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July 21, 2005

Mr. Jim Allegretto

Sr. Assistant Chief Accountant

United States Securities and Exchange Commission

100 F Street, NE

Washington, D.C. 20549-3651

            Re:

            Black Hills Corporation

Form 10-K for the year ended December 31, 2004

Filed March 16, 2005

File No. 1-31303

Black Hills Power, Inc.

Form 10-K for the year ended December 31, 2004

Filed March 30, 2005

File No. 1-7978

Dear Mr. Allegretto:

The purpose of this letter is to respond to your comments as set forth in your letter of June 29, 2005.  The headings used herein are the same as those set forth in your letter.  For ease of reference, we have set forth your comment before each response.

In connection with our response to your comments, we acknowledge the following:

            •

            the Company is responsible for the adequacy and accuracy of the disclosure in the filing;

            •

            staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filings; and

            •

            the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Jim Allegretto

July 21, 2005

Page 2

FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2004

General

Comment No. 1:

Where a comment below requests additional disclosures or other revisions to be made, please include them in your future filings including interim periods where applicable.  In our interest to reduce the volume of comments, we have not addressed Black Hills Power, Inc. with a separate comment if applicable to their facts and circumstances.  Please note that if you agree to a revision, we would also expect a concurrent change be made in the Black Hills Power, Inc. financial statements and related disclosures.  Please confirm to us your agreement with this objective.

The Company agrees that any revisions it agrees to make in its future filings will also be provided in the future filings of Black Hills Power, Inc., if applicable to their facts and circumstances.

Items 7 and 7A Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk

Oil and Gas, page 51

Comment No. 2:

We note that your lease operating expenses and depletion per Mcfe sold has changed substantially in the periods provided.  Please expand to discuss the economic reasons that underlie these variances.

The following table is provided for reference in the following discussion:

            2002

            2003

            2004

            E. Blanco LOE/Mcfe

            N/A

            $1.41

            $1.15

            All Other Properties LOE/Mcfe

            $0.69

            $0.75

            $0.85

            TOTAL LOE/Mcfe

            $0.69

            $0.95

            $0.97

            Total Depletion/Mcfe

            $0.98

            $0.83

            $0.92

With the acquisition of Mallon Resources Corporation on March 10, 2003, Black Hills Exploration and Production (BHEP) acquired significant gathering, treating and compression facilities associated with the East Blanco field.  The operating costs of these facilities are allocated to the East Blanco properties as LOE and represented $0.80 and $0.65 of East Blanco’s LOE per Mcfe for 2003 and 2004, respectively.  In addition, BHEP initiated efforts throughout 2003 and into 2004 to remediate properties that had been neglected prior to the acquisition.  These activities contributed to East Blanco’s total $1.41 and $1.15 LOE per Mcfe for 2003 and 2004, respectively.  LOE per Mcfe in the East Blanco field in 2003 was $1.41 as compared to $0.75 for our other properties, resulting in an increase in the Company’s overall average LOE per Mcfe.

Jim Allegretto

July 21, 2005

Page 3

The nominal $0.02 increase in LOE per Mcfe from 2003 to 2004 was attributable to increased activity in our Wyoming oil field, offset by a decline in LOE per Mcfe at East Blanco due to increases in production and the recovery of the fixed gathering, processing and compression costs over a larger pool of production.

The decrease in Depletion per Mcfe from 2002 to 2003 is also attributable to the Mallon acquisition.  Most of this decrease is due to the fact that the reserves we recorded pursuant to the acquisition have a lower cost per Mcfe than our average cost in 2002, thus lowering our average depletion cost per Mcfe.  The increase between 2003 and 2004 is a function of increases in average development costs per Mcfe as we develop the field.

We will provide more robust disclosure related to these activities, to the extent meaningful, in our future filings.

