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, 2010.March 31, 2011.
OR 
oTRANSITION REPOR TREPORT 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 Dakota  IRS 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
 
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x
No o
 
Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).
Yes o
No o
 
Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).
Large accelerated 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).
Yes o 
No x
 
As of OctoberApril 29, 2010,2011, 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 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 ABBREVIATIONS
3
   
PART 1.FINANCIAL INFORMATION 
   
Item 1.Financial Statements 
   
 Condensed Statements of Income - unaudited
4
   Three and Nine Months Ended September 30,March 31, 2011 and 2010 and 2009 
   
 Condensed Balance Sheets - unaudited
5
   September 30, 2010March 31, 2011 and December 31, 20092010 
   
 Cash Flow Statements - unaudited
67
   NineThree Months Ended September 30,March 31, 2011 and 2010 and 2009 
   
 Notes to Condensed Financial Statements - unaudited
78
   
Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations
2215
   
Item 4.Controls and Procedures
3121
 &nb sp; 
PART II.OTHER INFORMATION
32
   
Item 1.Legal Proceedings
3222
   
Item 1A.Risk Factors
3322
   
Item 6.Exhibits
3423
   
 Signatures
3524
   
 Exhibit Index
3625
 

2
 

GLOSSARY OF TERMS AND ABBREVIATIONS
 
The following terms and abbreviations appear in the text of this report and have the definitions described below:
 
AFUDCAllowance for Funds Used During Construction
ASCAccounting Standards Codification
ASC 310-10-50ASC 310-10-50, "Receivables"
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
Dodd-FrankDodd-Frank Wall Street Reform and Consumer Protection Act
DOEDepartment of Energy
EnsercoEnserco Energy, Inc., an indirect subsidiary of the Parent Company
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
GHGGreenhouse Gases
IRSInternal Revenue Service
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
NOxNitrogen Oxide
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 III
PPAPurchase Power AgreementMegawatt-hour
PPACAPatient Protection and Affordability Care Act
SDPUCSouth Dakota Public Utilities Commission
SECU.S. Securities and Exchange Commission
SOxSulfur Dioxide
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 March 31,  
 20112010   
 (in thousands)
      
Operating revenue$59,194 $54,489    
      
Operating expenses:     
Fuel, purchased power and cost of sales21,560 24,236    
Operations and maintenance17,990 15,005    
Depreciation and amortization6,562 4,734    
Taxes - property1,165 1,153    
Total operating expenses47,277 45,128    
      
Operating income11,917 9,361    
      
Other income (expense):     
Interest expense(4,220)(5,480)   
AFUDC - borrowed180 1,614    
Interest income10 395    
AFUDC - equity287 2,007    
Other income, net104 120    
Total other income (expense)(3,639)(1,344)   
      
Income before income taxes8,278 8,017    
Income tax expense(2,397)(2,083)   
Net income$5,881 $5,934    
 
BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF INCOME
(unaudited)
      
 Three Months Ended September 30, Nine Months Ended September 30,
 2010 2009 2010 2009
 (in thousands)
        
Operating revenue$59,051  $53,086  $169,978  $154,380 
        
Operating expenses:       
Fuel and purchased power20,944  24,254  66,796  66,769 
Operations and maintenance8,522  7,460  25 ,938  23,584 
Gain on sale of operating assets(6,238) —  (6,238) — 
Administrative and general6,883  6,385  20,516  19,628 
Depreciation and amortization6,043  4,708  16,461  14,761 
Taxes, other than income taxes1,805  1,359  5,542  5,007 
Total operating expenses37,959  44,166  129,015  129,749 
        
Operating income21,092  8,920  40,963 &nb sp;24,631 
        
Other income (expense):       
Interest expense(4,212) (2,837) (13,694) (8,246)
Interest income68  48  1,492  211 
AFUDC - equity266  2,593  2,503  5,270 
Other income, net22  17  160  814 
Total other income (expense)(3,856) (179) (9,539) (1,951)
        
Income before income taxes17,236  8,741  31,424  22,680 
Income tax expense(3,158) (1,575) (7,310) (5,445)
Net income$14,078  $7,166  $24,114  $17,235 
        
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
The accompanying notes to the condensed financial statements are an integral part of these condensed financial statements.

4
 

BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS
(unaudited)
 September 30,
2010		 December 31,
2009
 (in thousands)
ASSETS   
Current assets:   
Cash and cash equivalents$2,641  $1,709 
Receivables - customers, net20,661  19,991 
Receivables - affiliates, net11,491  4,146 
Other receivables, net3,147  5,293 
Money pool notes receivable57,143  57,737 
Materials, supplies and fuel20,620  18,825 
Regulatory assets, current8,805  7,467 
Other current assets6,653  1,639 
Total current assets131,161  116,807 
    
Investments4,354  4,197 
    
Property, plant and equipment951,127  950,577 
Less accumulated depreciation and amortization(304,879) (293,823)
Total property, plant and equipment, net646,248  656,754 
    
Other assets:   
Regulatory assets - non-current32,153  31,305 
Other, non-current assets3,688  3,730 
Total other assets35,841  35,035 
TOTAL ASSETS$817,604  $812,793 
    
LIABILITIES AND STOCKHOLDER'S EQUITY   
Current liabilities:   
Current maturities of long-term debt$84  $32,025 
Accounts payable14,808  24,175 
Accounts payable - affiliates34,569  10,030 
Accrued liabilities18,213  17,892 
Regulatory liabilities, current852  1,238 
Deferred income tax liabilities - current1,131  1,853 
Total current liabilities69,657  87,213 
    
Long-term debt, net of current maturities276,442  297,044 
    
Deferred credits and other liabilities:   
Deferred income tax liability - non-current108,860  96,207 
Regulatory liabilities, non-current27,634  14,955 
Benefit plan liabilities22,249  28,224 
Other, deferred credits and other liabilities10,185  10,952 
Total deferred credits and other liabilities168,928  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 earnings240,534  216,420 
Accumulated other comprehensive loss(948) (1,213)
Total stockholder's equity302,577  278,198 
TOTA L LIABILITIES AND STOCKHOLDER'S EQUITY$817,604  $812,793 
    
The accompanying notes to condensed financial statements are an integral part o f these condensed financial statements.
BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS
(unaudited)
 March 31,
2011		 December 31,
2010
 (in thousands)
ASSETS   
Current assets:   
Cash and cash equivalents$5,056  $2,045 
Receivables - customers, net24,880  28,716 
Receivables - affiliates, net5,524  6,891 
Other receivables, net1,133  2,077 
Notes receivable - Utility Money Pool48,925  39,862 
Materials, supplies and fuel21,540  21,259 
Regulatory assets, current4,575  3,584 
Deferred tax assets, current376  — 
Other, current assets7,347  3,712 
Total current assets119,356  108,146 
    
Investments4,487  4,396 
    
Property, plant and equipment984,793  962,640 
Less accumulated depreciation and amortization(321,504) (304,800)
Total property, plant and equipment, net663,289  657,840 
    
Other assets:   
Regulatory assets, non-current36,638  37,740 
Other, non-current assets3,595  3,610 
Total other assets40,233  41,350 
    
TOTAL ASSETS$827,365  $811,732 
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.

