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

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's telephone number (605) 721-1700
Former name, former address, and former fiscal year if changed since last report
NONE

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.

Yesx
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).

Yeso
No o
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
o
No
x

As of April 30,July 31, 2010, there were issued and outstanding 23,416,396 shares of the Registrant's common stock, $1.00 par value, all of which were held beneficially and of record by Black Hills Corporation.

Reduced Disclosure

The RegistrantRe gistrant 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
Table Of Contents
   
GLOSSARY OF TERMS AND ABBREVIATIONS
3
PART 1. FINANCIAL INFORMATION  
PARTItem 1. Financial StatementsFINANCIAL INFORMATION
Condensed Statements of Income - unaudited
4
Three and Six Months Ended June 30, 2010 and 2009 
   
Item 1.Condensed Balance Sheets - unauditedFinancial Statements
5
June 30, 2010 and December 31, 2009 
   
Cash Flow Statements - unaudited 
Condensed Statements of Income – unaudited6
Three
Six Months Ended March 31,June 30, 2010 and 20094
   
Condensed Balance Sheets - unaudited
March 31, 2010 and December 31, 2009
5
Condensed Statements of Cash Flows - unaudited
Three Months Ended March 31, 2010 and 2009
6
Notes to Condensed Financial Statements - unaudited7-15
7
   
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations16-22
16
   
Item 4.Controls and Procedures23
24
   
PART II.OTHER INFORMATION 
25
   
Item 1.Legal Proceedings24
 
25
Item 1A.Risk Factors24
26
   
Item 6.
Exhibits25
27
   
Signatures26
28
   
ExhibitExhibits Index27
29


2
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 810-10-15ASC 810-10-15, "Consolidation of Variable Interest Entities"
ASC 820ASC 820, "Fair Value 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
DOEDepartment of Energy
EnsercoEnserco Energy, Inc., an indirect subsidiary of the Parent Company
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
LIBORLondon Interbank Offered Rate
JPBConsolidated Wyoming Municipalities Electric Power System Joint Power Board
MDUMDU Resources Group, Inc.
MMBtuOne million British thermal units
MWMegawatts
MWhMegawatt-hours
Participation AgreementAmendment and Restated Wygen III Participation Agreement dated July 14, 2010 between the Company, MDU and JPB, which includes JPB as partial owner of Wygen I II
PPAPurchase Power Agreement
SDPUCSouth Dakota Public Utilities Commission
SECU.S. Securities and Exchange Commission
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 June 30, Six Months Ended June 30,
 2010 2009 2010 2009
 (in thousands)
        
Operating revenue$56,438  $46,836  $110,927  $101,294 
        
Operating expenses:       
Fuel and purcha sed power21,616  19,753  45,852  42,515 
Operations and maintenance9,390  8,486  17,416  16,124 
Administrative and general7,441  6,972  13,633  13,243 
Depreciation and amortization5,684 &n bsp;5,006  10,418  10,052 
Taxes, other than income taxes1,797  1,613  3,737  3,649 
Total operating expenses45,928  41,830  91,056  85,583 
        
Operating income10,510  5,006  19,871  15,711 
        
Other income (expense):       
Interest expense(5,616) (2,838) (9,482) (5,410)
Interest income1,029  65  1,424  164 
AFUDC - equit y230  1,276  2,237  2,677 
Other income, net18  508  138  797 
Total other income (expense)(4,339) (989) (5,683) (1,772)
        
Income before income taxes6,171  4,017  14,188  13,939 
Income tax expense(2,069) (912) (4,152) (3,870)
Net income$4,102 &n bsp;$3,105  $10,036  $10,069 
        
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.

4
 

3
BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS
(unaudited)
 June 30,
2010		 December 31,
2009
 (in thousands)
ASSETS   
Current assets:   
Cash and cash equivalents$2,503  $1,709 
Receivables - customers, net19,000  19,991 
Receivables - affilia tes, net4,929  4,146 
Other receivables, net2,428  5,293 
Money pool notes receivable—  57,737 
Materials, supplies and fuel19,422  18,825 
Regulatory assets, current6,438  7,467 
Other current assets2,884  1,639 
Total current assets57,604  116,807 
    
Investments4,337  4,197 
    
Property, plant and equipm ent984,695  950,577 
Less accumulated depreciation and amortization(298,811) (293,823)
Total property, plant and equipment, net685,884  656,754 
    
Other assets:   
Regulatory assets - non-current32,227  31,305 
Other, non-current assets4,403  3,730 
Total other assets36,630  35,035 
TOTAL ASSETS$784,455  $812,793 
    