Electric Utility, page 53

Comment No. 3:

Your electric utility segment has a trend of decreasing operating and net income over the 3 year period.  Your discussion should provide greater information on the reasons underlying such a trend.  For example, we note rising purchased power costs, offset by decreased fuel costs, were responsible for much of the 2004 earnings decline.  It is implied that rising natural gas prices made it more economical to purchase other fuel source power and cut back on your gas-fired generation.  If this was the case, you may want to make it clearer in your discussion.  If not the case, then expand to explain the business reasons for your increased purchased power costs versus lower fuel costs.  Furthermore the reasons for each of the increasing components of utility operating expenses should be discussed and quantified.

In identifying the trending decrease in our utility segment’s operating and net income over the 3 year period presented, the Company cites its disclosures on pages 20, 37, 40 and 53 of the 2004 Black Hills Corporation 10-K.  On pages 20 and 40 we disclose our utility’s rate freeze, which has been in place since 1995.  This discloses that our revenues from our system sales are generally stable, as our service territory has historically had only nominal annual load growth.  Our wholesale off-system sales are a significant factor in causing variability in our utility revenues.  The related costs of these sales are a primary driver in the increased purchased power and fuel costs.  While we believe we have disclosed our intent to attempt to capitalize on off-system sales opportunities, we also have included in our “Industry Overview” on page 37 our view of the power markets.  On page 53 we
provide our disclosure to describe and quantify our utility’s increasing operating cost structure.  While we have attempted to provide clarity into these items in our filings, we realize the discussion is not all in one place within the filing.  In future filings, we will strive to provide additional clarity on these issues to the extent possible and centralize the discussion in the Managements’ Discussion and Analysis.

In regard to the Staff’s inquiry into fluctuations in purchased power and fuel costs, we believe the disclosure included on page 53 clarifies the economic decision to purchase power from the market rather than to run our gas-fired turbines.

Jim Allegretto

July 21, 2005

Page 4

Comment No. 4:

You indicate on page 13 that your customer base includes commercial, residential, contract wholesale, wholesale off-system, industrial, municipal, and other customers.  Please provide volume data and revenue amounts segregated by components of your customer base.

            Revenue

            (in thousands)

            Customer Base

            2004

            %

            2003

            %

            2002

            Commercial

            $46,791

            -2%

            $47,777

            2%

            $46,673

            Residential

            36,536

            -3%

            37,716

            2%

            37,111

            Industrial

            19,796

            1%

            19,589

            -4%

            20,407

            Municipal Sales & Other

            2,200

            5%

            2,102

            2%

            2,070

            Contract Wholesale

            22,720

            6%

            21,451

            -20%

            26,879

            Wholesale Off-System

            38,228

            13%

            33,743

            53%

            22,083

            $166,271

            2%

            $162,378

            5%

            $155,223

            Megawatt Hours

            Customer Base

            2004

            %

            2003

            %

            2002

            Commercial

            627,326

            -2%

            641,779

            3%

            620,665

            Residential

            447,166

            -3%

            463,290

            2%

            454,201

            Industrial

            406,209

            0%

            404,341

            -2%

            413,930

            Municipal Sales & Other

            28,934

            5%

            27,426

            2%

            26,839

            Contract Wholesale

            614,700

            5%

            582,743

            -23%

            757,050

            Wholesale Off-System

            926,461

            15%

            805,946

            20%

            673,052

            3,050,796

            4%

            2,925,525

            -1%

            2,945,737

We will include the information provided above in future filings, along with an explanation of meaningful changes in volume and revenue derived from each component of our customer base.

Comment No. 5:

We note that you indicate degree days in 2004 are 9 percent below normal and 11 percent below the prior year. We assume you mean heating degree days. While such information is useful, we believe your disclosure could be enhanced by providing an analysis of the class of customers who are more sensitive to weather trends in tying the numerical change in degree days with the related volume change for such customers. To the extent your residential customer base does not use electric resistance to heat their homes; you may want to make this clear. In addition since your peak load occurs at approximately the same volume for summer versus winter, you may want to clarify whether you mean heating degree days or cooling degree days.

In future filings, we will enhance our disclosures to clarify meaningful impacts of weather trends on the different components of our utility customer base.  This enhanced disclosure will include any necessary differentiation between heating and cooling degree days.

