SecProbe.io

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 February 5, 2026

 VIA EDGAR TRANSMISSION

 Division of Corporate Finance

 United States Securities and Exchange Commission

 100 F Street, N.E.

 Washington, D.C. 20549-6010

 Re:
 Black Hills Corporation

 Registration Statement on Form S-4 (Registration No. 333-293105)

 Request for Acceleration of Effective Date

 Ladies and gentlemen:

 In accordance with Rule 461
under the Securities Act of 1933, as amended (the "Act"), Black Hills Corporation (the "Company") requests that the
Securities and Exchange Commission take appropriate action to cause the Registration Statement on Form S-4 (File No. 333-293105) to become
effective on February 6, 2026 at 4:00 p.m., Eastern Time, or as soon as practicable thereafter, or
at such later time as the Company or its counsel may request via telephone call to the staff. This letter and request for acceleration of effectiveness hereby supersedes our acceleration request filed with the Commission on February
4, 2026. In making this acceleration request, the
Company acknowledges that it is aware of its obligations under the Act.

 Please contact Charles Lange
of Faegre Drinker Biddle & Reath LLP via telephone at (215) 988-2642 or via e-mail at charles.lange@faegredrinker.com with any questions
you may have. In addition, please notify Mr. Lange when this request for acceleration has been granted.

 Very truly yours,

 BLACK HILLS CORPORATION

 By:
 /s/ Kimberly F. Nooney

 Name:
 Kimberly F. Nooney

 Title:
 Chief Financial Officer

 cc:
 Charles Lange, Faegre Drinker Biddle & Reath LLP

 Brandon Mason, Faegre Drinker Biddle & Reath LLP

 Darren Nakata, Black Hills Corporation

CORRESP
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 February 4, 2026

 VIA EDGAR TRANSMISSION

 Division of Corporate Finance

 United States Securities and Exchange Commission

 100 F Street, N.E.

 Washington, D.C. 20549-6010

 Re:
 Black Hills Corporation

 Registration Statement on Form S-4 (Registration No. 333-293105)

 Request for Acceleration of Effective Date

 Ladies and gentlemen:

 In accordance with Rule 461
under the Securities Act of 1933, as amended (the "Act"), Spire Global, Inc. (the "Company") requests that the
Securities and Exchange Commission take appropriate action to cause the Registration Statement on Form S-4 (File No. 333-293105) to become
effective on February 6, 2026 at 4:00 p.m., Eastern Time, or as soon as practicable thereafter, or
at such later time as the Company or its counsel may request via telephone call to the staff. In making this acceleration request, the
Company acknowledges that it is aware of its obligations under the Act.

 Please contact Charles Lange
of Faegre Drinker Biddle & Reath LLP via telephone at (215) 988-2642 or via e-mail at charles.lange@faegredrinker.com with any questions
you may have. In addition, please notify Mr. Lange when this request for acceleration has been granted.

 Very truly yours,

 BLACK HILLS CORPORATION

 By:
 /s/ Kimberly F. Nooney

 Name:
 Kimberly F. Nooney

 Title:
 Chief Financial Officer

 cc:
 Charles Lange, Faegre Drinker Biddle & Reath LLP

 Brandon Mason, Faegre Drinker Biddle & Reath LLP

 Darren Nakata, Black Hills Corporation

Mail Stop 3561
October 13 , 2016

David R. Emery
Chairman and Chief Executive Officer
Black Hills Corporation
625 Ninth Street
Rapid City, South Dakota 57701

Re: Black Hills Corporation
 Form 10-K for Fiscal Year Ended December 31,  2015
Filed February 25, 2016
File No. 1-31303

Dear Mr. Emery :

We have completed our review of your filing.  We remind you that our comments or
changes to disclosure in response to our comments do not foreclose the Commission from taking
any action with respect to the company or the filing 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 Un ited States.  We urge all persons who are responsible for the
accuracy and adequacy of the disclosure in the filing to be certain that the filing include s the
information the Securities Exchange Act of 1934 a nd all applicable rules require.