5

BLACK HILLS POWER, INC.
CONDENSED BALANCE SHEETS
(Continued)
(unaudited)
 March 31,
2011		 December 31,
2010
 (in thousands)
LIABILITIES AND STOCKHOLDER'S EQUITY   
Current liabilities:   
Current maturities of long-term debt$83  $81 
Accounts payable16,258  14,828 
Accounts payable - affiliates15,164  12,562 
Accrued liabilities16,364  15,541 
Regulatory liabilities, current2,692  1,932 
Deferred income tax liabilities, current—  859 
Total current liabilities50,561  45,803 
    
Long-term debt, net of current maturities276,401  276,422 
    
Deferred credits and other liabilities:   
Deferred income tax liabilities, non-current125,915  122,319 
Regulatory liabilities, non-current29,122  28,276 
Benefit plan liabilities20,174  19,581 
Other, deferred credits and other liabilities9,883  9,914 
Total deferred credits and other liabilities185,094  180,090 
    
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 earnings253,569  247,688 
Accumulated other comprehensive loss(1,251) (1,262)
Total stockholder's equity315,309  309,417 
    
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY$827,365  $811,732 
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.

6
 

 
BLACK HILLS POWER, INC.BLACK HILLS POWER, INC. BLACK HILLS POWER, INC. 
CONDENSED STATEMENTS OF CASH FLOWSCONDENSED STATEMENTS OF CASH FLOWS CONDENSED STATEMENTS OF CASH FLOWS 
(unaudited)(unaudited) (unaudited) 
Nine Months Ended September 30, Three Months Ended March 31, 
2010 2009 2011 2010 
(in thousands) (in thousands) 
Operating activities:  &n bsp;     
Net income$24,114  $17,235  $5,881  $5,934  
Adjustments to reconcile net income to cash provided by operating activities:        
Depreciation and amortization16,461  14,761  6,562  4,734  
Deferred income tax20,467  5,304  2,057  5,855  
Employee benefits3,060  3,337  601  1,021  
Gain on sale of operating assets(6,238) —  
AFUDC - equity(2,503) (5,270) (287) (2,007) 
Other non-cash adjustments5,615  142  (175) 92  
Change in operating assets and liabilities -        
Accounts receivable and other current assets(14,663) 13,494  2,256  3,164  
Accounts payable and other current liabilities20,143  (9,249) 6,473  (2,147) 
Regulatory assets2,665  6,733  3,468  (441) 
Regulatory liabilities1,245  (216) (317) —  
Contributions to employee benefit plans(8,800) —  
Other operating activities(8,818) (6,258) (2,213) (3,474) 
Net cash provided by operating activities52,748  40,013  24,306  12,731  
        
Investing activities:        
Property, plant and equipment additions(62,935) (106,150) (12,122) (22,648) 
Proceeds from sale of ownership interest in plant62,000  32,783  
Change in money pool note receivable from affiliate, net594  —  
Notes receivable from affiliates, net(9,063) 46,967  
Other investing activities2,244  1,786  (92) (3,344) 
Net cash provided by (used in) investing activities1,903  (71,581) (21,277) 20,975  
        
Financing activities:        
Long-term debt - repayments(52,543) (2,000) (18) (32,535) 
Change in money pool note payable to affiliates, net—  34,714  
Other financing activities(1,176) —  —  (320) 
Net cash (used in) provided by financing activities(53,719) 32,714  
Net cash provided by (used in) financing activities(18) (32,855) 
        
Increase in cash and cash equivalents932  1,146  
Net change in cash and cash equivalents3,011  851  
        
Cash and cash equivalents:    
Beginning of period1,709  4  
End of period$2,641  $1,150  
    
See Note 11 for supplemental cash flow information   
    
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.
Cash and cash equivalents beginning of period2,045  1,709  
Cash and cash equivalents end of period$5,056  $2,560  
 
See Note 10 for supplemental cash flow information.
The accompanying notes to condensed financial statements are an integral part of these condensed financial statements.

67
& nbsp;

BLACK HILLS POWER, INC.
 
Notes to Condensed Financial Statements
(unaudited)
(Reference is made to Notes to Financial Statements
included in our 20092010 Annual Report on Form 10-K)
 
(1) (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 20092010 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 September 30, 2010March 31, 2011, December 31, 20092010 and September 30, 2009March 31, 2010 financial information and are of a normal recurring nature. The results of operations for the three and nine months ended September 30, 2010March 31, 2011 and our financial condition as of September 30, 2010March 31, 2011 and December 31, 20092010 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.
 
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 or cash flows or earnings per share.flows.
 
(2) (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 company 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 is effective for annual periods that begin after November 15, 2009 with ongoing re-evaluation. The adoption of this standard had no impact on our financial 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 are required to be presented separately. These disclosures are required for interim and annual reporting periods and were effective for us on January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. The guidance requires additional disclosures, but did not and will not impact our financial position, results of operations or cash flows.

7

Recently Issued Accounting Standards and Legislation
 
Patient Protection and Affordable Care Act (HR 3590)
 
In March 2010, the President of the United States signed into law comprehensi vecomprehensive healthcare reform legislation under the PPACA as amended by the Healthcare and Education Reconciliation Act. The potential impact on the Company, if any, cannot be determined until regulations are promulgated under the PPACA.  Included among the provisions of the PPACA is a change in the tax treatment of the Medicare Part D subsidy (the "subsidy") which affects our Non-Pension Postretirement Benefit Plan. Internal Revenue Code Section 139A has been amended to eliminate the deduction of the subsidy in reducing income for years beginning after December 31, 2012. The impact of this change in the tax treatment of the subsidy had an immaterial effect on our financial position, results of operations and cash flows. The Company will continue to assess the accounting implications of the PPACA as related regulations and interpretations become available.
 
Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173)
In July 2010, the President of the United States signed into law comprehensive financial reform legislation under Dodd-Frank. Title VII of Dodd-Frank effectively regulates many derivative transactions in the United States that were previously unregulated, including swap transactions in the over-the-counter market. Among other things, Dodd-Frank (i) mandates the clearing of some swaps through regulated central clearing organizations and the trading of clearing swaps through regulated exchanges or swap execution facilities, in each case subject to certain key exemptions, and (ii) authorizes regulators to establish collateral and margin requirements fo r certain swap transactions that are not cleared. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. Significant rule-making by numerous governmental agencies, particularly the CFTC with respect to non-security commodities, will be required over the next several months to implement the restrictions, limitations, and requirements contemplated by Dodd-Frank, and we will continue to evaluate the impact as these rules become available.
Disclosures About the Credit Quality of Financing Receivables and the Allowance for Credit Losse s (ASC 310-10-50)
In July 2010, the FASB issued an amendment to ASC 310-10-50, Receivables - Disclosures. The guidance requires additional disclosures that will facilitate financial statement user's evaluation of the nature of credit risk inherent in financing receivables, how that risk is analyzed in arriving at the allowance for credit losses, and the reason for any changes in the allowance for credit losses. These disclosures should be provided on a disaggregated basis but exempts trade receivables that have a contractual maturity of one year or less, receivables measured at lower of cost or fair value, and receivables measured at fair value with the changes in fair value reported in earnings. The adoption of this amendment should have no impact on our financial position, results of operations or cash flows. It is effective for interim and annual reporting periods ending on or after December 15, 2010.
(3) (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 receivable allowance 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.
 
Accounts receivable consist of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivable balances are stated at billed and unbilled amounts net of write-offs or payment received. Approximately 29% of the accounts receivable balance consists of unbilled revenue as of March 31, 2011.
The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollected. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management's best estimate of future collection success given the existing collections environment.

8

In specific cases where we are aware of a customer's inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.
Following is a summary of accounts receivable balances (in thousands):
 

8

September 30,
2010		 December 31,
2009
   March 31,
2011		 December 31,
2010
Accounts receivable trade$14,544  $14,703 
Accounts receivable, trade$17,854  $21,365 
Unbilled revenues6,315  5,547 7,233  7,581 
Total accounts receivable - customers20,859  20,250 25,087  28,946 
Allowance for doubtful accounts(198) (259)(207) (230)
Receivables - customers, net$20,661  $19,991 $24,880  $28,716 
 
 

9

(4) (4)    REGULATORY ACCOUNTING
 
We had the following regulatory assets and liabilities (in thousands):
 
Recovery PeriodSeptember 30,
2010		 December 31,
2009
    Recovery PeriodMarch 31,
2011		 December 31,
2010
Regulatory assets:        
Unamortized loss on reacquired debt14 years$3,079  $2,207 14 years$2,953  $3,016 
AFUDCUp to 45 years7,106  7,579 Up to 45 years9,489  9,489 
Defined benefit postretirement plansUp to 17 years21,024  21,024 Up to 13 years18,615  18,049 
Deferred energy costsLess than one year5,817  7,467 Less than one year4,130  3,584 
Flow through accountingUp to 35 years5,031  4,772 
Other 3,932  495  995  2,414 
Total regulatory assets $40,958  $38,772  $41,213  $41,324 
        
Regulatory liabilities:        
Cost of removal for utility plantUp to 53 years$14,836  $13,678 Up to 53 years$16,656  $15,429 
Defined benefit postretirement planUp to 17 years11,320  11 Up to 13 years10,769  10,204 
Other 2,330  2,504  4,389  4,575 
Total regulatory liabilities $28,486  $16,193  $31,814  $30,208 
 
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.Sheets. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Condensed Balance Sheet.Sheets.
 

9
 

(5) (OTHER5)    COMPREHENSIVE INCOME
 
The following table presents the components of Other comprehensiveComprehensive income (in thousands):
 
 Three Months Ended September 30, 2010
Net income  $14,078 
Other comprehensive income, net of tax:   
Fair value adjustment on derivatives designated as cash flow hedges43   
Taxes(15)  
Fair value adjustment on derivatives designated as cash flow hedges, net of tax  28 
    
Reclassification adjustments included in net income16   
Taxes(6)  
Reclassification adjustments included in net income, net of tax  10 
    
Comprehensive income  $14,116 

10

Nine Months Ended September 30, 2010Three Months Ended March 31, 2011
Net income  $24,114   $5,881 
Other comprehensive income, net of tax:      
Fair value adjustment on derivatives designated as cash flow hedges360   $—   
Tax(125)  
Taxes—   
Fair value adjustment on derivatives designated as cash flow hedges, net of tax  235   — 
      
Reclassification adjustments included in net income48   $16   
Tax(18)  
Taxes(5)  
Reclassification adjustments included in net income, net of tax  30   11 
      
Comprehensive income  $24,379   $5,892 
 
 
 Three Months Ended September 30, 2009
Net income  $7,166 
Other comprehensive income, net of tax:   
Fair value adjustment on derivatives designated as cash flow hedges(42)  
Taxes15   
Fair value adjustment on derivatives designated as cash flow hedges, net of tax  (27)
    
Reclassification adjustments included in net income16   
Taxes(6)  
Reclassification adjustments included in net income, net of tax  10 
    
Comprehensive income  $7,149 
 Nine Months Ended September 30, 2009
Net income  $17,235 
Other comprehensive income, net of tax:   
Fair value adjustment on derivatives designated as cash flow hedges( 42)  
Tax15   
Fair value adjustment on derivatives designated as cash flow hedges, net of tax  (27)
    
Reclassification adjustments included in net income48   
Tax(17)  
Reclassification adjustments included in net income, net of tax  31 
    
Comprehensive income  $17,239 

11

 Three Months Ended March 31, 2010
Net income  $5,934 
Other comprehensive income, net of tax:   
Fair value adjustment on derivatives designated as cash flow hedges$327   
Taxes(115)  
Fair value adjustment on derivatives designated as cash flow hedges, net of tax  212 
    
Reclassification adjustments included in net income$17   
Taxes(6)  
Reclassification adjustments included in net income, net of tax  11 
    
