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

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(unaudited)

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)

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 the Company’sour 2008 Annual Report on Form 10-K)

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, 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 March 31,June 30, 2009, December 31, 2008 and March 31,June 30, 2008 financial information and are of a normal recurring nature. The results of operations for the three and six months ended MarchJune 30, 2009 and our financial condition as of June 30, 2009 and December 31, 2009,2008 are not necessarily indicative of the results of operations and financial condition to be expected as of or for the full year.any other period.

SFAS 157

During September 2006, the 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 for financial measurements. As permitted by FSP FAS 157-2, we deferred adoption for non-financial assets and liabilities measured at fair value on a non-recurring basis until January 1, 2009. SFAS 157 also requires new disclosures regarding the level of pricing observability associated with instruments carried 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.

SFAS 161

In March 2008, the FASB issued SFAS 161 which requires enhanced disclosures about how 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.

At March 31,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 threesix months ended March 31,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.

FSP FAS 157-4SFAS 165

In AprilMay 2009, the FASB approved FSP FAS 157-4 effectiveissued SFAS 165, which establishes general standards of accounting for interim and annual periods endingdisclosures 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. This FSP amends FAS 157 to address inactive markets. This FSP includes a two step model with the first step determining whether factors exist that indicate a market for an asset is not active. If step one results in the conclusion that there is not an active market, step two evaluates whether the quoted price is not associated with a distressed transaction. Additional disclosures will be required. We do not anticipate that the adoption of FSP FAS 157-4 will have an impact on our operating results, financial position or cash flows.

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 will requirerequires public companies to provide more frequent disclosures ofabout the fair value for public companies.of their financial instruments. These disclosures are included in Note 7.

SFAS 167

In June 2009, the FASB issued SFAS 167 which is a revision to FASB Interpretation 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 disclosures.financial condition, results of operations, and cash flows.

SFAS 168

On July 1, 2009, the FASB Accounting Standards Codification^TM will become 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 supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become 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 FAS 132(R)-1

During December 2008, the FASB issued FSP FAS 132(R)-1, which 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:

FSP FAS 132(R)-1 is 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.

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

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

Receivables and Payables

We have accounts receivable balances related to transactions with other BHC subsidiaries. The balances were $2.9$2.7 million and $12.6 million as of March 31,June 30, 2009 and December 31, 2008, respectively. We also have accounts payable balances related to transactions with other BHC subsidiaries. The balances were $4.7$9.2 million and $10.4 million as of March 31,June 30, 2009 and December 31, 2008, respectively.

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 $85.7$76.3 million and $70.2 million as of March 31,June 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 1.2%1.01% at March 31,June 30, 2009). Net interest expense of $0.4$0.7 million and $1.1 million was recorded for the three months and six months ended March 31,June 30, 2009, and netrespectively. Net interest income ofexpense was less than $0.1 million for the three and six months ended March 31,June 30, 2008.

Other Balances and Transactions

We also received revenues of approximately $0.2 million and $0.3$0.4 million for the three months ended March 31,June 30, 2009 and 2008, respectively; and $0.4 million and $0.7 million for the six months ended June 30, 2009 and 2008, respectively, from Black Hills Wyoming for the transmission of electricity.

We recorded revenues of $0.2 million for the threesix months ended March 31,June 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 $0.3$0.4 million and $0.7$0.4 million for the three months ended March 31,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.

We purchase coal from WRDC. The amount purchased during the three months ended March 31,June 30, 2009 and 2008 was $3.9$3.2 million and $3.1$2.8 million, respectively.respectively; and $7.1 million and $5.9 million for the six months ended June 30, 2009 and 2008.

We purchase excess power generated by Cheyenne Light. The amount purchased during the three months and six months ended March 31,June 30, 2009 was $2.0 million including $0.8and $3.9 million, respectively and includes $0.5 million and $1.3 million for wind-generated power and $1.3 million for the three and six months ended March 31, 2008.June 30, 2009, respectively. The amount purchased for the three and six month periods ended June 30, 2008 was $1.6 million and $3.1 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.