LIABILITIES AND STOCKHOLDER'S EQUITY   
Current liabilities:   
Current maturities of long-term debt$75  $32,025 
Accounts payable14,248  24,175 
Accounts payable - affiliates6,984  10,030 
Notes Payable - affiliates13,028  — 
Accrued liabilities16,624  17,892 
Regulatory liabilities, current3,138  1,238 
Deferred income tax liabilities - current1,781  1,853 
Total current liabilities55,878  87,213 
    
Long-term debt, net of current maturities276,462  297,044 
    
Deferred credits and other liabilities:   
Deferred income tax liability - non-current107,058  96,207 
Regulatory liabilities, non-current16,783  14,955 
Benefit plan liabilities30,093  28,224 
Other, deferred credits and other liabilities9,720  10,952 
Total deferred credits and other liabilities163,654  150,338 
    
Stockholder's equity:   
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued23,416  23,416 
Additional paid-in capital39,575  39,575 
Retained earnings226,456  216,420 
Accumulated other comprehensive loss(986) (1,213)
Total stockholder's equity288,461  278,198 
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY$784,455  $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) 
 Six Months Ended June 30, 
 2010 2009 
 (in thousands) 
Operating activities:    
Net income$10,036  $10,069  
Adjustments to reconcile net income to cash provided by operating activities:    
Depreciation and amortization10,418  10,052  
Deferred income tax11,029  3,634  
Employee benefits2,043  2,180  
AFUDC - equity(2,237) (2,677) 
Other non-cash adjustments159  175  
Change in operating assets and liabilities -    
Accounts receivable and other current assets(1,953) 10,255  
Accounts payable and other current liabilities(10,495) 11,011  
Regulatory assets(441) 6  
Regulatory liabilities—  (142) 
Other operating activities2,027  1,305  
Net cash provided by operating activities20,586  45,868  
     
Investing activities:    
Property, plant and equipment additions(40,241) (76,911) 
Proceeds from sale of ownership interest in plant—  32,321  
Change in money pool note receivable from affiliate, net57,737  —  
Other investing activities3,392  (4,314) 
Net cash provided by (used in) investing activities20,888  (48,904) 
     
Financing activities:    
Long-term debt - repayments(52,532) (1,984) 
Change in money pool note payable to affiliates, net13,028  5,642  
Other financing activities(1,176) —  
Net cash (used in) provided by financing activities(40,680) 3,658  
     
Increase in cash and cash equivalents794  622  
     
Cash and cash equivalents:    
Beginning of period1,709  4  
End of period$2,503  ; $626  
     
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.
CONDENSED STATEMENTS OF INCOME
(unaudited)

  
Three Months Ended
March 31,
 
  2010  2009 
  (in thousands) 
       
Operating revenues $54,489  $54,458 
         
Operating expenses:        
Fuel and purchased power  24,236   22,762 
Operations and maintenance  8,026   7,638 
Administrative and general  6,192   6,271 
Depreciation and amortization  4,734   5,047 
Taxes, other than income taxes  1,940   2,035 
   45,128   43,753 
         
Operating income  9,361   10,705 
         
Other income (expense):        
Interest expense  (3,866)  (2,585)
Interest income  395   112 
AFUDC - equity  2,007   1,401 
Other income, net  120   289 
   (1,344)  (783)
         
Income before income taxes  8,017   9,922 
Income taxes  (2,083)  (2,958)
         
Net income $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)
  
March 31,
2010
  
December 31,
2009
 
  (in thousands) 
ASSETS      
Current assets:      
Cash and cash equivalents $2,560  $1,709 
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  19,483   18,825 
Regulatory assets, current  7,908   7,467 
Other current assets  4,539   1,639 
Total current assets  71,517   116,807 
         
Investments  4,318   4,197 
         
Property, plant and equipment  972,466   950,577 
Less accumulated depreciation and amortization  (296,989)  (293,823)
Total property, plant and equipment, net  675,477   656,754 
         
Other assets:        
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 
         
LIABILITIES AND STOCKHOLDER'S EQUITY        
Current liabilities:        
Current maturities of long-term debt $20,053  $32,025 
Accounts payable  19,729   24,175 
Accounts payable – affiliate  8,968   10,030 
Accrued liabilities  19,634   17,892 
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  276,481   297,044 
         
Deferred credits and other liabilities:        
Deferred income tax liability – non-current  101,830   96,207 
Regulatory liabilities, non-current  15,367   14,955 
Benefit plan liabilities  29,179   28,224 
Other, deferred credits and other liabilities  10,074   10,952 
Total deferred credits and other liabilities  156,450   150,338 
         
