UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

Form 10-Q


x

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the quarterly period ended JuneSeptember 30, 2009.

OR

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the transition period from __________ to __________.

Commission File Number 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 filer

o

Accelerated filer

o


Non-accelerated filer

x

Smaller reporting company

o


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


Yes

o

No

x


As of July 31,October 30, 2009, 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 –

Three and SixNine Months Ended JuneSeptember 30, 2009 and 2008

4

Condensed Balance Sheets –

JuneSeptember 30, 2009 and December 31, 2008

5

Condensed Statements of Cash Flows –

SixNine Months Ended JuneSeptember 30, 2009 and 2008

6

Notes to Condensed Financial Statements

7-15

7-16

Item 2.

Results of Operations

15-20

17-23

Item 4.

Controls and Procedures

21

24

PART II.

OTHER INFORMATION

Item 1.

Legal Proceedings

22

25

Item 1A.

Risk Factors

22-23

25-27

Item 6.

Exhibits

24

28

Signatures

25

29

Exhibit Index

26

30





GLOSSARY OF TERMS


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


AFUDC

Allowance for Funds Used During Construction

BHC

ASC 105

ASC 105, “FASB Accounting Standards Codification and the Hierarchy of

Generally Accepted Accounting Principles – a replacement of FASB
Standard No. 162”
ASC 715ASC 715, “Compensation – Retirement Benefits”
ASC 810-10-15ASC 810-10-15, “Consolidation of Variable Interest Entities”
ASC 815ASC 815, “Derivative and Hedging”
ASC 820ASC 820 “Fair Value Measurements and Disclosures”
ASC 825ASC 825, “Financial Instruments”
ASC 855ASC 855, “Subsequent Events”
BHCBlack Hills Corporation, the Parent Company

Black Hills Energy

The name used to conduct the business activities of Black Hills Utility

Holdings, Inc.,

Holdings, Inc., a direct subsidiary of the Parent Company

Black Hills Wyoming

Black Hills Wyoming, LLC, an indirect subsidiary of the Parent Company

Cheyenne Light

Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary

of the

of the Parent Company

CO2

Carbon dioxide

Enserco

Enserco Energy, Inc., an indirect subsidiary of the Parent Company

EPA

U.S. Environmental Protection Agency

FAS

Financial Accounting Standard

FASB

Financial Accounting Standards Board

FERC

Federal Energy Regulatory Commission

FSP

FASB Staff Position

FSP FAS 107-1

FSP FAS 107-1, “Interim Disclosure About Fair Value of Financial

Instruments”

Instruments”

FSP FAS 132(R)-1

FSP FAS 132(R)-1, “Employer’s Disclosures about Pensions and Other

Postretirement Benefits” (Revised)

GAAP

Generally Accepted Accounting Principles

GHG

Greenhouse gas

LIBOR

London Interbank Offered Rate

MDU

MEAN

Municipal Energy Agency of Nebraska

MDUMDU Resources Group, Inc.

MW

MMBtu

Megawatts

One million British thermal units

MWh

MW

Megawatt-hours

Megawatts

SEC

MWh

Megawatt-hours

PPAPurchase Power Agreement
SDPUCSouth Dakota Public Utilities Commission
SECU.S. Securities and Exchange Commission

SFAS

Statement of Financial Accounting Standards

SFAS 157

SFAS 157, “Fair Value Measurements”

SFAS 161

SFAS 161, “Disclosure about Derivative Instruments and Hedging Activities –

an

an amendment of FASB Statement No. 133”

SFAS 165

SFAS 165, “Subsequent Events”

SFAS 167

SFAS 167, “Amendment to FASB Interpretation No. 46(R)”

SFAS 168

SFAS 168, “FASB Accounting Standards Codification and the

Hierarchy of Generally

Accepted Accounting Principles – a

replacement of FASB Standard No. 162”

WRDC

Silver Sage

Silver Sage Wind Power, LLC, a subsidiary of Duke Energy Corporation

WPSCWyoming Public Service Commission
WRDCWyodak Resources Development Corp., an indirect subsidiary of the Parent

Company




BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF INCOME

(unaudited)

 

Three Months Ended

Six Months Ended

 

June 30,

June 30,

 

2009

2008

2009

2008

 

(in thousands)

 

 

 

 

 

 

 

 

 

Operating revenue

$

46,836

$

57,978

$

101,294

$

115,610

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

Fuel and purchased power

 

19,753

 

28,226

 

42,515

 

55,725

Operations and maintenance

 

8,486

 

8,914

 

16,124

 

16,011

Administrative and general

 

6,972

 

4,610

 

13,243

 

10,073

Depreciation and amortization

 

5,006

 

5,278

 

10,052

 

10,530

Taxes, other than income taxes

 

1,613

 

1,680

 

3,649

 

3,409

 

 

41,830

 

48,708

 

85,583

 

95,748

 

 

 

 

 

 

 

 

 

Operating income

 

5,006

 

9,270

 

15,711

 

19,862

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

Interest expense

 

(2,838)

 

(2,513)

 

(5,410)

 

(5,206)

Interest income

 

65

 

25

 

164

 

119

Allowance for funds used

 

 

 

 

 

 

 

 

during construction – equity

 

1,276

 

606

 

2,677

 

890

Other income, net

 

508

 

53

 

797

 

168

 

 

(989)

 

(1,829)

 

(1,772)

 

(4,029)

 

 

 

 

 

 

 

 

 

Income before income taxes

 

4,017

 

7,441

 

13,939

 

15,833

Income taxes

 

(912)

 

(2,190)

 

(3,870)

 

(5,006)

 

 

 

 

 

 

 

 

 

Net income

$

3,105

$

5,251

$

10,069

$

10,827


  Three Months Ended  Nine Months Ended 
  September 30,  September 30, 
  2009  2008  2009  2008 
  (in thousands) 
             
