and it began commercial operation on April 1, 2010.  The expected cost of construction is approximately $255 million, which includes estimates of AFUDC.  In April 2009, we sold a 25% ownership interest to MDU.  At closing, MDU made a payment to us for its 25% share of the costs to date onfor the ongoingon-going construction of the facility.   Proceeds of $32.8 million were received.  MDU will continue to reimburse us monthly for its 25% of the total costs paid to complete the project.  We will retain responsibility for operationsoperation of the facility with a life-of-plant site lease, and agreements with MDU for operations and coal supply.  In conjunctionsupply agreements in place with the sales transaction, we also modified our 2004 PPA with MDU under which we 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 25 MW from our other generation facilities or system purchases.

(11)SUBSEQUENT EVENT

Bond Issuance

On October 27, 2009, we 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 intercompany borrowings from BHC, primarily incurred to fund the construction of Wygen III.  Estimated deferred finance costs of $1.9 million were capitalized and will be amortized over the life of the bonds.

Renewable Energy Contracts

On October 1, 2009, we entered into a renewable energy sales agreement with Cheyenne Light to purchase renewable energy and associated environmental energy credits produced by Silver Sage.  Silver Sage commenced commercial operations on October 1, 2009.  This agreement allows us to buy 20 MW of the unit-contingent renewable energy purchased by Cheyenne Light from Silver Sage.

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ITEM 2.RESULTS OF OPERATIONS

  Three Months Ended  Nine Months Ended 
  September 30,  September 30, 
  2009  2008  2009  2008 
  (in thousands) 
             
Revenue $53,086  $59,358  $154,380  $174,968 
Fuel and purchased power  24,254   30,119   66,769   85,844 
Gross margin  28,832   29,239   87,611   89,124 
                 
Operating expenses  19,912   19,011   62,980   59,034 
Operating income $8,920  $10,228  $24,631  $30,090 
                 
Net income $7,166  $6,371  $17,235  $17,198 

The following tables provide certain operating statistics:

 Electric Revenue 
 (in thousands) 
   
 Three Months Ended September 30, Nine Months Ended September 30, 
    Percentage      Percentage   
Customer Base2009  Change 2008 2009  Change 2008 
                  
Commercial $15,694   (5)%  $16,581  $44,888   2%  $43,804 
Residential  11,132   (16)   13,189   35,804   —    35,784 
Industrial  4,714   (14)   5,500   14,494   (11)   16,338 
Municipal sales  778   (3)   802   2,074   —    2,069 
Total retail sales  32,318   (10)   36,072   97,260   (1)   97,995 
Contract wholesale  6,488   (5)   6,862   18,672   (7)   20,063 
Wholesale off system  9,625   (27)   13,213   24,610   (48)   47,548 
Total electric sales  48,431   (14)   56,147   140,542    (15)   165,606 
Other revenue  4,655   45    3,211   13,838    48    9,362 
Total revenue $53,086   (11)%  $59,358  $154,380   (12)%  $174,968 

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  Megawatt Hours Sold 
    
  Three Months Ended September 30,  Nine Months Ended September 30, 
     Percentage       Percentage    
Customer Base 2009  Change 2008  2009  Change  2008 
                  
Commercial  207,939       6%   195,661   553,150      4%   531,433 
Residential  113,266    (6)   120,888   395,865    (1)   398,028 
Industrial  80,222   (25)   107,380   260,190   (18)   319,077 
Municipal sales  9,894     (3)   10,228   25,556     (2)   26,073 
Total retail sales  411,321     (5)   434,157   1,234,761     (3)   1,274,611 
Contract wholesale  161,796     (2)   165,872   473,723     (4)   494,457 
Wholesale off system  309,770    28   241,546   784,173     4   753,057 
Total electric sales  882,887     5   841,575   2,492,657     (1)   2,522,125 
Losses and company                        
use  30,764    22   25,313   98,057   72   56,911 
Total energy  913,651         5%   866,888   2,590,714   —   2,579,036 


  Electric Utility Power Plant Availability 
    
  Three Months Ended September 30,  Nine Months Ended September 30, 
  2009  2008  2009  2008 
             
Coal-fired plants  97.7%   95.8%**   90.5%*   91.8%** 
Other plants  99.6%   98.7%        97.1%     90.6%     
Total availability  98.5%   97.1%        93.4%     91.3%     
___________________________
  *Reflects major 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 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.