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 
Retained earnings  222,354   216,420 
Accumulated other comprehensive loss  (990)  (1,213)
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)

  
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)( unaudited)
(Reference is made to Notes to Financial Statements
included in our 2009 Annual Report on Form 10-K)

(1) MANAGEMENT'S STATEMENT
(1)MANAGEMENT'S STATEMENT

The condensed financial statements included herein have been prepared by Black Hills Power, Inc., (the "Company," "we," "us," or "our"), without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These financial statements should be read in conjunction with the financial statements and the notes thereto, included in our 2009 Annual Report on Form 10-K filed with the SEC.

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

(2)RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION
Certain prior year data presented in the financial statements has been reclassified to conform to the current year presentation. These reclassifications had no effect on total assets, net income, cash flows or earnings per share.

(2) RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION
Recently Adopted Accounting Standards

Consolidation of Variable Interest Entities, ASC 810-10-15

In June 2009, the FASB issued a revision regarding consolidations. The amendment requires a Companycompany to consider whether an entity that is insufficiently capitalized or is not controlled through voting should be consolidated. It also requires additional disclosures about the involvement with variable interest entities and any significant changes in risk exposure due to that involvement. This standard wasis effective for annual periods that begin after November 15, 2009.2009 with ongoing re-evaluation. The adoption of this standard had no impact on our financial statements.

Fair Value Measurements,Measu rements, 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 shallare required to be presented separately. These disclosures are required for interim and annual reporting periods and were effective for the Companyus 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 requirerequires additional disclosures, but did not and will not impact our financial position, results of operations or cash flows.


7
7
 

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 onwould affect 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 assetsas sets and is not expected to have a significant impact on our financial position, or results of operations.operations or cash flows.

(3)ALLOWANCE FOR DOUBTFUL ACCOUNTS
(3) ACCOUNTS RECEIVABLE

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 receivablesaccounts receivable balances (in thousands):

  
March 31,
2010
  
December 31,
2009
 
       
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  (256)  (259)
Net accounts receivable $20,678  $19,991 

 June 30,
2010		 December 31,
2009
    
Accounts receivable trade$14,003  $14,703 
Unbilled revenues5,220  5,547 
Total accounts receivable - customers19,223  20,250 
Allowance for doubtful accounts(223) (259)
Receivables - customers, net$19,000  $19,991 
(4)REGULATORY ACCOUNTING

8

(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 

 Recovery PeriodJune 30,
2010		 December 31,
2009
     
Regulatory assets:    
Unamortized loss on reacquired debt14 years$3,141  $2,207 
AFUDCUp to 45 years7,106  7,579 
Defined benefit postretirement plansUp to 17 years21,024  21,024 
Deferred energy costsLess than one year6,438  7,467 
Other 956  495 
Total regulatory assets $38,665  $38,772 
     
Regulatory liabilities:    
Cost of removal for utility plantUp to 53 years$14,663  $13,678 
Other 5,258  2,515 
Total regulatory liabilities $19,921  $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
(5) OTHER COMPREHENSIVE INCOME

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

  
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 
 Three Months Ended June 30,
 2010 2009
Net income$4,102  $3,105 
Other comprehensive income, net of tax:   
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $4)(6) — 
Reclassification adjustments included in net income (net of tax of $(6) and $(6), respectively)10  11 
Comprehensive income$4,10 6  $3,116 

9

 Six Months Ended June 30,
 2010 2009
Net income$10,036  $10,069 
Other comprehensive income, net of tax:   
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $(115))206  — 
Reclassification adjustments included in net income (net of tax of $(11) and $(11), respectively)21  21 
Comprehensive income$10,263  $10,090 
Balances by classification included within Accumulated other comprehensive loss on the accompanying Condensed Balance Sheets are as follows (in thousands):

  
March 31,
2010
  
December 31,
2009
 
       
Derivatives designated as cash flow hedges $(670) $(893)
Employee benefit plans  (320)  (320)
Accumulated other comprehensive loss $(990) $(1,213)

 June 30,
2010		 December 31,
2009
Derivatives designated as cash flow hedges$(666) $(893)
Employee benefit plans(320) (320)
Total Accumulated other comprehensive loss$(986) $(1,213)