Comprehensive income  $6,157 
 
Balances by classification included within Accumulated other comprehensive loss on the accompanying Condensed Balan ceBalance Sheets arewere as follows (in thousands):
 
 September 30,
2010		 December 31,
2009
Derivatives designated as cash flow hedges$(628) $(893)
Employee benefit plans(320) (320)
Total Accumulated other comprehensive loss$(948) $(1,213)
&n bsp;
 March 31,
2011		 December 31,
2010
Derivatives designated as cash flow hedges$(837) $(848)
Employee benefit plans(414) (414)
Total Accumulated other comprehensive loss$(1,251) $(1,262)
 

10

(6) (6)    RELATED-PARTY TRANSACTIONS
��
Receivables and Payables
 
We have accounts receivable and accounts payable balances related to t ransactionstransactions with other BHC subsidiaries. The balances were as follows (in thousands):
September 30,
2010		 December 31,
2009
   March 31,
2011		 December 31,
2010
Accounts receivable with related parties$11,491  $4,146 $5,524  $6,891 
Accounts payable with related parties$34,569  $10,030 $15,164  $12,562 
 
Mo neyMoney 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 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.
 
We had the following balances with the Utility Money Pool (in thousands):
 September 30, 2010 December 31, 2009
    
Notes receivable with Utility Money Pool, net$57,143  $57,737 
 March 31, 2011 December 31, 2010
Notes receivable - Utility Money Pool, net$48,925  $39,862 
 
Advances under these notes bear interest at 2.75% above the daily LIBOR rate (which equates to 3.01%2.99% at September 30, 2010March 31, 2011). Net interest income relating to balances for the Utility Money Pool was as follows (in thousands):
 
 Three Mont hs Ended September 30, Nine Months Ended September 30,
 20102009 20102009
Net interest expense (income)$(121)$42  $(171)$1,126 
 Three Months Ended March 31,  
 20112010   
Net interest expense (income)$(317)$(54)   

12
 


13

Other Balances and Transactions
 
We transact various activities with related parties. The sales and purchases with related parties were as follows (in thousands):
 
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended March 31,  
20102009 2010200920112010 
Revenues:       
Transmission of electricity sold to Black Hills Wyoming$216 $223  $1,158 $653 $162 $173  
Electricity and dispatch services sold to Cheyenne Light$171 $598  $1,045 $1,286 $185 $548  
      
Expenses:     
Coal purchases from WRDC$4,033 $4,183  $13,569 $11,254 $4,887 $4,084  
Excess power generated at Cheyenne Light$2,545 $1,864  $7,255 $5,810 
Purchase of excess power generated at Cheyenne Light$1,807 $2,591  
Natural gas from Enserco$611 $934  $1,333 $1,512 $161 $522  
Corporate support services from Parent$3,101 $3,840  $11,317 $11,274 $5,174 $4,004  
 
We have funds on deposit from Black Hills Wyoming for transmission system reserve which are included in Other, Deferreddeferred credits and other liabilities on the accompanying Condensed Balance Sheets. We have transmission system reserve balances as

11

follows (in thousands):
 March 31, 2011December 31, 2010  
Funds on deposit from affiliate$2,060 $2,044   
Interest on the funds on deposit from Black Hills Wyoming accrues quarterly at an average quarterly prime rate (3.25% at Septe mber 30, 2010March 31, 2011). We have transmission system reserve balances as follows (in thousands)
     
 September 30, 2010December 31, 2009  
     
Deferred credits and other liabilities2,027 $1,978   
     
     
 Three Months Ended September 30,Nine Months Ended September 30,
 2010200920102009
     
Interest expense$16 $16 $48 $53 
 March 31, 2011March 31, 2010  
Interest expense paid to affiliate$17 $16   
 

14

(7) (7)    EMPLOYEE BENEFIT PLANS
 
Defined Benefit Pension Plan
 
We have a noncontributory defined benefit pension plan (the "Plan"" Pension Plan") covering employees who meet certain eligibility requirements.
 
The components of net periodic benefit cost for the Pension Plan arewere as follows (in thousands):
 
 Three Months Ended Nine Months Ended
 September 30, September 30,
 2010 2009 2010 2009
Service cost$304  $287  $912  $871 
Interest cost820  786  2,462  2,357 
Expected return on plan assets(752) (718) (2,256) (2,032)
Prior service cost15  18  45  74 
Net loss344  377  1,030  1,236 
Curtailment expense—  189  —  189 
Net periodic benefit cost$731  $939  $2,193  $2,695 
Pension Plan
In September 2010, bargaining unit participants in the Black Hills Corporation Pension Plan (the “Pension Plan”) voted to ratify a partial freeze to the Pension Plan which is effective January 1, 2011. The partial freeze eliminates new bargaining unit employees from participation in the Pension Plan, and freezes the benefits of current participants except for the following group: those participants who both 1) are age 45 or older as of December 31, 2010 and have 10 years or more of credited service as of January 1, 2011; and 2) elect to continue to accrue additional benefits under the pension plan and consequently forgo the additional age- and points-based employer contribution under the Company's 401(k) retirement savings plan. The assets and obligations for the Black Hills Corporation Pension Plan will be revalued at December 31, 2010 during the year-end valuation process and any pre-tax curtailment expense related to t his partial freeze will be recorded by the Company in the fourth quarter of 2010.
 Three Months Ended March 31,  
 2011 2010    
Service cost$199  $304     
Interest cost773  820     
Expected return on plan assets(905) (752)    
Prior service cost16  15     
Net loss372  344     
Net periodic benefit cost$455  $731     
 
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 arewere as follows (in thousands)thousands):
 
Three Months Ended Nine Months Ended
September 30, September 30,Three Months Ended March 31,  
2010 2009 2010 20092011 2010 
Service cost$94  $54  $282  $162 $52  $94  
Interest cost149  111  447  333 91  149  
Amortization of prior service cost(42) —  (126) — (78) (42) 
Net loss56  —  168  — 41  56  
Net transition obligation—  13  —  39 
Net periodic benefit cost$257  $178  $771  $534 $106  $257  
 
It has been determined that the post-65 retiree prescription drug plans are actuarially equivalent and qualify for th ethe Medicare Part D subsidy. The decrease in net periodic postretirement benefit cost due to the subsidy was less than $0.1 million.