Jim Allegretto

July 21, 2005

Page 5

Note 1.  Business Description and Summary of Significant Accounting Policies

Material, Supplies and Fuel. page 86

Comment No. 6:

Please tell us how you currently account for the stripping costs associated with your mining activities. To the extent that such costs are capitalized as a component of inventory, please tell us how often your inventory turns. Additionally, please tell us how the adoption of EITF 04-06 will impact your financial statements.

We currently account for stripping costs by recording a deferred asset.  This asset is amortized into earnings as a cost of sales when coal is sold using a proportional performance ratio.  This ratio is based on historical and forecasted stripping costs and the actual and estimated tons of coal uncovered, resulting in a stripping cost rate applied to each ton sold.

We have not capitalized stripping costs as a component of inventory as our mine does not stockpile an inventory of coal as it is extracted.  Our mine’s primary customers are mine-mouth power generation facilities owned by our regulated and non-regulated subsidiaries and PacifiCorp.  As the coal is extracted it is placed on a conveyor belt that delivers the coal to these power plants.  Although we don’t inventory coal, it is useful to note that our mine typically operates with uncovered coal reserves equaling approximately 12 months of production.

The adoption of EITF 04-06 will result in the Company adjusting the methodology used in its ratio for developing its stripping cost rate.  The new rate will be generated on an annual basis based on the stripping costs incurred for the period and the related tons of coal uncovered.  Based on management’s evaluation of EITF 04-06, we do not believe that its adoption will have a material impact on our consolidated financial statements.

.

Comment No. 7:

Please disclose the aggregate transaction gain or loss recorded in your consolidated statements of income for the three years ended December 31, 2004. Please refer to paragraphs 15 and 30 of SFAS 52. Please explain your basis in GAAP, practice or promulgated, of classifying such items in revenues. If significant, please disclose any exchange rate changes subsequent to year-end and its effects on unsettled balances related to foreign currency transactions. Please refer to paragraph 32 of SFAS 52.

As calculated in accordance with paragraph 15 of SFAS 52, our aggregate transaction gains or losses recorded in the consolidated statements of income for the three years ended December 31, 2004 are:

            2004:

            pre-tax loss of

            $

            1,412,189

            2003:

            pre-tax income of

            $

            676,523

            2002:

            pre-tax income of

            $

            24,546

Jim Allegretto

July 21, 2005

Page 6

In explaining why the transaction gains and losses are recorded in operating revenues on the income statement and were not quantified in our 10-K disclosures as required by paragraph 30 of SFAS 52, it is important to note that these transactions were part of our gas marketing subsidiary’s operations.  These operations meet the GAAP definition of an “energy trading activity.”  As required by EITF 02-03, we recorded gains and losses from “energy trading activities” on a net basis in the income statement.  This includes the contracts that generated the foreign currency transaction gains/losses.  We haven’t quantified the foreign currency gain/loss in our disclosures as in the presentation they are netted with gains/losses from other energy trading contracts.  Since our business strategy employs limited speculative positions, generally the foreign currency transaction gain/loss is
offset by the gain/loss on a contract used to hedge (not designated as a hedge under the provisions of SFAS 133) the foreign currency exposure, or by being “long” or “short” in the foreign currency.  Therefore, quantifying the foreign currency gain/loss as provided above could confuse or mislead the reader when the impact from our total exposure to foreign currency was not significant to the consolidated financial statements.

Paragraph 32 of SFAS 52 requires “...disclosure of the rate change and its effect on unsettled balances pertaining to foreign currency transactions, if significant.....”  The changes in the U.S./Canadian dollar exchange rate subsequent to year end did not result in a significant impact to the Company and therefore, we believe, did not require disclosure.

Oil and Gas Operations, page 87

Comment No. 8:

We note that you account for your oil and gas activities under the full cost method and are subject to a ceiling test. You maintain a portfolio of swaps to hedge a portion of your crude oil and natural gas production. These derivative transactions are accounted for as cash flow hedges. Please tell us if your computation of the limitation of capitalized costs includes the impact of the aforementioned cash flow hedges. Please refer to SAB Topic 12:  D(3)(b).

In the course of preparing our response to your Comment 8, we determined that the “ceiling test” calculation for 2004 did not include the present value impac