Operating revenue $53,086  $59,358  $154,380  $174,968 
                 
Operating expenses:                
Fuel and purchased power  24,254   30,119   66,769   85,844 
Operations and maintenance  7,460   7,604   23,584   23,615 
Administrative and general  6,385   4,538   19,628   14,612 
Depreciation and amortization  4,708   5,275   14,761   15,805 
Taxes, other than income taxes  1,359   1,594   5,007   5,002 
   44,166   49,130   129,749   144,878 
                 
Operating income  8,920   10,228   24,631   30,090 
                 
Other income (expense):                
Interest expense  (2,837)  (2,751)  (8,246)  (7,957)
Interest income  48   171   211   290 
Allowance for funds used                
during construction – equity  2,593   1,183   5,270   2,072 
Other income, net  17   17   814   185 
   (179)  (1,380)  (1,951)  (5,410)
                 
Income before income taxes  8,741   8,848   22,680   24,680 
Income taxes  (1,575)  (2,477)  (5,445)  (7,482)
                 
Net income $7,166  $6,371  $17,235  $17,198 


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





BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(unaudited)

 

June 30,

December 31,

 

2009

2008

 

(in thousands)

ASSETS

 

 

 

 

Current assets:

 

 

 

 

Cash and cash equivalents

$

626

$

4

Receivables (net of allowance for doubtful accounts

 

 

 

 

of $365 and $370, respectively) –

 

 

 

 

Customers

 

15,251

 

23,881

Affiliates

 

2,707

 

12,619

Other

 

6,384

 

2,111

Materials, supplies and fuel

 

19,149

 

19,309

Other current assets

 

7,399

 

5,730

 

 

51,516

 

63,654

 

 

 

 

 

Investments

 

4,138

 

3,999

 

 

 

 

 

Property, plant and equipment

 

897,660

 

843,691

Less accumulated depreciation

 

(289,885)

 

(281,220)

 

 

607,775

 

562,471

 

 

 

 

 

Other assets:

 

 

 

 

Regulatory assets

 

33,732

 

33,818

Other

 

1,601

 

2,842

 

 

35,333

 

36,660

 

$

698,762

$

666,784

LIABILITIES AND STOCKHOLDER’S EQUITY

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

Current maturities of long-term debt

$

32,021

$

2,016

Accounts payable

 

38,175

 

26,567

Accounts payable – affiliates

 

9,155

 

10,411

Notes payable – affiliates

 

75,826

 

70,184

Accrued liabilities

 

16,767

 

15,151

Deferred income taxes

 

1,331

 

732

 

 

173,275

 

125,061

 

 

 

 

 

Long-term debt, net of current maturities

 

117,204

 

149,193

 

 

 

 

 

Deferred credits and other liabilities:

 

 

 

 

Deferred income taxes

 

88,758

 

85,504

Regulatory liabilities

 

14,340

 

13,573

Benefit plan liabilities

 

31,962

 

29,904

Other

 

8,210

 

8,626

 

 

143,270

 

137,607

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

 

203,350

 

193,281

Accumulated other comprehensive loss

 

(1,328)

 

(1,349)

 

 

265,013

 

254,923

 

$

698,762

$

666,784


  September 30,  December 31, 
  2009  2008 
  (in thousands) 
ASSETS      
Current assets:      
Cash and cash equivalents $1,150  $4 
Receivables, net –        
Customers  19,025   23,881 
Affiliates  2,236   12,619 
Other  4,071   2,111 
Materials, supplies and fuel  18,836   19,309 
Other current assets  9,422   5,730 
   54,740   63,654 
         
Investments  4,156   3,999 
         
Property, plant and equipment  919,746   843,691 
Less accumulated depreciation  (292,610)  (281,220)
   627,136   562,471 
         
Other assets:        
Regulatory assets  26,965   33,818 
Other  1,546   2,842 
   28,511   36,660 
  $714,543  $666,784 
LIABILITIES AND STOCKHOLDER’S EQUITY        
         
Current liabilities:        
Current maturities of long-term debt $32,023  $2,016 
Accounts payable  24,568   26,567 
Accounts payable – affiliates  5,895   10,411 
Notes payable – affiliates  104,898   70,184 
Accrued liabilities  16,618   15,151 
Deferred income taxes  1,043   732 
   185,045   125,061 
         
Long-term debt, net of current maturities  117,186   149,193 
         
Deferred credits and other liabilities:        
Deferred income taxes  90,088   85,504 
Regulatory liabilities  14,791   13,573 
Benefit plan liabilities  26,057   29,904 
Other  9,214   8,626 
   140,150   137,607 
Stockholder’s equity:        
Common stock $1 par value; 50,000,000 shares authorized;        
23,416,396 shares issued  23,416   23,416 
Additional paid-in capital  39,575   39,575 
Retained earnings  210,516   193,281 
Accumulated other comprehensive loss  (1,345)  (1,349)
   272,162   254,923 
  $714,543  $666,784 

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





BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited)

 

Six Months Ended

 

June 30,

 

2009

2008

 

(in thousands)

Operating activities:

 

 

 

 

Net income

$

10,069

$

10,827

Adjustments to reconcile net income to cash

 

 

 

 

provided by operating activities:

 

 

 

 

Depreciation and amortization

 

10,052

 

10,530

Provision for valuation allowances

 

(5)

 

48

Deferred income tax

 

3,634

 

3,041

Allowance for funds used during construction –

 

 

 

 

equity

 

(2,677)

 

(890)

Change in operating assets and liabilities –

 

 

 

 

Accounts receivable and other current assets

 

10,255

 

8,617

Accounts payable and other current liabilities

 

11,011

 

1,859

Other operating activities

 

3,529

 

1,299

 

 

45,868

 

35,331

Investing activities:

 

 

 

 