15

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

12

 
The components of net periodic benefit cost for the Supplemental Plans arewere as follows (in thousands):
 
Three Months Ended Nin e Months Ended
September 30, September 30,Three Months Ended March 31,  
2010 2009 2010 20092011 2010 
Interest cost$25  $25  $75  $75 $28  $25  
Net loss7  11  21  33 12  7  
Net periodic benefi t cost$32  $36  $96  $108 
Net periodic benefit cost$40  $32  
 
Contributions
 
We anticipate that we will make contributions to each of the benefit plans during 20102011 and 2011.2012. Contributions to the Healthcare Plan and the Supplemental Plan are expected to be made in the form of benefit payments. Contributions are as follows (in thousands):
 
 Nine Months Ended September 30, 2010Remaining Anticipated Contributions for 2010Anticipated Contributions for 2011
    
Defined Benefit Pension Plan$8,800 $— $— 
Non-Pension Defined Benefit Postretirement Healthcare Plan$244 $81 $400 
Supplemental Non-qualified Defined Benefit Plan$74 $24 $112 
    
 Contributions Made for theRemaining 
 Three Months Ended March 31, 2011Anticipated Contributions for 2011Anticipated Contributions for 2012
Defined Benefit Pension Plan$— $— $904 
Non-Pension Defined Benefit Postretirement Healthcare Plan$107 $321 $518 
Supplemental Non-qualified Defined Benefit Plan$35 $106 $122 
 
(8)     (8)    FAIR VALUE OF FINANCIAL INSTRUMENTS
 
The estimated fair values of our financial instruments arewere as follows (in thousands):
 
September 30, 2010 December 31, 2009March 31, 2011 December 31, 2010
Carrying Amount Fair Value Carrying Amount Fair ValueCarrying Amount Fair Value Carrying Amount Fair Value
Cash and cash equivalents$2,641  $2,641  $1,709  $1,709 $5,056  $5,056  $2,045  $2,045 
Derivative financial instruments - other current assets$355  $355  $—  $— 
Derivative financial instruments - accrued liabilities$—  $—  $5  $5 
Long-term debt, including current maturities$276,526  $293,009  $329,069  $344,942 $276,484  $277,256  $276,503  $301,964 
 
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.

16
 

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.
 
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.
 

1713
 

(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 risks associated with prices and seasonal level requirements.
As of (September 30, 20109 and December 31, 2009, we had the following swaps and related balances (dollars, in thousands):
 Natural Gas Swaps
 September 30, 2010 December 31, 2009
Notional - forward purchase *232,500  232,500 
Notional - forward sale *232,500  — 
Maximum terms in months1  10 
Current derivative asset$355  $— 
Non-current derivative asset$—  $— 
Current derivative liability$—  $5 
Non-current derivative liability$—  $— 
Pre-tax accumulated other comprehensive income (loss) included in the Condensed Balance Sheets$355  $(5)
Unrealized gain/(loss)$—  $— 
    
* Gas in MMBtus.   
(10) )    LONG-TERM DEBT
 
In February 2010, our Series AC bonds matured. These were paid in full for $30.0 million of principal plus accrued interest of $1.2 million.
 
In March 2010, we completed redemption of our Series Y 9.49% bonds in full. These bonds were originally due in 2018. A total of $2.7 million was paid on March 31, 2010, which included the principal balance of $2.5 million plus accrued interest and an early redemption premium of 2.618%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Balance Sheets and is being amortized over the remaining term of the original bonds.
 
In June 2010, we completed redemption of our Series Z 9.35% bonds in full. These bonds were originally due to mature in 2021. A total of $21.8 million was paid on June 1, 2010, whi chwhich 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 is being amortized over the remaining term of the original bonds.
 

18

(11) (10)    SUPPLEMENTAL CASH FLOWSFLOW INFORMATION
 
Nine Months Ended September 30,Three Months Ended March 31,
January 1, 2010 January 1, 20092011 2010
(in thousands)(in thousands)
Non-cash investing and financing activities -      
Property, plant and equipment financed with accrued l iabilities$2,920  $19,344 
Property, plant and equipment financed with accrued liabilities$832  $8,467 
      
Supplemental disclosure of cash flow information:      
Cash (paid) refunded during the period for -      
Interest (net of amounts capitalized)$(14,247) $(9,098)$(3,146) $(3,851)
Income taxes$8,392  $(494)$—  $1,018 
 
(12) (11)    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 20092010 Annual Report on Form 10-K. There have been no material developments in any previously reported proceedings or any new material procee dingsproceedings that have developed or material proceedings that have terminated during the first ninethree months of 2010.2011.
 
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, 2010March 31, 2011, cannot be reasonably determined and could have a material adverse effect on our results of operations, financial position or cash flows.
 

19

Purchase Power Agreement and Partial Sale of Wygen III
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. This PPA provided the City of Gillette, through the JPB, with an option to purchase a 23% ownership interest in our Wygen III facility which commenced commercial operations on April 1, 2010.
On July 14, 2010, we sold a 23% ownership interest in Wygen III to the JPB for $62.0 million. We recognized a gain of $6.2 million on the sale. The JPB exists for the purpose of, among other things, financing the electrical system of the City of Gillette. The transaction entitles the JPB t o 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.
(13) SUBSEQUENT EVENT
Osage Power Plant
On October 1, 2010 we suspended the operations of our 62 year old, 34.5 MW coal-fired Osage power plant located in Osage, Wyoming which was put into operations in 1948. Osage will remain an asset in the generation portf

20

olio and maintain all operating permits so the plant will have the ability to resume full operations, if needed.
 
 

2114
 

ITEM 2.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
 
Three Months Ended Nine Months Ended
September 30, September 30,Three Months Ended March 31,  
2010 2009 2010 20092011 2010 
(in thousands)(in thousands)
Revenues$59,051  $53,086  $169,978  $1 54,380 
Revenue$59,194  $54,489  
Fuel and purchased power20,944  24,254  66,796  66,769 21,560  24,236  
Gross margin38,107  28,832  103,182  87,611 37,634  30,253  
           
Operations and maintenance, administrative and general, depreciation expenses23,253  19,912  68,457  62,980 
Gain on sale of operating assets(6,238) —  (6,238) — 
Operations and maintenance, depreciation and amortization25,717  20,892  
Operating income21,092  8,920  40,963  24,631 11,917  9,361  
           
Interest expense, net(4,144) (2,789) (12,202) (8,035)(4,030) (3,471) 
Other income, net22  17  160  814 391  2,127  
AFUDC - equity266  2,593  2,503  5,270 
Income tax expense(3,158) (1,575) (7,310) (5,445)(2,397) (2,083) 
Net income$14,078  $7,166  $24,114  $17,235 $5,881  $5,934  
 