In order to fuel our combustion turbine, we purchase natural gas from Enserco. The amount purchased during the three months ended March 31,June 30, 2009 and 2008 was $0.1$0.5 million and less than $0.1$3.5 million, respectively; and $0.6 million and $3.5 million for the six months ended June 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 $3.6$3.8 million and $3.1$3.0 million for the three months ended March 31,June 30, 2009 and 2008, respectively; and $7.4 million and $6.1 million for the six months ended June 30, 2009 and 2008, respectively.

We have funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $1.9 million as of March 31,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 (4.52%(3.37% at March 31,June 30, 2009).

Defined Benefit Pension Plan

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

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

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 (Supplemental Plans)(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):

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)(“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):

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.

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

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.

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.

Legal Proceedings

We are subject to various legal proceedings, claims and litigation as described in Note 11 of the Notes to 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 threesix months of 2009.

On April 9, 2009,In the normal course of business, we sold a 25% ownership interestare subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations.  We believe the amounts provided in our Wygen III generation facility to MDU. At closing, MDU made a payment to us for its 25% sharefinancial 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, to dateif any, that may be incurred in excess of those amounts provided as of June 30, 2009, cannot be reasonably determined and could have a material adverse effect on the ongoing constructionour results of the facility. MDU will continue to reimburse us for its 25% of the total costs paid to complete the project. In conjunction with the sales transaction, we also modified a 2004 power purchase agreement under which we supplied MDU with 74 MW of capacity and energy through 2016.operations, financial position or cash flows.

Extension of Long-Term Power Sales Agreement with MEAN

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

Sale 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. In conjunction with the sales transaction, we also modified a 2004 power purchase agreement with MDU under which we supplied MDU with 74 MW of capacity and energy through 2016.

The following tables provide certain operating statistics:

___________________________

Three Months Ended March 31,June 30, 2009 Compared to Three Months Ended March 31,June 30, 2008. Net income increased $1.4decreased $2.1 million from the prior period primarily due to the following:

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:

Wygen III Power Plant Project and Sale 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 inby June, 2010. The expected cost of construction is approximately $255 million, which includes estimates for AFUDC. AOur 2004 agreementPurchase Power Agreement with MDU included an option for MDU to purchase an ownership interest in Wygen III. In April 2009, MDU exercised this option, and we sold a 25% ownership interestunder an agreement entered into in Wygen III to MDU. WeApril 2009, we will retain an undivided ownership of 75% of the facility’s capacityfacility 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 agreement with MDU under which we supplied MDU with 74 MW of capacity and energy through 2016.

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:

Purchase Power Agreement with MEAN

In July 2009, we entered into a five-year PPA with MEAN. The contract commences the month following the commercial operations of 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.

Financing Transactions and Short-Term Liquidity

Future Financing Plans

We anticipate issuing a long-term first mortgage bond of approximately $180 million. The offering is expected to be completed in the Fall of 2009; proceeds of the transaction will be used to fund capital expenditures, including construction costs related to the Wygen III facility, and to fund the approximate $30 million maturity 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 June 30, 2009, our first mortgage bonds credit ratings, as assessed by the three major credit rating agencies, were as follows:

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

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. However, whether actual results and developments will conform to our expectations and predictions is subject to a number ofForward-looking statements involve risks and uncertainties, that, amongand 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 things,similar terminology. There are various factors that could cause actual results to differ materially from those contained insuggested by the forward-looking statements; accordingly, there can be no assurances that such indicated results will be realized. The forward-looking statements includinginclude the factors discussed above, the risk factors described in Item 1A of our 2008 Annual Report on Form 10-K, and in Item 1A. of Part II of this Quarterly Report on Form 10-Q filed with the SEC, and the following:

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.

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of March 31,June 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 March 31,June 30, 2009 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

BLACK HILLS POWER, INC.

Part II – Other Information

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 78 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 78 is incorporated by reference into this item.

There have been no material changes inExcept to the extent updated or described below, our Risk Factors from those reportedare documented in Item 1A.IA. of Part I ofin our 2008 Annual Report on Form 10-K filed withfor the Securitiesyear ended December 31, 2008.

Federal and Exchange Commission.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.

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

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

We own electric utilities that serve customers in 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.