Sincerely,

 /s/ William H. Thompson

 William  H. Thompson
Accounting Branch Chief
Office of Consumer Products

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		Document

625 Ninth Street / P.O. Box 1400

 P:  605.721.1700

Rapid City, SD  57709-1400

 www.blackhillscorp.com

October 7, 2016

William H. Thompson

Accounting Branch Chief

Office of Consumer Products

Division of Corporation Finance

United States Securities and Exchange Commission

Washington, D.C.  20549

Re:

 Black Hills Corporation

Form 10-K for the Fiscal Year Ended December 31, 2015

Filed February 25, 2016

Form 10-Q for Fiscal Quarter Ended June 30, 2016

Filed August 5, 2016

Amendment No. 1 to Form 8-K Filed March 18, 2016

File No. 1-31303

Dear Mr. Thompson:

The purpose of this letter is to respond to your comments as set forth in your letter of September 23, 2016.

We have carefully considered your comments.  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.

FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015

Consolidated Balance Sheets, page 127

Comment No. 1:

Please tell us whether there are any items included in other current assets that exceed five percent of total current assets.  If so, please state separately, in the balance sheets or in the notes thereto, any item in excess of five percent of total current assets.  Refer to Rule 5-02.8 of Regulation S-X.

Improving life with energy

www.blackhillscorp.com

William H. Thompson

U.S. Securities and Exchange Commission

October 7, 2016

Page 2

Company’s Response:

We have a process in place to review disclosure requirements including those under Rule 5-02.8 of Regulation S-X, which requires additional disclosure for other current assets in excess of five percent of total current assets.  We had no amounts in other current assets that would meet the threshold for additional disclosure in our Form 10-K for the fiscal year ended December 31, 2015, as shown in the following table:

Other Current Assets at December 31, 2015 (in thousands):

 % of Total Current Assets

Accrued receivables related to litigation expenses and settlements

 $

 39,050

 4.7%

Prepaid expenses

 19,262

 2.3%

Construction contract receivable

 10,857

 1.3%

Other current assets

 2,594

 0.3%

Total Other current assets

 $

 71,763

Total Current Assets

 $

 822,151

We will continue to review disclosure requirements, and in the future if there are any items included in other current assets that exceed five percent of total current assets, will state such items separately, in the balance sheets or in the notes thereto.

(12) Stock, page 165

Comment No. 2:

Please tell us your consideration to disclose the weighted-average grant date fair value for stock options pursuant to ASC 718-10-50-2(c)(2).  Please also tell us your consideration to disclose the method and assumptions used to estimate the fair value of stock options pursuant to ASC 718-10-50-2(f).

Company’s Response:

We acknowledge the Staff’s comment and note the requirements of ASC 718-10-50-2(c)(2) and ASC 718-10-50-2(f).  Because no options were granted in 2015 and the total cost of options granted in 2014 and 2013 were immaterial to the consolidated financial statements, the Company chose not to make the related detailed disclosures.

The table below summarizes for 2015, 2014 and 2013 the options granted in each year, the grant date fair value of the options granted during each year, the total grant date fair value cost and the valuation assumptions used to estimate the grant date fair value of the options.

Improving life with energy

www.blackhillscorp.com

William H. Thompson

U.S. Securities and Exchange Commission

October 7, 2016

Page 3

 2015

 2014

 2013

Options granted during the year

 —

 80,949

 9,800

Grant date fair value of each option granted during the year

 NA

 $

 12.58

 $

 7.65

Total grant date fair value

 $

 —

 $

 1,018,000

 $

 75,000

Valuation Assumptions:

Risk-free interest rate1

 NA

 2.1

 %

 1.4

 %

Expected price volatility2

 NA

 29.4

 %

 29.3

 %

Expected dividend yield3

 NA

 2.9

 %

 3.8

 %

Expected life in years4

 NA

 7.0

 7.0

1 Based on treasury interest rates with terms consistent with the expected life of the options.

2 Based on a blended historical and implied volatility of the Company’s stock price.

3 Based on the Company’s historical dividend payout and expectation of future dividend payouts and may be subject to change in the future.