Property, plant and equipment additions

 

(76,911)

 

(58,841)

Proceeds from sale of ownership interest in plant

 

32,321

 

Change in money pool notes receivable from

 

 

 

 

affiliate, net

 

 

10,304

Other investing activities

 

(4,314)

 

(166)

 

 

(48,904)

 

(48,703)

 

 

 

 

 

Financing activities:

 

 

 

 

Long-term debt – repayments

 

(1,984)

 

(1,982)

Change in money pool note payable to

 

 

 

 

affiliate, net

 

5,642

 

13,325

 

 

3,658

 

11,343

 

 

 

 

 

Increase (decrease) in cash and

 

 

 

 

cash equivalents

 

622

 

(2,029)

 

 

 

 

 

Cash and cash equivalents:

 

 

 

 

Beginning of period

 

4

 

2,033

End of period

$

626

$

4

 

 

 

 

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

 

 

 

 

Non-cash investing and financing activities:

 

 

 

 

Property, plant and equipment acquired

 

 

 

 

with accrued liabilities

$

27,782

$

11,449

 

 

 

 

 

Cash paid during the period for:

 

 

 

 

Interest (net of amounts capitalized)

$

4,970

$

5,820

Income taxes paid

$

621

$

4,333


  Nine Months Ended 
  September 30, 
  2009  2008 
  (in thousands) 
Operating activities:      
Net income $17,235  $17,198 
Adjustments to reconcile net income to cash        
provided by operating activities:        
Depreciation and amortization  14,761   15,805 
Provision for valuation allowances  (111)  172 
Deferred income tax  5,304   6,580 
Allowance for funds used during construction –        
equity  (5,270)  (2,072)
Change in operating assets and liabilities –        
Accounts receivable and other current assets  13,494   4,088 
Accounts payable and other current liabilities  (9,249)  (1,048)
Regulatory assets and liabilities  6,517   (3,811)
Other operating activities  (2,668)  1,959 
   40,013   38,871 
Investing activities:        
Property, plant and equipment additions  (106,150)  (97,475)
Proceeds from sale of ownership interest in plant  32,783    
Change in money pool notes receivable from        
affiliate, net     10,304 
Other investing activities  1,786   (183)
   (71,581)  (87,354)
Financing activities:        
Long-term debt – repayments  (2,000)  (1,995)
Change in money pool note payable to        
affiliate, net  34,714   49,796 
   32,714   47,801 
Increase (decrease) in cash and        
cash equivalents  1,146   (682)
         
Cash and cash equivalents:        
Beginning of period  4   2,033 
End of period $1,150  $1,351 
         
Supplemental disclosure of cash flow information:        
         
Non-cash investing and financing activities:        
Property, plant and equipment acquired        
with accrued liabilities $19,344  $15,750 
         
Cash paid during the period for:        
Interest (net of amounts capitalized) $9,098  $9,833 
Income taxes paid $494  $3,396 

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





BLACK HILLS POWER, INC.


Notes to Condensed Financial Statements

(unaudited)

(Reference is made to Notes to Financial Statements

included in our 2008 Annual Report on Form 10-K)


(1)

MANAGEMENT’S STATEMENT


The condensed financial statements included herein have been prepared by Black Hills Power, Inc., (the “Company,” “we,” “us,” “our”) without audit, pursuant to the rules and regulations of the SEC.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented.  These financial statements should be read in conjunction with the financial statements and the notes thereto, included in our 2008 Annual Report on Form 10-K filed with the SEC.  These financial statements include consideration of events through August 14,November 11, 2009.


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


(2)

RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

STANDARDS

SFAS 157

During September 2006,


FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB issued SFAS 157. This Statement defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 does not expand the application of fair value accounting to any new circumstances, but applies the framework to other accounting pronouncements that require or permit fair value measurement. We adopted the provisions of SFAS 157 on January 1, 2008 for all assets and liabilities measured at fair value. The adoption of SFAS 157 and related FSPs did not have a material impact on our financial position, results of operations or cash flows.

7


SFAS 161

In March 2008, the FASB issued SFAS 161 which requires enhanced disclosures about derivative and hedging activities and their affect on an entity’s financial position, financial performance and cash flows. SFAS 161 encourages, but does not require, disclosures for earlier periods presented for comparative purposes at initial adoption. We adopted the provisions of SFAS 161 on January 1, 2009.

At June 30, 2009, we do not hold any derivative instruments. We occasionally hold natural gas in storage for use as fuel for generating electricity with our gas-fired combustion turbines. To minimize associated price risk and seasonal storage level requirements, we occasionally utilize various derivative instruments in managing these risks. Additionally, we engage in activities to manage risk associated with changes in interest rates. In prior years, we entered into floating-to-fixed interest rate swap agreements to minimize our exposure to interest rate fluctuations associated with our floating rate debt obligations. These swaps were designated as cash flow hedges in accordance with SFAS 133, and accordingly the resulting gain or loss is carried in Accumulated other comprehensive loss on the accompanying Condensed Balance Sheets and amortized over the life of the related debt. For the six months ended June 30, 2009 and 2008, respectively, we amortized less than $0.1 million from Accumulated other comprehensive loss to Interest expense related to a settled interest rate swap designated as a cash flow hedge.

SFAS 165

In May 2009, the FASB issued SFAS 165, which establishes general standards of accounting for and disclosures of events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. We adopted and applied the provisions of SFAS 165 for our financial statements issued after June 15, 2009.

FSP FAS 107-1

In April 2009, the FASB approved FSP FAS 107-1 effective for interim and annual periods ending after June 15, 2009. This FSP requires public companies to provide more frequent disclosures about the fair value of their financial instruments. These disclosures are included in Note 7.