 
9
 


(6) RELATED-PARTY TRANSACTIONS
(6)RELATED-PARTY TRANSACTIONS

Receivables and Payables

We have accounts receivable balances related to transactions with other BHC subsidiaries. The balances were $3.0$4.9 million and $4.1$4.1 million as of March 31,June 30, 2010 and December 31, 2009, respectively. We also have accounts payable balances related to transactions with other BHC subsidiaries. The balances were $9.0$7.0 million and $10.0$10.0 million as of March 31,June 30, 2010 and December 31, 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,Agreement, we may borrow from our Parent. The Agreement restricts us from loaning funds to our Parent or to any of our Parent's non-utility subsidiaries; the Agreement does not restrict us from making dividends to our 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 a net notenotes payable balance of $13.1 million on June 30, 2010 and a net notes receivable balance of $10.8$57.7 million and $57.7 million as of March 31, 2010 and December 31, 2009 respectively.. Advances under this notethese notes bear interest at 0.70%2.75% above the daily LIBOR rate (which equates to 0.95%0.35% at March 31, 2010)June 30, 2010). Net interest expenseincome of $0.2less than $0.1 million and $0.1 million was recorded for the three and six months ended March 31,June 30, 2010 and net, respectively. Net interest expense was $0.4$0.7 million and $1.1 million for the three and six months ended March 31, 2009.June 30, 2009, respectively.

10

Other Balances and Transactions

We also received revenues of approximately $0.2$0.8 million and $0.2$0.2 million for the three months ended March 31,June 30, 2010 and 2009, respectively, and $0.9 million and $0.4 million for the six months ended June 30, 2010 and 2009, respectively from Black Hills Wyoming for the transmission of electricity.

We received revenues of approximately $0.5$0.3 million and $0.3$0.4 million for the three months ended March 31,June 30, 2010 and 2009, respectively, and $0.9 million and $0.7 million for the six months ended June 30, 2010 and June 30, 2009 from Cheyenne Light for the sale of electricity and dispatch services.

We purchase coal from WRDC. The amount purchased during the three months ended March 31,June 30, 2010 and 2009 was $4.1$3.9 million and $3.9$3.2 million, respectively; and $8.0 million and $7.1 million for the six months ended June 30, 2010 and June 30, 2009, respectively.

We purchase excess power generated by Cheyenne Light. The amount purchased during the three and six months ended March 31,June 30, 2010 was $2.6$2.1 million and $4.7 million and includes $1.2$1.3 million and $2.5 million for wind-generated power.power, respectively. The amount purchased for the three and six month periodperiods ended March 31,June 30, 2009 was $2.0$2.0 million and $3.9 million and includes $0.8$0.5 million and $1.3 million of wind-generated power.power, respectively.

In order to fuel our combustion turbine, we purchase natural gas from Enserco. The amount purchased during the three months ended March 31,June 30, 2010 and 2009 was $0.5$0.2 million and $0.1$0.5 million respectively., respectively; and $0.7 million and $0.6 million for the six months ended June 30, 2010 and 2009. These amounts are included in Fuel and purchased power on the accompanying Condensed Statements of Income.

In addition, we also pay our Parent for allocated corporate support service cost incurred on our behalf. Corporate costs allocated from our Parent were $4.0$4.2 million and $3.6$3.8 million for the three months ended March 31,June 30, 2010 and 2009, respectively; and $8.2 million and $7.4 million for the six months ended June 30, 2010 and 2009, respectively.


 
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We have funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $2.0$2.0 million as of March 31,June 30, 2010 and $2.0$2.0 million as of December 31, 2009, respectively, which is included in Other, DeferredDeferr ed credits and other liabilities on the accompanying Condensed Balance Sheets. Interest on the funds accrues quarterly at an average quarterly prime rate (3.25%(3.10% at March 31, 2010)June 30, 2010) and was less than $0.1 million at March 31,for the three and six months ended June 30, 2010 and 2009, respectively.

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(7) EMPLOYEE BENEFIT PLANS
(7)EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

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

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

  Three Months Ended March 31, 
  2010  2009 
       
Service cost $304  $292 
Interest cost  820   785 
Expected return on plan assets  (752)  (657)
Prior service cost  15   28 
Net loss  344   430 
         
Net periodic benefit cost $731  $878 

 Three Months Ended June 30, Six Months Ended June 30,
 2010 2009 2010 2009
Service cost$304  $292  $608  $584 
Interest cost820  785  1,641  1,570 
Expected return on plan assets(752) (657) (1,504) (1,314)
Prior service cost15  28  30  56 
Net loss344  430  687  860 
Net periodic benefit cost$731  $878  $1,462  $1,756 
There
Ther e were no contributions made to the Plan in the first quarter of 2010. There are no further contributions expected to be made to the Plan in 2010.