4 Based on historical experience.

Given the immateriality of the stock options, the Company plans to make the following general disclosure regarding stock options in its Form 10-K for the fiscal year ending December 31, 2016.

“The Company has not issued any stock options since 2014 and has _______ (currently 119,000) stock options outstanding at December 31, 2016.  The amount of stock options granted during the last three years, related exercise activity and the number of stock options outstanding at December 31, 2016 are not material to the Company’s consolidated financial statements.”

Comment No. 3:

Please disclose in future filings your accounting policy with respect to stock-based compensation.

Company’s Response:

We acknowledge the Staff’s comment and will disclose the following in Footnote 1, Accounting Policies in our Notes to Condensed Consolidated Financial Statements on Form 10-Q for the fiscal quarter ended September 30, 2016, and in future filings.

“Share-Based Compensation

We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation, by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation.  Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures.”

Improving life with energy

www.blackhillscorp.com

William H. Thompson

U.S. Securities and Exchange Commission

October 7, 2016

Page 4

Form 10-Q for Fiscal Quarter Ended June 30, 2016

Notes to Condensed Consolidated Financial Statements

(2) Acquisition

Acquisition of SourceGas

Seller’s non-controlling interest, page 16

Comment No. 4:

We note your disclosure that one of the sellers retained a 0.5% of the outstanding equity interest of SourceGas under the terms of the purchase agreement, and the agreement contains both a call option to purchase the remaining interest and a put option to sell the retained interest.  It appears that the purchase price allocation includes 100% of SourceGas net assets and the value of the 0.5% equity interest is reflected as Redeemable NCI.  Please clarify for us and disclose how you accounted for the NCI and the related call and put options.  In doing so, please also tell us whether the exercise price for the call and put options are fixed and similar or not significantly different.  Refer to ASC 480-10-55-59 through 55-62.

Company’s Response:

Under the terms of the Purchase and Sale Agreement (PSA) Exhibit A - Option Agreement (filed as EX-2.2 to the Form 8-K filed on July 14, 2015), Black Hills Utility Holdings, Inc. (a wholly-owned subsidiary of Black Hills Corporation (BHC)) is granted an option to purchase the 0.5% non-controlling interest (NCI) in SourceGas Holdings, LLC (SourceGas) beginning 366 days from February 11, 2016 (the call option).  The call option expires after 90 days from the effective date of February 12, 2017 if it is not exercised.  The Option Agreement also grants the seller the option to sell its remaining interest in SourceGas to BHC (the put option).  The put option is effective upon the expiration of the call option and expires after 90 days from its inception.

The Option Agreement establishes the exercise pricing for the options.  The call option exercise price is determined by first deriving the value of the retained interest by multiplying the Base Purchase Price, as defined in the PSA, by the 0.5% NCI.  The exercise price of the call option is then calculated by multiplying this calculated value of the retained interest by 110%.  The put option pricing is determined by first deriving the value of the retained interest (in the same manner as explained for the call option).  The exercise price of the put option is then calculated by multiplying this calculated value of the retained interest by 90%.

The Option Agreement provides for potential adjustments to the exercise price of the call and put options.  If either party objects to the option’s price determined as described above, as not reflective of the fair market value of the retained interest, then the parties may engage an independent appraiser to determine the value of the retained interest.  The call option and put option will then each be calculated as 110% and 90%, respectively, of the appraised value of the retained interest.  Further, the Option Agreement provides for a potential adjustment related to the lesser of actual capital expenditures and capital contributions from the NCI owner from February 12, 2016 through the date the option is exercised; the amount of the adjustment would be the same for both the call option and put option.  We expect this adjustment will be zero as we do not currently anticipate requesting additional capital contributions from the NCI owner.

ASC 480-10-55-59 through 55-62 provides the following guidance related to a written put option and a purchase call option embedded in an NCI:

55-59:  If the derivative instrument in Derivative 2 is freestanding of the noncontrolling interest, it should be combined with the noncontrolling interest and accounted for as a financing.  That is, the combination of option contracts should be viewed on a combined basis with the noncontrolling interest and accounted for as a financing of the parent’s purchase of the noncontrolling interest.