(3)

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

SFAS 167

In June 2009, the FASB issued SFAS 167 which is a revision to FASB InterpretationStandard No. 46(R). This Statement amends the analysis performed by a company in determining whether an entity that is insufficiently capitalized or is not controlled through a voting interest should be consolidated. It will require additional disclosures about the involvement with variable interest entities and any significant changes in risk exposure due to that involvement. We are currently assessing the impact that the adoption of this Statement will have on our financial condition, results of operations, and cash flows.

162, ASC 105 (SFAS 168)

8



SFAS 168

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


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

FSP


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

The ASC for Fair Value Measurements and Disclosures defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements.  This does not expand the application of fair value accounting to any new circumstances, but applies the framework to other applicable GAAP that requires or permits fair value measurement.  We apply fair value measurements to certain assets and liabilities, primarily commodity derivatives.  The adoption of this standard did not have a material impact on the Company’s financial position, results of operations or cash flows.

7


Derivative and Hedging, ASC 815 (SFAS 161)

The ASC for Derivative and Hedging Disclosures requires enhanced disclosures about derivative and hedging activities and their affect on an entity’s financial position, financial performance and cash flows.  ASC 815 encourages, but does not require, disclosures for earlier periods presented for comparative purposes at initial adoption.  Required comparative disclosures for periods subsequent to January 1, 2009 are provided in Note 9.

Subsequent Events, ASC 855 (SFAS 165)

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

Financial Instruments, ASC 825 (FSP FAS 132(R)-1

During December 2008,107-1)


The ASC for Financial Instruments requires public companies to provide more frequent disclosures about the fair value of their financial instruments for interim and annual periods ending after June 15, 2009.  These disclosures are included in Note 8.

(3)RECENTLY ISSUED ACCOUNTING STANDARDS

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

In June 2009, the FASB issued FSPa revision regarding consolidations.  The amendment requires a Company to consider whether an entity that is insufficiently capitalized or is not controlled through voting should be consolidated.  It will require additional disclosures about the involvement with variable interest entities and any significant changes in risk exposure due to that involvement.  This standard is effective for annual periods that begin after November 15, 2009.  We are currently assessing the impact that the adoption of this standard will have on our financial condition, results of operations, and cash flows.

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

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


·How investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies;


·

The major categories of plan assets;


·

The input and valuation techniques used to measure the fair value of plan assets;


·

The effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and


·

Significant concentrations of risk within plan assets.

FSP FAS 132(R)-1 is


These disclosures are effective for fiscal years ending after December 15, 2009. We do not expect the adoption of FSP FAS 132(R)-1 to have a significant effect on our financial statements.


9

8



(4)

ALLOWANCE FOR DOUBTFUL ACCOUNTS


We maintain an allowance for doubtful accounts which reflects our best estimate of potentially uncollectible trade receivables.  We regularly review our trade receivables allowances by considering such factors as historical experience, credit-worthiness, the age of the receivable balances and current economic conditions that may affect the ability to pay.

Following is a summary of receivables (in thousands):

  September 30,  December 31, 
  2009  2008 
       
Accounts receivable – customers $19,284  $24,251 
Allowance for doubtful accounts  (259)  (370)
Net accounts receivable $19,025  $23,881 


(5)OTHER COMPREHENSIVE INCOME


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

 

Three Months Ended

 

June 30,

 

2009

2008

 

 

 

 

 

Net income

$

3,105

$

5,251

Other comprehensive income (loss), net of tax:

 

 

 

 

Reclassification adjustments included in

 

 

 

 

net income (net of tax of $(6) and $(6),

 

 

 

 

respectively)

 

11

 

10

Total comprehensive income

$

3,116

$

5,261


Six Months Ended

 Three Months Ended 

June 30,

 September 30, 

2009

2008

 2009  2008 

 

 

 

 

      

Net income

$

10,069

$

10,827

 $7,166  $6,371 

Other comprehensive income (loss), net of tax:

 

 

 

 

        

Reclassification adjustments included

 

 

 

 

in net income (net of tax of $(11) and $48,

 

 

 

 

Fair value adjustment on derivatives        
designated as cash flow hedges (net of        
tax of $15 and $0, respectively)  (27)   
Reclassification adjustments included in        
net income (net of tax of $(6) and $(6),        

respectively)

 

21

 

(90)

  10   10 

Total comprehensive income

$

10,090

$

10,737

 $7,149  $6,381 



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


9


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

 

Derivatives

Employee

 

 

Designated as

Benefit

 

 

Cash Flow Hedges

Plans

Total

 

 

 

 

 

 

 

As of June 30, 2009

$

(911)

$

(417)

$

(1,328)

 

 

 

 

 

 

 

As of December 31, 2008

$

(932)

$

(417)

$

(1,349)


10

  September 30,  December 31, 
  2009  2008 
       
Derivatives designated as cash flow hedges $(928) $(932)
         
Employee benefit plans $(417) $(417)
         
Total $(1,345) $(1,349)




(5)

(6)

RELATED-PARTY TRANSACTIONS


Receivables and Payables


We have accounts receivable balances related to transactions with other BHC subsidiaries.  The balances were $2.7$2.2 million and $12.6 million as of JuneSeptember 30, 2009 and December 31, 2008, respectively.  We also have accounts payable balances related to transactions with other BHC subsidiaries.  The balances were $9.2$5.9 million and $10.4 million as of JuneSeptember 30, 2009 and December 31, 2008, respectively.

Money Pool Notes Receivable and Notes Payable  


Money Pool Notes Receivable and Notes Payable

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


Through the Utility Money Pool, we had net note payable balances and interest payable of $76.3$105.1 million and $70.2 million as of JuneSeptember 30, 2009 and December 31, 2008, respectively.  Advances under this note bear interest at 0.70 percent above the daily LIBOR rate (which equates to 1.01%0.95% at JuneSeptember 30, 2009).  Net interest expense of $0.7less than $0.1 million and $1.1 million was recorded for the three months and sixnine months ended JuneSeptember 30, 2009, respectively.  Net interest expense was less than $0.1approximately $0.4 million and $0.4 million for the three and sixnine months ended JuneSeptember 30, 2008.