Non-pension Defined Benefit Postretirement Plans

Employees who are participants in the Postretirement 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 thousands):

  Three Months Ended March 31, 
  2010  2009 
       
Service cost $94  $54 
Interest cost  149   111 
Amortization of prior service cost  (42)  - 
Net loss  56   - 
Net transition obligation  -   13 
         
Net periodic benefit cost $257  $178 

 Three Months Ended June 30, Six Months Ended June 30,
 2010 2009  ;2010 2009
Service cost$94  $54  $188  $108 
Interest cost149  111  298  222 
Amortization of prior service cost(42) —  (84) — 
Net loss56  —  112  — 
Net transition obligation—  13  —  26 
Net periodic benefit cost$257  $178  $514  $356 
We anticipate that we will make contributions to the Healthcare Plan for the 2010 fiscal year of approximately $0.3 million. ContributionsContributi ons 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.

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&nb sp;

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

 Three Months Ended June 30, Six Months Ended June 30,
 2010 2009 2010 2009
Interest cost$25  $25  $50  $50 
Net loss7  11  14  22 
Net periodic benefit cost$32  $36  $64  $72 
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
(8) FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

 June 30, 2010 December 31, 2009
 Carrying Amount Fair Value Carrying Amount Fair Value
Cash and cash equivalents$2,503  $2,503  $1,709  $1,709 
Derivative financial instruments - other current assets$312  $312  $—  $— 
Derivative financial instruments - accrued liabilities$—  $—  $5  $5 
Long-term debt, including current maturities$276,537  $313,767  $329,069  $344,942 
The following methodsmethod s 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.

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(9) RISK MANAGEMENT ACTIVITIES AND DERIVATIVES
(9)RISK MANAGEMENT ACTIVITIES AND DERIVATIVES

We 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 utilize various derivative instruments in managing these risks.

As of March 31,June 30, 2010 and December 31, 2009, we had the following swaps and related balances (dollars, in thousands):

  Natural Gas Swaps 
    
  March 31, 2010  December 31, 2009 
       
Notional*  232,500   232,500 
Maximum terms in months  7   10 
Current derivative asset $322  $- 
Non-current derivative asset $-  $- 
Current derivative liability $-  $5 
Non-current derivative liability $-  $- 
Pre-tax accumulated other comprehensive income (loss) $327  $(5)
Unrealized gain/(loss) $-  $- 
___________________________
 Natural Gas Swaps
 June 30, 2010 December 31, 2009
Notional*232,500  232,500 
Maximum terms in months4  10 
Current derivative asset$312  $— 
Non-current derivative asset$—  $— 
Current derivative liability$—  $5 
Non-current derivative liability$—  $— 
Pre-tax accumulated other comprehensive income (loss) included in the Condensed Balance Sheets$312  $(5)
Unrealized gain/(loss)$—  $— 
    
* Gas in MMBtus.   
*Gas in MMBtus.

(10)LONG-TERM DEBT
(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 provided notice to the bondholders of our intent to call ourthe Series Y bonds in full. These bonds were originally due in 2018. The balanceA total of $2.7 million was paid on March 31, 2010, which includesincluded the principal balance of $2.5 million plus accrued interest and an early redemption premium of 2.6%2.618%. 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 were originally due to mature in 2021. A total of $21.8 million was paid on June 1, 2010, which included the principal balance of $20.0 million plus accrued interest and an early redemption premium of 4.675%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Balance Sheets and will be amortized over the remaining term of the original bonds.

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(11) SUPPLEMENTAL CASH FLOWS INFORMATION
13
 Six Months ended
 June 30, 2010 June 30, 2009
 (in thousands)
Non-cash investing and financing activities -   
Property, plant and equipment financed with accrued liabilities$5,897  $27,782 
    
Supplemental disclosure of cash flow information:   
Cash (paid) refunded during the period for -   
Interest (net of amounts capitalized)$(10,959) $(4,970)
Income taxes$6,517  $(621)
 


(12) COMMITMENTS AND CONTINGENCIES
(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 