  Megawatt Hours Generated and Purchased 
    
  Three Months Ended September 30,  Nine Months Ended September 30, 
     Percentage        Percentage    
Resources 2009  Change  2008  2009  Change  2008 
                   
Coal  465,068   3 %   450,884   1,251,276   (1)%   1,268,514 
Gas  28,251   138     11,856   35,076   (35)   53,687 
   493,319   7     462,740   1,286,352   (3)   1,322,201 
                           
MWhs purchased  420,332   4     404,148   1,304,362   4    1,256,835 
Total resources  913,651   5 %   866,888   2,590,714   —    2,579,036 


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  Heating and Cooling Degree Days 
    
  Three Months Ended  Nine Months Ended 
  September 30,  September 30, 
  2009  2008  2009  2008 
Heating and cooling degree days:            
Actual            
Heating degree days  178   223   4,705   4,814 
Cooling degree days  303   453     354      482 
                 
Variance from normal                
Heating degree days  (22)%   (2)%   4%   6% 
Cooling degree days  (39)%   (8)%   (41)%   (19)% 

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008.  Net income increased $0.8 million from the prior period primarily due to the following:

·Increased other margins of $1.5 million primarily due to an increase in transmission rates effective January 1, 2009;

·A $0.3 million increase in retail margins primarily due to lower purchase power and fuel costs partially offset by lower MWh sold due to lower industrial sales; and

·Increased AFUDC of $1.5 million primarily due to construction of Wygen III in 2009.

Partially offsetting the increases were 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 $0.7 million increase in employee benefit costs.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008.  Net income was comparable to the prior period primarily due to the following:

·A $6.0 million decrease in margins from off-system sales reflecting the lower margins available in the current low energy price environment; and

·A $2.8 million increase in employee benefit costs.

Partially offsetting the decreases were the following:

·Increased gross margins of $4.5 million primarily due to an increase in transmission rates effective January 1, 2009; and

·Increased AFUDC of $4.0 million primarily due to construction of Wygen III in 2009.


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

In March 2008, we received final regulatory approval for construction of Wygen III.  Construction began immediately and the 110 MW coal-fired base load electric generating facility is expected to be completed by June, 2010.  The expected cost of construction is approximately $255 million, which includes estimates for AFUDC.  Our 2004 PPA with 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, MDU reimbursed us for its 25%, or $32.8 million, 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 our 2004 PPA with MDU under which we 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 such 25 MW from our other generation facilities or system purchases.

Extension of Long-Term Power Sales Agreement with MEAN

In March 2009, our 10-year power sales contract between MEAN 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:

2009-201720 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-201915 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-202112 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-202310 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

Purchase Power Agreement with MEAN

In July 2009, we 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.MDU.

Rate Case Filed with the SDPUC

On September 30, 2009, we 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.  We are seeking a 26.6%, increase in annual utility revenues and we anticipate thatrevenues.  In March 2010, the newSDPUC approved interim rates will befor a 20% increase in rates effective April 1, 2010 for our South Dakota customers on or around April 1, 2010.customers.  The proposed rate increase is subject to approval by the SDPUC.


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Rate Case Filed with the WPSC

On October 19, 2009, we 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.  We are seeking a 38.95%, increase in annual utility revenues andrevenues.  On May 4, 2010, we anticipate thatfiled a settlement stipulation agreement with the new rates will be effectiveWPSC for our Wyoming customers on or around April 1, 2010, although recovery could be delayed until August 2010 as part of the regulatory process.a $3.1 million increase in annual revenues.  The proposed rate increase is subject to approval by the WPSC.


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Financing Transactions and Short-Term Liquidity

Financing Plans

In October 2009, we completed the issuance of a long-term first mortgage bond of approximately $180 million.  Proceeds of the transaction will be used to fund capital expenditures, including construction costs related to the Wygen III facility, and to fund the approximate $30 million maturity ofFebruary 2010, our Series AC 8.06% first mortgage bonds matured.  These were paid in full for $30.0 million plus accrued interest of $1.2 million.

In February 2010, we provided notice to the bondholders of our intent to call our Series Y bonds in full.  These bonds were originally due in February 2010.2018.  The balance of $2.7 million was paid on March 31, 2010, which includes the balance of $2.5 million plus accrued interest and an early redemption premium of 2.6%.  The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Balance Sheets and will be amortized over the remaining term of the original bonds.

In April 2010, we provided notice to the bondholders of our intent to call the Series Z bonds in full.  These bonds, originally due in 2010, will be paid in full on May 31, 2010 with an early redemption premium of 4.675%.