 

22

The following tables provide certain financial information and operating statistics (dollars in thousands):
 
 Electric Revenue
 Three Months Ended September 30, Nine Months Ended September 30,
Customer Base2010 Percentage Change  2009 2010 Percentage Change 2009
Commercial$18,529  18 % $15,694  $49,172  10 % $44,888 
Residential13,492  21 % 11,132  39,517  10 % 35,804 
Industrial5,402  15 % 4,714  16,243  12 % 14,494 
Municipal Sales850  ; 9 % 778  2,251  9 % 2,074 
Total retail sales38,273  18 % 32,318  107,183  10 % 97,260 
Contract wholesale4,758  (27)% 6,488  18,554  (1)% 18,672 
Wholesale off system9,695  1 % 9,625  26,950 &nb sp;10 % 24,610 
Total electric sale52,726  9 % 48,431  152,687  9 % 140,542 
Other revenues6,325  36 % 4,655  17,291  25 % 13,838 
Total revenues$59,051  11 % $53,086  $169,978  10 % $154,380 
 Electric Revenue by Customer Type      
 Three Months Ended March 31,  
 2011 Percentage Change 2010      
Commercial$17,314  19 % $14,539       
Residential17,170  19 % 14,479       
Industrial5,764  24 % 4,637       
Municipal sales734  12 % 653       
Total retail sales40,982  19 % 34,308       
Contract wholesale4,620  (31)% 6,718       
Wholesale off-system6,953  (20)% 8,716       
Total wholesale sales52,555  6 % 49,742       
Other revenue6,639  40 % 4,747       
Total revenue$59,194  9 % $54,489       

15

 Megawatt Hours Sold by Customer Type      
 Three Months Ended March 31,  
 2011 Percentage Change 2010      
Commercial178,237  (3)% 184,438       
Residential174,400  — % 174,535       
Industrial88,749  2 % 86,663       
Municipal sales8,302  1 % 8,226       
Total retail sales449,688  (1)% 453,862       
Contract wholesale *89,959  (47)% 168,465       
Wholesale off-system242,156  5 % 231,047       
Total wholesale sales781,803  (8)% 853,374       
Losses and company use32,671  236 % 9,719       
Total energy814,474  (6)% 863,093       
*    Decrease in 2011 MWh due to the termination of wholesale contracts with two previous wholesale customers who acquired ownership interest in the Wygen III facility.
 
 Megawatt Hours Sold
 Three Months Ended September 30, Nine Months Ended September 30,
Customer Base2010 Percentage Change 2009 2010 Percentage Change 2009
Commercial195,634  (6)% 207,939  544,935  (1)% 553,150 
Residential122,123  8 % 113,266  410,561  4 % 395,865 
Industrial90,426  13 % 80,222  278,514  7 % 260,190 
Municipal sales9,008  (9)% 9,894  24,811  (3)% 25,556 
Total retail sales417,191  1 % 411,321  1,258,821  2 % 1,234,761 
Contract wholesale83,013  (49)% 161,796  371,736  (22)% 473,723 
Wholesale off system309,297  (0)% 309,770  839,408   ;7 % 784,173 
Total electric sales809,501  (8)% 882,887  2,469,965  (1)% 2,492,657 
Losses and company use42,203  37 % 30,764  95,714  (2)% 98,057 
Total energy851,704  (7)% 913,651  2,565,679  (1)% 2,590,714 
 Electric Utility Power Plant Availability 
 Three Months Ended March 31, 
 20112010 
Coal-fired plants90.1%
(a) 
93.9%
(b) 
 
Other plants98.8% 99.8%  
Total availability93.5% 96.5%  
(a)    2011 reflects a planned major outage at the PacifiCorp operated Wyodak plant.
(b)    2010 reflects an unplanned 12 day outage at the PacifiCorp operated Wyodak plant due to a collapsed scrubber vessel.
 
 Electric Utility Power Plant Availability 
 Three Months Ended September 30, Nine Months Ended September 30, 
 2010 2009 2010 2009 
Coal-fired plants *94.8%
(a) 
97.7%
(b) 
93.1%
(a) 
90.5%
(b) 
Other plants98.2% 99.6% 98.9% 97.1% 
Total availability96.1% 98.5% 95.4% 93.4% 
___________________________            
(a) 2010 reflect the addition of Wygen III which commenced commercial operations on April 1, 2010. Wygen III's availability during the three and nine months ended September 30, 2010 was 96.6% and 91.2%, respectively.
(b)    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.
 Megawatt Hours Generated and Purchased      
 Three Months Ended March 31,  
Generated -2011 Percentage Change 2010      
Coal-fired437,838  2 % 430,573       
Gas-fired1,024  (64)% 2,838       
 438,862  1 % 433,411       
            
Purchased375,612  (13)% 429,682       
Total Generated and Purchased814,474  (6)% 863,093       
 
 

2316
 

 Megawatt Hours Generated and Purchased
 Three Months Ended September 30, Nine Months Ended September 30,
Generated -2010 Percentage Change 2009 2010 Percentage Change 2009
Coal-fired525,000  13 % 465,068  1,514,831  21 % 1,251,276 
Gas-fired11,780  (58)% 28,251  15,724  (55)% 35,076 
 536,780  9 % 493,319  1,530,555  19 % 1,286,352 
            
Purchased314,924  (25)% 420,332  1,035,124&n bsp; (21)% 1,304,362 
Total Generated and Purchased851,704  (7)% 913,651  2,565,679  (1)% 2,590,714 
Degree DaysDegree Days 
Three Months Ended September 30,Nine Months Ended September 30,Three Months Ended March 31, 
201020092010200920112010 
Heating and cooling degree days:   
Actual -   
Heating degree days188 178 4,484 4,705 3,707 3,392  
Cooling degree days456 303 521 354 — —  
   
Variance from normal -   
Heating degree days(17)%(22)%(3)%4 %12%3% 
Cooling degree days(8)%(39)%(12)%(41)%—%—% 
 
Amounts are presented on a pre-tax basis unless otherwise indicated. Minor differences in comparative amounts may result due to rounding.
 ;
Three Months Ended September 30, 2010March 31, 2011 Compared to Three Months Ended September 30, 2009March 31, 2010. Net income was $14.15.9 million compared to $7.25.9 million for the same period in the prior year primarily due to the following:
 
Gross margin: Gross margin increased $9.37.4 million primarily due to an increase of $6.2 million related to the impact of the outcome of the rate case during 2010 partially offset by a decrease in margins resulting from two previous wholesale power customers acquiring an increase of $2.1 millionownership interest in off-system margins, and increased intercompany revenues of $0.3 million related to a shared services agreement.Wygen III.
 