(12)COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We are subject to various legal proceedings, claims and litigation as described in Note 12 of the Notes to our Financial Statements in our 2009 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 threesix months of 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 March 31,June 30, 2010, cannot be reasonably determined and could have a material adverse effect on ourou r 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 providesprovided the City of Gillette, through JPB, 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 theThe City of Gillette notified us of their intent to completeexercise the option to purchase the capacity rate is structured to escalate commencing23% ownersh ip interest in Wygen III and the transaction closed in 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, theThe PPA will terminateterminated upon the closing of the transaction. (See Note 13)
(13) SUBSEQUENT EVENT
Partial Sale of Wygen III
On July 14, 2010, we sold a 23% ownership interest in Wygen III to the JPB for $62.0 million. The JPB exists for the purpose of, among other things, financing the electrical system of the City of Gillette. The transaction entitles the JPB to approximately 25.3 MW for the life of the plant. The purchase terminates the current PPA with the City of Gillette, and the Participation Agreement provides that the City of Gillette pay us for administrative services and share in the costs of operating the plant for the life of the facility.

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


 Three Months Ended June 30, Six Months Ended June 30,
 2010 2009 2010 2009
 (in thousands)
Revenues$56,438  $46,836  $110,927  $101,294 
Fuel and purchased power21,616  19,753  45,852  42,515 
Gross margin34,822  27,083  65,075  58,779 
        
Operating, general and administrative expenses24,312  22,077  45,204  43,068 
Operating income10,510  5,006  1 9,871  15,711 
        
Interest expense, net(4,587) (2,773) (8,058) (5,246)
Other income18  508  138  797 
AFUDC - equity230  1,276  2,237  2,677 
Income tax expense(2,069) (912) (4,152) (3,870)
Net income$4,102  $3,105  $10,036  $10,069 
  
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 

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The following tables provide certain operating statistics:statistics (dollars in thousands):
 Electric Revenue
 Three Months Ended June 30, Six Months Ended June 30,
Customer Base2010 Percentage Change 2009 2010 Percentage Change 2009
Commercial$16,104  11% $14,551  $30,643  5% $29,194 
Residential11,546  11% 10,391  26,025  5% 24,672 
Industrial6,204  23% 5,030  10,841  11% 9,780 
Municipal Sales748  13% 660  1,401  8% 1,296 
Total retail sales34,602  13% 30,632  68,910  6% 64,942 
Contract wholesale7,078  26% 5,631  13,796  13% 12,184 
Wholesale off system8,539  48% 5,765  17,255  15% 14,985 
Total electric sale50,219  19% 42,028  99,961  9% 92,111 
Other revenues6,219  29% 4,808  10,966  19% 9,183 
Total revenues$56,438  21% $46,836  $110,927  10% $101,294 
 Megawatt Hours Sold
 Three Months Ended June 30, Six Months Ended June 30,
Customer Base2010 Percentage Change 2009 2010 Percentage Change 2009
Commercial164,863  (3)% 169,955  349,301  1% 345,211 
Residential113,903  (4)% 119,123  288,438  2% 282,599 
Industrial101,425  8% 93,984  188,088  5% 179,968 
Municipal sales7,577  0% 7,567  15,803  1% 15,662 
Total retail sales387,768  (1)% 390,629  841,630  2% 823,440 
Contract wholesale120,258  (16)% 143,248  288,723  (7)% 311,927 
Wholesale off system299,064  30%&n bsp;230,617  530,111  12% 474,403 
Total electric sales807,090  6% 764,494  1,660,464  3% 1,609,770 
Losses and company use43,792  7% 41,104  53,511  (20)% 67,293 
Total energy850,882  6% 805,598  1,713,975  2% 1,677,063 
 Electric Utility Power Plant Availability
 Three Months Ended June 30, Six Months Ended June 30,
 2010 2009 2010 2009
Coal-fired plants *90.9% 77.4% 91.4% 87.0%
Other plants98.8% 92.2% 99.3% 95.8%
Total availability93.8% 83.9% 94.4% 90.8%
*    2009 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.
  
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 Generated and Purchased
 Three Months Ended June 30, Six Months Ended June 30,
Generated -2010 Percentage Change 2009 2010 Percentage Change 2009
Coal-fired559,258  60% 348,657  989,831  26% 786,208 
Gas-fired1,106  (81)% 5,750  3,944  (42)% 6,825 
 560,364  58% 354,407  993,775  25% 793,033 
            
Purchased290,518  (36)% 451,191  720,200  (19)% 884,030 
Total Generated and Purchased850,882  6% 805,598  1,713,975  2% 1,677,063 
 


  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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��


 Degree DaysDegree Days
 Three Months Ended June 30,Six Months Ended June 30,
 2010200920102009
Heating and cooling degree days:    
Actual -    
Heating degree days904 1,273 4,296 4,527 
Cooling degree days65 51 65 51 
     