2008, respectively.


Other Balances and Transactions


We also received revenues of approximately $0.2 million and $0.4$0.3 million for the three months ended JuneSeptember 30, 2009 and 2008, respectively; and $0.4$0.7 million and $0.7$1.0 million for the sixnine months ended JuneSeptember 30, 2009 and 2008, respectively, from Black Hills Wyoming for the transmission of electricity.


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

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

We received revenues of approximately $0.4 million and $0.4 million for the three months ended June 30, 2009 and 2008, respectively; and $0.7 million and $1.1 million for the six months ended June 30, 2009 and 2008, respectively, from Cheyenne Light for the sale of electricity and dispatch services.


10


We purchase coal from WRDC.  The amount purchased during the three months ended JuneSeptember 30, 2009 and 2008 was $3.2$4.2 million and $2.8$4.9 million, respectively; and $7.1$11.3 million and $5.9$10.8 million for the sixnine months ended JuneSeptember 30, 2009 and 2008.

2008, respectively.


We purchase excess power generated by Cheyenne Light.  The amount purchased during the three months and sixnine months ended JuneSeptember 30, 2009 was $2.0$1.9 million and $3.9$5.8 million, respectively and includes $0.5$0.3 million and $1.3$1.5 million for wind-generated power for the three and sixnine months ended JuneSeptember 30, 2009, respectively.  The amount purchased for the three and sixnine month periods ended JuneSeptember 30, 2008 was $1.6$1.5 million and $3.1$4.6 million, respectively.  On August 28, 2008, we entered into a contract with Cheyenne Light under which Cheyenne Light sells up to 20 MW of wind-generated, renewable energy to us until 2028.

11



In order to fuel our combustion turbine, we purchase natural gas from Enserco.  The amount purchased during the three months ended JuneSeptember 30, 2009 and 2008 was $0.5$0.9 million and $3.5$3.0 million, respectively; and $0.6$1.5 million and $3.5$6.6 million for the sixnine months ended JuneSeptember 30, 2009 and 2008, respectively.  These amounts are included in Fuel and purchased power on the accompanying Condensed Statements of Income.


In addition, we also pay the Parent for allocated corporate support service cost incurred on our behalf.  Corporate costs allocated from the Parent were $3.8 million and $3.0$2.8 million for the three months ended JuneSeptember 30, 2009 and 2008, respectively; and $7.4$11.3 million and $6.1$8.9 million for the sixnine months ended JuneSeptember 30, 2009 and 2008, respectively.


We have funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $2.0 million as of September 30, 2009 and $1.9 million as of June 30, 2009 and December 31, 2008, respectively, which is included in Other, Deferred credits and other liabilities on the accompanying Condensed Balance Sheets.  Interest on the funds accrues quarterly at an average quarterly prime rate (3.37%(3.25% at JuneSeptember 30, 2009).


(6)

(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.


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


11


The following table sets forth the projected benefit obligation as of December 31, 2008 and July 31, 2009.  The July 31, 2009 projected benefit obligation reflects the curtailment of the plan:

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

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

 

Three Months Ended

Six Months Ended

 

June 30,

June 30,

 

2009

2008

2009

2008

 

 

 

 

 

 

 

 

 

Service cost

$

292

$

279

$

584

$

558

Interest cost

 

785

 

758

 

1,570

 

1,516

Expected return on plan assets

 

(657)

 

(1,094)

 

(1,314)

 

(2,188)

Prior service cost

 

28

 

28

 

56

 

56

Net loss

 

430

 

 

860

 

 

 

 

 

 

 

 

 

 

Net periodic benefit cost

$

878

$

(29)

$

1,756

$

(58)


  Three Months Ended  Nine Months Ended 
  September 30,  September 30, 
  2009  2008  2009  2008 
             
Service cost $287  $279  $871  $837 
Interest cost  786   758   2,357   2,274 
Expected return on plan assets  (718)  (1,094)  (2,032)  (3,282)
Prior service cost  18   28   74   84 
Net loss  377      1,236    
Curtailment expense  189      189    
                 
Net periodic benefit cost (gain) $939  $(29) $2,695  $(87)

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





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

Six Months Ended

 

June 30,

June 30,

 

2009

2008

2009

2008

 

 

 

 

 

 

 

 

 

Interest cost

$

25

$

30

$

50

$

60

Net loss

 

11

 

11

 

22

 

22

 

 

 

 

 

 

 

 

 

Net periodic benefit cost

$

36

$

41

$

72

$

82


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

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


Non-pension Defined Benefit Postretirement Plans


Employees who are participants in the Postretirement Healthcare Plans (“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)ousands):

 

Three Months Ended

Six Months Ended

 

June 30,

June 30,

 

2009

2008

2009

2008

 

 

 

 

 

 

 

 

 

Service cost

$

54

$

52

$

108

$

104

Interest cost

 

111

 

104

 

222

 

208

Net transition obligation

 

13

 

13

 

26

 

26

 

 

 

 

 

 

 

 

 

Net periodic benefit cost

$

178

$

169

$

356

$

338


  Three Months Ended  Nine Months Ended 
  September 30,  September 30, 
  2009  2008  2009  2008 
             
Service cost $54  $52  $162  $156 
Interest cost  111   104   333   312 
Net transition obligation  13   13   39   39 
                 
Net periodic benefit cost $178  $169  $534  $507 

We anticipate that we will make contributions to the Healthcare Plan for the 2009 fiscal year of approximately $0.2 million.  Contributions are expected to be made in the form of benefit payments.


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 $0.1 million.