Operating, generalOperations and administrative,maintenance, depreciation expensesexpense: Operating expenses increased $3.34.8 million primarily due to additional operating costs of $1.4 million and an increase of $1.3 million in depreciation expense of $2.4 million associated with the Wygen III plant which commenced commercial operationsoperation on April 1, 2010, increased employee compensation and an increase of $0.6 million in intercompany costs associated with a shared services agreement.
Gain on sale of operating assets: Gain on sale of operating assets of $6.2 million resulted from the partial sale of Wygen III to the City of Gillette.benefits, and benefits and increased corporate allocations.
 
Interest expense, net: Interest expense, net increased $1.40.6 million primarily due to higher interest expense of $1.0 million on the first mortgage bonds partially off set by a $0.6$1.4 million decrease in AFUDC associated with the borrowed funds component due to the completed construction at Wygen III.III partially offset by lower interest expense of $0.7 million due to repayment of Series AC, Series Y and Series Z bonds during 2010.
 
Other income, net: Other income, net decreased $2.31.7 million primarily due to a decrease in AFUDC-equity.AFUDC-equity due to the placement of Wygen III into commercial operation.
 
Income tax, expense: The effective tax rate was comparable increased compared to the same period in the prior year. However,This increase in the effective tax rate was impacted byis due to a $2.2 million tax benefit for a repairs deduction taken for tax purposes and the flow-through treatment of the associated tax benefit resulting from a rate case settlement offset by lower tax benefit from AFUDC-equity which decreased upon commercial operationsoperation of Wygen III.
 

24

Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009. Net income was $24.1 million compared to $17.2 million for the same period in prior year primarily due to the following:
Gross margin: Gross margin increased $15.6 million primarily due to the impact of $12.1 million related to the outcome of the rate case during 2010, an increase of $2.6 million from off-system margins, and increased intercompany revenues of $1.5 million associated with a shared services agreement.
Operating expenses: Operating expenses increased $5.5 million primarily due to a $2.7 million increase in operating expenses associated with the Wygen III plant which commenced commercial operations on April 1, 2010, an increase of $1.7 million in depreciation expense primarily associated with the Wygen III plant which commenced commercial operations on April 1, 2010, an increase of $0.7 million in property taxes and an increase of $1.8 million in intercompany costs associated with a shared services agreement.
Gain on sale of operating assets: Gain on sale of op erating assets of $6.2 million resulted from the partial sale of Wygen III to the City of Gillette.
Interest expense, net: Interest expense, net increased $4.2 million primarily due to a higher interest expense on the first mortgage bonds partially offset by a $0.4 million decrease in AFUDC associated with the borrowed funds component due to the completed construction at Wygen III.
Other income, net: Other income decreased $3.4 million primarily due to a decrease in AFUDC-equity of $2.8 million and recognition of $0.5 million from the sale of Wygen III in the prior year.
Income tax, expense: The effective tax rate was comparable to the same period in the prior year. However, the effective tax rate was impacted by a $2.2 million tax benefit for a repairs deduction taken for tax purposes and the flow-through treatment of the associated tax benefit resulting from a rate case settlement partially offset by lower tax benefit from AFUDC-equity which decreased upon commercial operations of Wygen III.

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Significant Events
 
Osage Power Plant
On October 1, 2010 we suspended the operations of our 62 year old, 34.5 MW coal-fired Osage Power Plant located in Osage, Wyoming. The Osage plant consumed 103,100 tons of coal during the first six months of 2010 and 247,100 tons of coal during 2009. Osage will remain an asset in the generation portfolio and maintain all operating permits so the plant will have the ability to resume full operations, if needed.
Sale 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 effective April 2010 that replaced a previous PPA entered into in 1998. This new agreement provided the City of Gillette, through the 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. The JPB 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 w e will recognize a gain on the sale of approximately $6.2 million. Under the Participation Agreement among the owners of Wygen III, we will continue to operate Wygen III and the City of Gillette will pay us for administrative services and its share in the costs of operating the plant for the life of the facility. The PPA dated March 2010 terminated upon the closing of the transaction.
Smart Grid Funding
In April 2010, we reached an agreement with the DOE for smart grid funding through grants totaling $9.6 mill ion made available through the American Recovery and Reinvestment Act of 2009. The grants will enable us to install smart meters and related communications infrastructure and information technology software and equipment. We expect to complete installation of these meters in 2011.
Wygen III Power Plant Project
Construction of our 110 MW coal-fired base load electric generation facility, Wygen III, was completed and it commenced commercial operations on April 1, 2010. The 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. As described above, in July 2010, we sold an additional 23% ownership in Wygen III to the City of Gillette.
Rate Case Filed with the SDPUC
In 2009,28, 2011, we filed a rate case withrequest for declaratory ruling from the SDPUC requesting an electric revenue increase to recover costs associated with Wygen IIIconfirm that a proposed 20 MW wind farm site near Belle Fourche, SD is reasonable and other generatio n, transmissioncost effective. This $38.0 million project would be owned by us and distribution assetsadvances our progress toward the State of South Dakota's objective that 10% of all electricity sold be obtained from renewable, recycled and increased operating expenses incurred during the past four years. We were 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 7, 2010, the SDPUC approved a final revenue increase of $15.2 million or 12.7% effective April 1, 2010. The final settlement represented a rate base increase of $22.0 million, or 19.4%.conserved energy resources by 2015.
 
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 a South Dakota Surplus Energy Credit of $2.5 million in year on e (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.

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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 were seeking a $3.8 million increase in annual utility revenues. On May 13, 2010, the WPSC approved an annual rate increase of $3.1 million effective June 1, 2010.

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Financing Tra nsactionsTransactions and Short-Term Liquidity
 
Financing
 
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 March 2010, we completed a call of our Series Y 9.49% bonds in full. These bonds were originally due in 2018. A total 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 2.618%.
 
In June 2010, we completed a call of our Series Z 9.35% bonds in full. These bonds, originally due in 2021, were paid in full on 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%.
 