Improving life with energy

www.blackhillscorp.com

William H. Thompson

U.S. Securities and Exchange Commission

October 7, 2016

Page 5

55-60:  Under that approach, the parent would consolidate 100 percent of the subsidiary and would attribute the stated yield earned under the combined derivative instrument and noncontrolling interest position to interest expense (that is, the financing would be accreted to the strike price of the forward or option over the period until settlement).  No gain or loss would be recognized on the sale of the noncontrolling interest by the parent to the noncontrolling interest holder at the inception of the derivative instrument.

55-61:  The risks and rewards of owning the noncontrolling interest have been retained by the parent during the period of the derivative instrument, notwithstanding the legal ownership of the noncontrolling interest by the counterparty.  Combining the two transactions in this circumstance reflects the substance of the transactions; that the counterparty is financing the noncontrolling interest.  Upon such combination, the resulting instrument is not a derivative instrument subject to Subtopic 815-10.

55-62:  This accounting applies even if the exercise prices of the put and call options are not equal, as long as those exercise prices are not significantly different.

In arriving at our accounting for these features under the guidance above, we first considered whether the put option and call option are freestanding financial instruments.  We concluded they are not freestanding financial instruments as the features are not separately detachable from the 0.5% NCI nor separately exercisable from the 0.5% NCI.

We next noted that the 0.5% NCI, when considering these embedded features, is not mandatorily redeemable.  The put and call are options and there is no date certain or event certain to occur in which the NCI must be purchased by the Company.

Additionally, we noted that the exercise date and price of the call and put options are significantly different.  The call option may be exercised beginning February 12, 2017 and expires after 90 days.  The put option exercise period begins only after the call option expires and the put option expires after 90 days from that date.  The difference in exercise price between the call and put options is 20% regardless of whether the potential adjustments described above are applicable, which we consider to be significant.

For the above reasons, we ultimately concluded that the 0.5% NCI should not be classified as debt under the guidance of ASC 480-10-55-59 through 55-62.

We also considered the guidance of ASC 815-15-25-1 to determine whether either the put or call option represented an embedded derivative that required bifurcation.

ASC 815-15-25-1 provides the following guidance:

An embedded derivative shall be separated from the host contract and accounted for as a derivative instrument pursuant to Subtopic 815-10 if and only if all of the following criteria are met:

a.

 The economic characteristics and risks of the embedded derivative are not clearly and closely related to the economic characteristics and risks of the host contract.

b.

 The hybrid instrument is not remeasured at fair value under otherwise applicable generally accepted accounting principles (GAAP) with changes in fair value reported in earnings as they occur.

c.

 A separate instrument with the same terms as the embedded derivative would, pursuant to Section 815-10-15, be a derivative instrument subject to the requirements of this Subtopic. (The initial net investment for the hybrid instrument shall not be considered to be the initial net investment for the embedded derivative.)

An embedded feature would only require bifurcation if the instrument, if freestanding, possessed the characteristics of a derivative.  We note that neither the put nor call would meet the net settlement criteria in ASC 815 as neither the put nor call permit net settlement, nor is the NCI readily convertible to cash.  As a result, we concluded that the put and call do not require bifurcation.

Improving life with energy

www.blackhillscorp.com

William H. Thompson

U.S. Securities and Exchange Commission

October 7, 2016

Page 6

We concluded that it is appropriate to account for the NCI and the related call and put options as a separate component of equity.  We considered the guidance of ASC 480-10-S99-3A which discusses the application of Accounting Series Release No. 268, Presentation in Financial Statements of “Redeemable Preferred Stocks” (ASR 268), in paragraphs 3 through 4, which reads in part:

...the SEC staff believes that ASR 268 also provides analogous guidance for other redeemable equity instruments including, for example, common stock, derivative instruments, noncontrolling interests, securities held by an employee stock ownership plan, and share-based payment arrangements with employees.