(7)

(8)

FAIR VALUE OF FINANCIAL INSTRUMENTS


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

 

2009

 

Carrying Amount

Fair Value

 

 

 

 

 

Cash and cash equivalents

$

626

$

626

Long-term debt

$

149,225

$

157,081


  2009 
  Carrying Amount  Fair Value 
       
Cash and cash equivalents $1,150  $1,150 
Derivative financial instruments – liabilities $42  $42 
Long-term debt, including current maturities $149,209  $171,273 

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


Cash and Cash Equivalents


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


Derivative Financial Instruments

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

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.


(8)

(9)

RISK MANAGEMENT ACTIVITIES AND DERIVATIVES


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

14


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

  Natural Gas Swaps 
    
Notional*  232,500 
Maximum terms in months  12 
Current derivative asset $ 
Non-current derivative asset $ 
Current derivative liability $42 
Non-current derivative liability $ 
Pre-tax accumulated other comprehensive    
income (loss) $(42)
Unrealized gain/(loss) $ 
___________________________
*Gas in MMBtus.

Additionally, we engage in activities to manage risk associated with changes in interest rates.  We occasionally enter into floating-to-fixed interest rate swap agreements to minimize our exposure to interest rate fluctuations associated with our floating rate debt obligations.  These swaps were designated as cash flow hedges in accordance with generally accepted accounting for derivatives, and accordingly the resulting gain or loss is carried in Accumulated other comprehensive loss on the accompanying Condensed Balance Sheets and amortized over the life of the related debt.  For the nine months ended September 30, 2009 and 2008, respectively, we amortized less than $0.1 million from Accumulated other comprehensive loss to Interest expense related to a settled interest rate swap designated as a cash flow hedge.

(10)COMMITMENTS AND CONTINGENCIES


Legal Proceedings


We are subject to various legal proceedings, claims and litigation as described in Note 11 of the Notes to our Financial Statements in our 2008 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 sixnine months of 2009.


In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations.  We believe the amounts provided in our 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 JuneSeptember 30, 2009, cannot be reasonably determined and could have a material adverse effect on our results of operations, financial position or cash flows.



15


Extension of Long-Term Power Sales Agreement with MEAN


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


2009-2017

20 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II

2018-2019

15 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

2020-2021

12 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II

2022-2023

10 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

14



Partial Sale of Wygen III to MDU


On April 9, 2009, we sold to MDU a 25% ownership interest in our Wygen III generation facility currently under construction.  At closing, MDU made a payment to us for its 25% share of the costs to date on the ongoing construction of the facility.   Proceeds of $32.8 million were received.  MDU will continue to reimburse us for its 25% of the total costs paid to complete the project.  We will retain responsibility for operations of the facility with a life-of-plant site lease and agreements with MDU for operations and coal supply.  In conjunction with the sales transaction, we also modified aour 2004 power purchase agreementPPA with MDU under which we supplied MDU with 74 MW of capacity and energy through 2016.

  The PPA with MDU now provides that once online, the first 25 MW of MDU’s required 74 MW will be supplied from its ownership interest in Wygen III.  During periods of reduced production at Wygen III, or during periods when Wygen III is offline, we will provide MDU with its 25 MW from our other generation facilities or system purchases.

(11)SUBSEQUENT EVENT

Bond Issuance

On October 27, 2009, we completed a $180 million first mortgage bond issuance.  The bonds were priced at 99.931% of par and a reoffer yield of 6.13%.  The bonds mature November 1, 2039 and carry an annual interest rate of 6.125%, which will be paid semi-annually.  We received proceeds of $178.3 million net of underwriting fees which were used to repay intercompany borrowings from BHC, primarily incurred to fund the construction of Wygen III.  Estimated deferred finance costs of $1.9 million were capitalized and will be amortized over the life of the bonds.

Renewable Energy Contracts

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

16



ITEM 2.

RESULTS OF OPERATIONS

 

Three Months Ended

Six Months Ended

 

June 30,

June 30,

 

2009

2008

2009

2008

 

(in thousands)

 

 

 

 

 

 

 

 

 

Revenue

$

46,836

$

57,978

$

101,294

$

115,610

Fuel and purchased power

 

19,753

 

28,226

 

42,515

 

55,725

Gross margin

 

27,083

 

29,752

 

58,779

 

59,885

 

 

 

 

 

 

 

 

 

Operating expenses

 

22,077

 

20,482

 

43,068

 

40,023

Operating income

$

5,006

$

9,270

$

15,711

$

19,862

 

 

 

 

 

 

 

 

 

Net income

$

3,105

$

5,251

$

10,069

$

10,827


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

The following tables provide certain operating statistics:

 

Electric Revenue

 

(in thousands)

 

 

 

Three Months Ended June 30,

Six Months Ended June 30,

 

 

Percentage

 

 

Percentage

 

Customer Base

2009

Change

2008

2009

Change

2008

 

 

 

 

 

 

 

 

 

 

Commercial

$

14,551

11%

$

13,063

$

29,194

10%

$

26,535

Residential

 

10,391

4

 

10,002

 

24,672

7

 

22,980

Industrial

 

5,030

(9)

 

5,542

 

9,780

(10)

 

10,838

Municipal sales

 

660

3

 

639

 

1,296

3

 

1,264

Total retail sales

 

30,632

5

 

29,246

 

64,942

5

 

61,617

Contract wholesale

 

5,631

(10)

 

6,270

 

12,184

(8)

 

13,202

Wholesale off system

 

5,765

(70)

 

19,238

 

14,985

(56)

 

34,335

Total electric sales

 

42,028

(23)

 

54,754

 

92,111

(16)

 

109,154

Other revenue

 

4,808

49

 

3,224

 

9,183

42

 

6,456

Total revenue

$

46,836

(19)%

$

57,978

$

101,294

(12)%

$

115,610


15

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


17

 