Variance from normal -    
Heating degree days9%28%4%5%
Cooling degree days(37)%(50)%(37)%(50)%
 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,June 30, 2010 Compared to Three Months Ended March 31, 2009.June 30, 2009. Net income decreased $1.0was $4.1 million from compared to $3.1 million for the same period in the prior periodyear primarily due to the following:

GrossG ross margin: Gross margin increased $7.7 million primarily due to the impact of $5.9 million related to the outcome of the rate case where interim rates were put into effect on April 1, 2010, an increase of $0.3 million in off-system sales, a decrease in purchased power costs of $0.9 million due to the commencement of commercial operations of Wygen III, and increased intercompany revenues of $0.6 million related to a shared services agreement.
Operating expenses: Operating expenses increas ed $2.2 million primarily due to an increase of $0.9 million in depreciation expense associated with depreciation for the Wygen III plant which commenced commercial operations on April 1, 2010, an increase of $0.4 million in labor and employee benefit costs, an increase in property taxes of $0.2 million and an increase of $0.8 million in intercompany costs associated with a shared services agreement.
Interest expense, net: Interest expense, net increased $1.8 million primarily due to higher interest expense of $1.9 million on the bonds and a $0.6 million decrease in AFUDC associated with the borrowed funds with the completed construction at Wygen III.
Other income, net: Other income, net decreased $1.4$1.5 million primarily due to a decrease in retail margins of $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.AFUDC-equity.

Income tax, expenseOperating expenses: Operating expenses were comparableIncome tax expense increased $1.2 million primarily due to an increase in earnings before taxes compared to the same period in the prior year.year and a higher effective tax rate resulting from the lower benefit from AFUDC-equity which decreased upon commercial operations of Wygen III.

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Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009. Net income was $10.0 million compared to $10.1 million for the same period in prior year primarily due to the following:
Gross margin: Gross margin increased $6.3 million primarily due to the impact of $5.9 million related to the outcome of the rate case where interim rates that went into effect on April 1, 2010, an increase of $0.7 million from off-system sales, and increased intercompany revenues of $1.2 million associated with a shared services agreement, partially offset by an increase in purchased power cost s of $2.1 million not recoverable through the energy cost adjustment.
Operating expenses: Operating expenses increased $2.1 million primarily due to an increase of $0.9 million in depreciation expense associated with depreciation for the Wygen III plant which commenced commercial operations on April 1, 2010, an increase of $0.2 million in labor and employee benefit costs and an increase of $1.2 million in intercompany costs associated with a shared services agreement.
Interest expense, net: Interest expense, net increased $1.0$2.8 million primarily due to a higher interest expense of $2.3 million on the bonds offset by a $0.9$0.2 million increase in AFUDC associated with the borrowed funds from the construction at Wygen III.

Other income, net: Other income increased $0.4decreased $1.1 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 taxesAFUDC-equity and a favorableprior year's recognition of $0.5 million from the sale of Wygen III.
Income tax, impact as a result ofexpense: The effective tax rate for the increase in AFUDC-equity.six months ended June 30, 2010 was comparable to the effective tax rate for the six months ended June 30, 2009.

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Significant Events

Purchase Power AgreementSale of Partial Ownership in Wygen III

In March 2010, 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 replaceseffective April 2010 that replaced a previous PPA entered into in 1998. This new agreement that expired in April 2010.  This PPA also providesprovided the City of Gillette, through JPB, with an option to purchase a 23% ownership interest, or approximately 25.3 MW, in our Wygen III facility which commenced commercial operations on April 1, 2010. As an incentivethe JBP exists for the purpose of, among other things, financing the electrical system of the City of Gillette. The City of Gillette exercised this option on July 14, 2010 and the JPB purchased the 23% ownership interest in Wygen III for $62.0 million for which we will recognize a gain on the sale of approximately $5.0 million to $6.0 million. We will continue to operate Wygen III and, through the Participation Agreement, the City of Gillette to completewill pay us for administrative services and its share in the purchase,costs of operating 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, theplant. The PPA will terminatedated March 2010 terminated upon the closing of the transaction.


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Smart Grid Funding

In April 2010, we reached an agreement with the Department of EnergyDOE 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. We expect to complete installation of these meters in 2011 and have spent $0.3 million of the DOE grant funds during 2010.

Wygen III Power Plant Project

Construction of our 110 MW coal-fired base load electric generation facility, Wygen III, was completed and it begancommenced commercial operationoperations 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 for the on-going construction of the facility. MDU will continueAs described above, in July 2010, we sold an additional 23% ownership in Wygen III to reimburse us monthly for its 25%the City of the total costs paid to complete the project.  We will retain responsibility for operation of the facility with a life-of-plant site lease, and operations and coal supply agreements in place with MDU.Gillette.