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,March 31, 2010, our first mortgage bonds credit ratings, as assessed by the three major credit rating agencies, were as follows:

Rating AgencyRatingOutlook
Moody’sMoody'sA3Stable
S&PBBBStable
FitchA-Stable



 
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SAFE HARBOR FOR FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q includes “forward-looking statements”"forward-looking statements" as defined by the SEC.  We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.  All statements, other than statements of historical facts, included in this Form 10-Q 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 statements involve 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,” “potentials,”"may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potentials," or “continue”"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 assurances that such indicated results will be realized.  The forward-looking statements include the factors discussed above, the risk factors described in Item 1A1A. of our 20082009 Annual Report on Form 10-K, in Item 1A. of Part II of this Quarterly Report on Form 10-Q filed with the SEC, and the following:

 ·Our ability to obtain adequate cost recovery for our retail utility operations through regulatory proceedings; to receive favorable rulings in the periodic applications to recover costs for fuel and purchased power; and our ability to add power generation assets into regulatory rate base;

 ·Our ability to access the bank loan and debt capital markets depends on market conditions beyond our control.  If the credit markets remain tight and do not improve, 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;

 ·Our ability to obtain from utility commissions any requisite determination of prudency to support resource planning and development programs we propose to implement;

 ·The timing and extent of scheduled and unscheduled outages of power generation facilities;

 ·The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;

 ·Changes in business and financial reporting practices arising from the enactment of the Energy Policy Act of 2005;2005 and subsequent rules and regulations promulgated thereunder;

 ·Our ability to remedy any deficiencies that may be identified in the review of our internal controls;

·Our ability to successfully complete labor negotiations with our union;

·Our ability to recover our borrowing costs, including debt service costs, in our customer rates;

 
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·Liabilities of environmental conditions, including remediation and reclamation obligations under environmental laws;

·Our ability to complete the permitting, construction, start-up and operations of power generating facilities in a cost-effective and timely manner;

 ·The timing, volatility and extent of changes in energy-related and commodity prices, interest rates, energy and commodity supply or volume, the cost and availability of transportation of commodities, and demand for our services, all of which can affect our earnings, liquidity position and the underlying value of our assets;

 ·Our ability to effectively use derivative financial instruments to hedge commodity risks;

 ·Our ability to minimize defaults on amounts due from counterparty transactions;

 ·Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment;environment and to recover those expenditures in customer rates, where applicable;

 ·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;

 ·Weather and other natural phenomena;

 ·Industry, market, political and marketeconomic changes, including the impact of consolidations and changes in competition;

 ·The effect of accounting policies issued periodically by accounting standard-setting bodies;

 ·The cost and effects on our business, including insurance, resulting from terrorist actions or responses to such actions or events;

 ·The outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements;settlements on our financial condition or results of operations;

 ·Price risk due to marketable securities held as investments in benefit plans;

 ·General economic and political conditions, including tax rates or policies and inflation rates; and

 ·Other factors discussed from time to time in our other filings with the SEC.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement.  We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise.

 
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ITEM 4.CONTROLS AND PROCEDURES

Evaluation of Disclosure 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 (Exchange Act)) as of September 30, 2009.March 31, 2010.  Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2009March 31, 2010 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.


 
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BLACK HILLS POWER, INC.

Part II –- Other Information

Item 1.Legal Proceedings

For information regarding legal proceedings, see Note 11 of Notes to Financial Statements in Item 8 of our 20082009 Annual Report on Form 10-K and Note 8 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 8 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.1A. of Part I in our Annual Report on Form 10-K for the year ended December 31, 2008.2009.

Federal and state laws concerning climate change and air emissions, including emission reduction mandates and renewable energy portfolio standards, may materially increaseMunicipal governments within our generation and production costsutility service territories possess the power of condemnation, and could render someseek a municipal utility within a portion of our generating units uneconomical to operatecurrent service territories by limiting or denying franchise privileges for our operations, and maintain.
We own and operate regulated fossil-fuel generating plants in South Dakota and Wyoming. We are constructing another fossil-fuel generating plant in Wyoming. Air emissionsexercising powers of fossil-fuel generating plants arecondemnation over all or part of our utility assets within municipal boundaries. Although condemnation is a process that is 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 resultconstitutional protections requiring just compensation, as with any judicial procedure, the outcome is uncertain.  If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment 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 pollutantsassets 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.condemnation.


 
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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.


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We own electric utilities that serve customers in Montana, South Dakota and Wyoming. Montana has 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 this state increases its 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 6.Exhibits


Exhibit 4Second 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 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 POWER, INC.

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 POWER, INC.
  
  
 /S/ /S/ DAVID R. EMERY
 
David R. Emery, Chairman
and Chief Executive Officer
  
  
 /S/ /S/ ANTHONY S. CLEBERG
 
Anthony S. Cleberg, Executive Vice President
and Chief Financial Officer
  
Dated:  November 12, 2009May 11, 2010 


 
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EXHIBIT INDEX


Exhibit NumberDescription
  
Exhibit 4Second 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 31.1Certification 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 31.2Certification 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 32.1Certification 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 32.2Certification 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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