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, 2010March 31, 2011, our first mortgage bonds credit ratings, as assessed by the three major credit rating agencies, were as follows:
 
Rating AgencyRatingOutlook
FitchA-Stable
Moody'sA3Stable
S&PBBB+Stable
 

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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 actual results to differ materially from those anticipated. In some cases, forward-looking statements can be identified by t erminologyterminology 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 20092010 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; our ability 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 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 and subsequent rules and regulations promulgated thereunder;
 
•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 and subsequent rules and regulations promulgated thereunder;
Our ability to remedy any deficiencies that may be identified in the revie wreview 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;
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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•    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 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 ris ks;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 and to recover those expenditures in customer rates, where applicable;

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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;
 
•    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;

 
•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 economic changes, including the impact of consolidations and changes in competition;
Industry, market, political and economic 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 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;
 
•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 descr ibeddescribed 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, 2010March 31, 2011. 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, 2010March 31, 2011 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.
Effective August 1, 2010, the Company implemented a new financial and human resource system. Although many financial processes were changed, the underlying intern al controls did not materially change. The new financial and human resource system was implemented as part of a corporate unification project of Black Hills Corp. and was not undertaken in response to any actual or perceived significant deficiencies in the Company's internal control over financial reporting. The new system streamlines processes by consolidating two financial systems into one, standardizes accounting systems, is intended to improve management reporting and will consolidate accounting functions for the Parent Company and its subsidiaries.
 

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& nbsp;

BLACK HILLS POWER, INC.
 
Part II - Other Information
 
Item 1.Legal Proceedings
 
For information regarding legal proceedings, see Note 1213 of Notes to Financial Statements in Item 8 of our 20092010 Annual Report on Form 10-K and Note 1211 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 1211 is incorporated by reference into this item.

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Item 1A.Risk Factors
 
Except to the extent updated or described below, ourOur Risk Factors are documented in Item 1A. of Part I in our Annual Report on Form 10-K for the year ended December 31, 2009.2010
Municipal governments may seek to limit or deny franchise privileges.
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. Although 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.
Federal and state laws concerning climate change and air emissions may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.
We own and operate regulated and non-regulated fossil-fuel generating plants in South Dakota and Wyoming. We recently completed another fossil-fuel generating plant in Wyoming. Recent developments under federal and state laws and regulation governing air emissions from fossil-fuel generating plants will likely result in more stringent emission limitations, which could have a material impact on our costs or operations.
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 carbon dioxide and other GHG emissions are pollutants subject to regulation under the motor vehicle provisions of the Clean Air Act. The case was remanded to the United States Environmental Protection Agency (the "EPA") for further rule-making 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, 2009, the EPA signed its proposed Endangerment and Cause or Contribute Finding for Greenhouse Gases 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 October 30, 2009, the EPA published final rules regarding a mandatory GHG reporting regimen, the purpose of which would be to collect data to inform future policy and regulatory decisions.
On June 23, 2010, the EPA published in the Federal Register the Greenhouse Gas Tailoring Rule, implementing regulation of greenhouse gases for permitting purposes. This rule will impact Black Hills in the event of a major modification at an existing facility or in the event of construction of a new major source. Existing permitted facilities will see monitoring and reporting requirements incorporated into their operating permits upon renewal. New projects or major modifi cations to existing projects will result in a Best Available Control Technology review that could result in more stringent emissions control practices and technologies.
On April 29, 2010, the EPA published in the Federal Register the proposed Industrial and Commercial Boiler Hazardous Air Pollutant (IB MACT) regulations, proposing hazardous air pollutant related emission limits and monitoring requirements.  The final rule has a court ordered deadline of January 16, 2011 and as proposed, will have a significant impact on our Neil Simpson 1, Osage, and Ben French facilities.  The regulation currently has a three year compliance window and will require engineering evaluations to determine economic viability of continued operations of these units. In our current opi nion, the proposed regulations will lead to retirement of these units within three years of the effective date of the final rule.
On June 21, 2010, the EPA published in the Federal Register the proposed coal combustion residuals regulations.  The regulations are complex and contain various options and at this time we cannot determine an accurate impact on our operations.  EPA is expected to propose the Electric Utility MACT regulation for control of hazardous air pollutants, in the first quarter of 2011. Certain requirements of that regulation could have significant impacts on Neil Simpson 2 and Wygen III. Also late in 2011 EPA is scheduled to issue updated regulations for wastewater discharges from electric generating units, which could have a significant impa ct on all of our generating fleet.
In addition, various climate change bills are under consideration in Congress. Due to 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 al lowed, the allocation of emission allowances to specific sources, and the effect of carbon regulation on natural gas and coal prices.
New or more stringent regulations, including GHG emissions limitations or other energy efficiency requirements, such as the EPA's recently published Greenhouse Gas Tailoring Rule, which will require additional monitoring and reporting requirements for existing and new facilities, would require, 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-fu el generating plants are included in rate base, we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by our non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.
We own regulated electric utilities that serve customers in South Dakota, Wyoming, and Montana. To a varying degree Montana has adopt ed mandatory renewable portfolio standards that require electric utilities to supply a minimum percentage of the power delivered to customers from renewable resources (e.g., wind, solar, biomass) by a certain date in the future. These renewable energy portfolio standards have increased the power supply costs of our electric operations. If these states increase their renewable energy portfolio standards, or if similar standards are imposed by the other states in which we operate electric utilities, our power supply costs will further increase. Although we will seek to recover these higher costs in rates, any unrecovered costs could have a material negative impact on our results of operations and financial condition.
Increased risks of regulatory penalties could negatively impact our business.
The Energy Policy Act of 2005 increased the Federal Energy Regulatory Commission's (“FERC”) civil penalty authority for violation of FERC statutes, rules and orders.  FERC can now impose penalties of $1.0 million per violation, per day, and other regulatory agencies that impose compliance requirements relative to our business also have civil penalty authority.  In addition, FERC has delegated certain aspects of authority for enforcement of electric system reliability standards to the North American Electric Reliability Corporation, with similar penalty authority for violations. Many rules that were historically subject to voluntary compliance are now mandatory and subject to potential civil penalties for violations.  If a serious v iolation did occur, and penalties were imposed by FERC or another federal agency, this action could have a material adverse effect on our operations or our financial results..
 

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Item 6.    Exhibits
 
 
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 t hethe 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: November 10, 2010
May 12, 2011
 

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EXHIBIT INDEX
 
Exhibit Number    Description
 
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 Sect ionSection 906 of the Sarbanes - Oxley Act of 2002.

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