Rate Case Filed with the SDPUC

On September 30,In 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 arewere seeking a $32.0 million, or 26.6%, increase in annual utility revenues. In March 2010, the SDPUC approved interim rates for a 20% increase in rates effective April 1, 2010 for South Dakota customers. On July 8, 2010, the SDPUC approved a final revenue increase of $ 15.2 million or 12.7%. The proposedfinal settlement represented a rate base increase is subjectof $22.0 million, or 19.4%. A refund to approval bycustomers will be provided and has been accrued for the SDPUC.difference in rates.

As part of the rate case settlement, we have agreed that (a) 65% of our off-system sales income will be credited to ratepayers with a minimum credit of $2.0 million per year; (b) our rates will reflect an SD Surplus Energy Credit of $2.5 million in year one (fiscal year ending March 2011), $2.25 million in year two, $2.0 million in year three and zero thereafter; and (c) a three year moratorium on any rate case filings excluding any extraordinary events as defined in the stipulation agreement.
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 arewere seeking a $3.8 million, or 38.95%, increase in annual utility revenues. On May 4,13, 2010, we filed a settlement stipulation agreement with the WPSC for aapproved an annual rate increase of $3.1 million increase in annual revenues.  The proposed rate increase is subject to approval by the WPSC.

effective June 1, 2010.

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Financing Transactions and Short-Term Liquidity

Financing Plans

In February 2010, our Series AC bonds matured. These werew ere 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 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%2.618%. 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 be2021, were paid in full on May 31,June 1, 2010 with a payment of $21.8 million which included principal of $20.0 million, accrued interest and an early redemption premium of 4.675%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Balance Sheets and will be amortized over the remaining term of the original bonds.

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 March 31,June 30, 2010, our first mortgage bonds credit ratings, as assessed by the three major credit rating agencies, were as follows:

Rating AgencyRatingOutlook
Moody'sA3Stable
S&P *BBBBB BStable
FitchA-Stable

* In July 2010, S&P upgraded our senior secured debt rating to BBB+.

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SAFE HARBOR FOR FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q includes "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 actualactua l 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," 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 assurances 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 2009 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 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 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 obtain from utility commissions any requisite determination of prudency to support resource planning and development programs we propose to implement;
•    

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

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

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

·Our ability to recover our borrowing costs, including debt service costs, in our customer rates;
•    
Changes in business and financial reporting practices arising from the enactment of the Energy Policy Act of 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;
•    
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;

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21•  &nb sp; 
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 counterpa rty transactions;


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

·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;
•    

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

•    
·Our ability to minimize defaults on amounts due from counterparty transactions;
Weather and other natural phenomena;

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

Industry, market, political and economic changes, including the impact of consolidations and changes in competition;
·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;
The effect of ac counting policies issued periodically by accounting standard-setting bodies;

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

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

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

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

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
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 March 31, 2010.June 30, 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 financialfinanc ial reporting during the quarter ended March 31,June 30, 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.INC .

Part II - Other Information

Item 1.Legal Proceedings
Item 1.Legal Proceedings

For information regarding legal proceedings, see Note 11 of Notes to Financial Statements in ItemIte m 8 of our 2009 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.

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Item 1A. Risk Factors

Except to the extent updated or described below, our Risk Factors are documented in Item 1A. of Part I in our Annual Report on Form 10-K for the year ended December 31, 2009.

Municipal governments within our utility service territories possess the power of condemnation, and could seek a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations, and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. AlthoughAlthoug h condemnation is a process that is subject to constitutional 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 assets subject to condemnation.


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Item 6.Exhibits
Item 6.    Exhibits


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.
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 31.2Certification 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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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/ DAVID R. EMERY
David R. Emery, Chairman
and Chief Executive Officer
 /S/ ANTHONY S. CLEBERG
Anthony S. Cleberg, Executive Vice President
and Chief Financial Officer
Dated:  May 11, 2010

/S/ DAVID R. EMERY
David R. Emery, Chairman
and Chief Executive Officer
/S/ ANTHONY S. CLEBERG
Anthony S. Cleberg, Executive Vice President
 and Chief Financial Officer
Dated: August 10, 2010

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EXHIBIT INDEX


Exhibit NumberDescription
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.
Exhibit NumberDescription
 
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.

 
27Exhibit 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 a dopted 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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