Megawatt Hours Sold

 

 

 

Three Months Ended June 30,

Six Months Ended June 30,

 

 

Percentage

 

 

Percentage

 

Customer Base

2009

Change

2008

2009

Change

2008

 

 

 

 

 

 

 

 

 

 

Commercial

 

169,955

5%

 

162,313

 

345,211

3%

 

335,772

Residential

 

119,123

4

 

114,106

 

282,599

2

 

277,140

Industrial

 

93,984

(14)

 

109,028

 

179,968

(15)

 

211,697

Municipal sales

 

7,567

(1)

 

7,637

 

15,662

(1)

 

15,845

Total retail sales

 

390,629

(1)

 

393,084

 

823,440

(2)

 

840,454

Contract wholesale

 

143,248

(9)

 

156,965

 

311,927

(5)

 

328,585

Wholesale off system

 

230,617

(19)

 

283,770

 

474,403

(7)

 

511,511

Total electric sales

 

764,494

(8)

 

833,819

 

1,609,770

(4)

 

1,680,550

Losses and company

 

 

 

 

 

 

 

 

 

 

use

 

41,104

78

 

23,044

 

67,293

119

 

30,776

Total energy

 

805,598

(6)%

 

856,863

 

1,677,063

(2)%

 

1,711,326


 

Electric Utility Power Plant Availability

 

 

 

Three Months Ended June 30,

Six Months Ended June 30,

 

2009

2008

2009

2008

 

 

 

 

 

Coal-fired plants

77.4%*

75.7%**

87.0%*

84.0%**

Other plants

92.2%

85.6%

95.8%

91.0%

Total availability

83.9%

80.6%

90.8%

87.5%


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


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

*

Reflects major outages at Neil Simpson I and Neil Simpson II coal-fired plants.  The Neil Simpson I outage was scheduled for 31 days and was subsequently extended to 39 days.  The Neil Simpson II outage was scheduled for 18 days and was subsequently extended to 27 days.  The outages were extended on both units for major rotor damage discovered during the overhauls.

**

Reflects major maintenance outages at our Ben French, Neil Simpson I and Osage coal-fired plants.  The Ben French outage was scheduled for 25 days and was subsequently extended to accelerate major maintenance originally scheduled for 2009.  The actual outage was 88 days and resulted in the plant’s output being restored to its full rated capacity.  The Osage outage was originally scheduled for approximately 10 days and lasted 52 days as a result of additional unplanned required maintenance.  All the plants were online by the end of the second quarter of 2008.

 

Megawatt Hours Generated and Purchased

 

 

 

Three Months Ended June 30,

Six Months Ended June 30,

 

 

Percentage

 

 

Percentage

 

Resources

2009

Change

2008

2009

Change

2008

 

 

 

 

 

 

 

Coal

348,657

(9)%

384,748

786,208

(4)%

817,630

Gas

5,750

19

4,831

6,825

(84)

41,831

 

354,407

(9)

389,579

793,033

(8)

859,461

 

 

 

 

 

 

 

MWhs purchased

451,191

(3)

467,284

884,030

4

851,865

Total resources

805,598

(6)%

856,863

1,677,063

(2)%

1,711,326


16


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


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Heating and Cooling Degree Days

 

 

 

Three Months Ended

Six Months Ended

 

June 30,

June 30,

 

2009

2008

2009

2008

Heating and cooling degree days:

 

 

 

 

Actual

 

 

 

 

Heating degree days

1,273

1,230

4,527

4,591

Cooling degree days

51

29

51

29

 

 

 

 

 

Variance from normal

 

 

 

 

Heating degree days

28%

23%

5%

7%

Cooling degree days

(50)%

(71)%

(50)%

(71)%



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

Three Months Ended JuneSeptember 30, 2009 Compared to Three Months Ended JuneSeptember 30, 2008.  Net income decreased $2.1increased $0.8 million from the prior period primarily due to the following:


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

·A $2.8$0.3 million increase in retail margins primarily due to lower purchase power and fuel costs partially offset by lower MWh sold due to lower industrial sales; and

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

Partially offsetting the increases were the following:

·A $2.2 million decrease in margins from off-system sales reflecting the lower margins available in the industry’s current low energy price environment;

and

·

A $1.8 million decrease in retail margins primarily due to outages at Neil Simpson I, Neil Simpson II and Wyodak, partially offset by a full quarter of operations at Ben French which had outages in the second quarter of 2008; and

     A $1.5$0.7 million increase in employee benefit costs.


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

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

Partially offsetting the decreases were the following:

·A $2.8 million increase in employee benefit costs.

Partially offsetting the decreases were the following:

·

Increased gross margins of $1.9$4.5 million primarily due to an increase in transmission rates effective January 1, 2009; and


·

Increased AFUDC of $0.9$4.0 million primarily due to construction of Wygen III in 2009.

Six Months Ended June 30, 2009 Compared to Six Months Ended June 30, 2008. Net income decreased $0.8 million from the prior period primarily due to the following:

     A $3.8 million decrease in margins from off-system sales reflecting the lower margins available to the industry’s current low energy price environment; and

     A $2.3 million increase in employee benefit costs.

Partially offsetting the decreases were the following:

     Increased gross margins of $3.0 million due to an increase in transmission rates effective January 1, 2009; and

     Increased AFUDC of $2.5 million primarily due to construction of Wygen III in 2009.



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19


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


In March 2008, we received final regulatory approval for construction of Wygen III.  Construction began immediately and the 110 MW coal-fired base load electric generating facility is expected to be completed by June, 2010.  The expected cost of construction is approximately $255 million, which includes estimates for AFUDC.  Our 2004 Purchase Power AgreementPPA with MDU included an option for MDU to purchase an ownership interest in Wygen III.  MDU exercised this option, and under an agreement entered into in April 2009, we will retain an undivided ownership of 75% of the facility with MDU owning the remaining 25%.  At closing, MDU reimbursed us for its 25%, or $32.8 million, of the total costs incurred to date on the ongoing construction of the facility.  We will retain responsibility for operations of the facility with a life-of-plant site lease and agreements with MDU for operations and coal supply.  In conjunction with the sales transaction, we also modified our 2004 power purchase agreementPPA with MDU under which we supplied MDU with 74 MW of capacity and energy through 2016.

  The PPA with MDU now provides that once online, the first 25 MW of MDU’s required 74 MW will be supplied from its ownership interest in Wygen III.  During periods of reduced production at Wygen III, or during periods when Wygen III is offline, we will provide MDU with such 25 MW from our other generation facilities or system purchases.


Extension of Long-Term Power Sales Agreement with MEAN


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


2009-2017

20 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II

2018-2019

15 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

2020-2021

12 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II

2022-2023

10 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II


Purchase Power Agreement with MEAN


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


Rate Case Filed with the SDPUC

On September 30, 2009, we filed a rate case with the SDPUC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred during the past four years.  We are seeking a 26.6%, increase in annual utility revenues and we anticipate that the new rates will be effective for our South Dakota customers on or around April 1, 2010.  The proposed rate increase is subject to approval by the SDPUC.


20


Rate Case Filed with the WPSC

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

Financing Transactions and Short-Term Liquidity

Future


Financing Plans

We anticipate issuing


In October 2009, we completed the issuance of a long-term first mortgage bond of approximately $180 million.  The offering is expected to be completed in the Fall of 2009; proceedsProceeds of the transaction will be used to fund capital expenditures, including construction costs related to the Wygen III facility, and to fund the approximate $30 million maturity of our Series AC, 8.06% first mortgage bonds due in February 2010.


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 JuneSeptember 30, 2009, our first mortgage bonds credit ratings, as assessed by the three major credit rating agencies, were as follows:


Rating Agency

Rating

Outlook

Moody’s

Baa1

A3

Stable

S&P

BBB

Stable

Fitch

A-

Stable

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

18




21


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 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 2008 Annual Report on Form 10-K, in Item 1A. of Part II of this Quarterly Report on Form 10-Q filed with the SEC, and the following:


·

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


·

Our ability to access the bank loan and debt capital markets depends on market conditions beyond our control.  If the credit markets remain tight and do not improve, we may not be able to permanently refinance some short-term debt and fund our power generation projects on reasonable terms, if at all;


·

Our ability to raise capital in the debt capital markets depends upon our financial condition and credit ratings, among other things.  If our financial condition deteriorates unexpectedly, or our credit ratings are lowered, we may not be able to refinance some short-term debt and fund our power generation projects on reasonable terms, if at all;


·

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


·

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


·

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


·

Changes in business and financial reporting practices arising from the enactment of the Energy Policy Act of 2005;


·

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


19

22



·

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


·

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


·

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


·

Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment;


·

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 and market changes, including the impact of consolidations and changes in competition;


·

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


·

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


·

The outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements;


·

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


·

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


·

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


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


20

23



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 JuneSeptember 30, 2009.  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 JuneSeptember 30, 2009 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

21



24


BLACK HILLS POWER, INC.


Part II – Other Information


Item 1.

Legal Proceedings


For information regarding legal proceedings, see Note 11 of Notes to Financial Statements in Item 8 of our 2008 Annual Report on Form 10-K and Note 8 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 8 is incorporated by reference into this item.


Item 1A.

Item 1A.                      Risk Factors


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


Federal and state laws concerning climate change and air emissions, including emission reduction mandates and renewable energy portfolio standards, may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.

We own and operate regulated fossil-fuel generating plants in South Dakota and Wyoming. We are constructing another fossil-fuel generating plant in Wyoming. Air emissions of fossil-fuel generating plants are subject to federal, state and tribal regulation. Recent developments under federal and state laws and regulation governing air emissions from fossil-fuel generating plants will likely result in more stringent emission limitations.


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


22

25


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

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


More stringent GHG emissions limitations or other energy efficiency requirements, however, could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, and the closure of certain generating facilities. To the extent our regulated fossil-fuel generating plants are included in rate base, we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by our non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.



26


We own electric utilities that serve customers in Montana, South Dakota and Wyoming. Montana has adopted mandatory renewable portfolio standards that require electric utilities to supply a minimum percentage of the power delivered to customers from renewable resources (e.g., wind, solar, biomass) by a certain date in the future. These renewable energy portfolio standards have increased the power supply costs of our electric operations. If this state increases its renewable energy portfolio standards, or if similar standards are imposed by the other states in which we operate electric utilities, our power supply costs will further increase. Although we will seek to recover these higher costs in rates, any unrecovered costs could have a material negative impact on our results of operations and financial condition.

23



27


Item 6.

Exhibits



Exhibit 4Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon, as Trustee to Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (previously filed as Exhibit 4.21 to the Company’s Post-Effective Amendment No. 2 to the Registration Statement on Form S-3 (File No. 333-150669) and incorporated by reference herein).
Exhibit 31.1

Certification of Chief Executive Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

Exhibit 31.2

Certification of Chief Financial Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

Exhibit 32.1

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

Exhibit 32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

24



28


BLACK HILLS POWER, INC.


Signatures

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:  August 14,November 12, 2009

25



29


EXHIBIT INDEX



Exhibit Number

Description

Exhibit 4

Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon, as Trustee to Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (previously filed as Exhibit 4.21 to the Company’s Post-Effective Amendment No. 2 to the Registration Statement on Form S-3 (File No. 333-150669) and incorporated by reference herein).

Exhibit 31.1

Certification of Chief Executive Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

Exhibit 31.2

Certification of Chief Financial Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

Exhibit 32.1

Certification of Chief Executive Officer  pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

Exhibit 32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

26



30