ASR 268 requires equity instruments with redemption features that are not solely within the control of the issuer to be classified outside of permanent equity (often referred to as classification in “temporary equity”). The SEC staff does not believe it is appropriate to classify a financial instrument (or host contract) that meets the conditions for temporary equity classification under ASR 268 as a liability.

We therefore concluded that classification of the NCI, and the related call and put options, as temporary equity under ASC 480-10-S99-3A was the appropriate accounting treatment.

Amendment No. 1 to Form 8-K Filed March 18, 2016

Exhibit 99.2

(4) Pro Forma Allocation of Purchase Price, page 7

Comment No. 5:

While we understand that the non-controlling interest is subject to valuation adjustments that have not been made, please tell us your consideration to disclose the equity interest of SourceGas acquired by the company and retained by t

Mail Stop 3561
September 23 , 2016

David R. Emery
Chairman and Chief Executive Officer
Black Hills Corporation
625 Ninth Street
Rapid City, South Dakota 57701

Re: Black Hills Corporation
 Form 10-K for Fiscal Year Ended December 31,  2015
Filed February 25, 2016
Form 10 -Q for Fiscal Quarter Ended June 30, 2016
Filed August 5, 2016
Amendment No. 1 to Form 8 -K Filed March 18, 2016
File No. 1-31303

Dear Mr. Emery :

We have limited our review of your filing to the financial statements and related
disclosures and have the following comments.  In some of our comments, we may ask you to
provide us with information so we may better understand your disclosure.

Please respond to  these comments  within ten busine ss days by providing the requested
information or advis e us as soon as possible when you will respond.  If you do not believe our
comments apply to your facts and circumstances, please tell us why in your response.

After  reviewing your response to these  comments, we may have additional comments.

Form 10 -K for Fiscal Year Ended December 31, 2015

Consolidated Balance Sheets, page 127

1. Please tell us whether there are any items included in other current  assets that exceed five
percent of total current assets . If so, please state separately, in the balance sheets or in the
notes thereto, any item in excess of five percent of total current assets .  Refer to Rule 5 -
02.8 of Regulation S -X.

(12) Stock, page 165

2. Please tell us your consideration to disclose the weighted -average grant date fair value for
stock options pursuant to ASC 718 -10-50-2(c)(2).  Please also tell us your consideration

David R. Emery
Black Hills Corporation
September 23, 2016
Page 2

 to disclose the method and assumptions used to estimate the fair value of s tock options
pursuant to ASC 718 -10-50-2(f).

3. Please disclose in future filings your accounting policy with respe ct to stock -based
compensation.

Form 10 -Q for Fiscal Quarter  Ended June 30, 2016

Notes to Condensed Consolidated Financial Statements

(2) Acquisition

Acquisition of SourceGas

Seller’s non -controlling interest, page 16

4. We note your disclosure that one of the sellers retained 0.5% of the outstanding equity
interest of SourceGas under the terms of the purchase agreement, and the agreemen t
contains both a call option to purchase the remaining interest and a put option to sell the
retained interest.  It appears that the purchase price allocation includes 100% of
SourceGas net assets and the value of the 0.5% equity interest is reflected as Redeemable
NCI.  Please clarify for us and disclose how you accounted for the NCI and the related
call and put options.  In doing so, please also tell us whether the exercise price for the call
and put options are fixed and similar or not significantly dif ferent.  Refer to ASC 480 -10-
55-59 through 55 -62.

Amendment No. 1 to Form 8 -K Filed March 18, 2016

Exhibit 99.2

(4) Pro Forma Allocation of Purchase Price, page 7

5. While we understand that the non -controlling interest is subject to valuation adjustme nts
that have not been made, please tell us you r consideration to disclose the equity interest
of SourceGas acquired by the company and retained by the seller, and to disclose the
non-controlling interest call and put options contained in the purchase agre ement.

(5) Pro Forma Adjustments, page 9

6. Please tell us and disclose in future filings how you determined the estimated fair value
of the long -term gas supply contract held by SourceGas’ non -regulated subsidiary in pro
forma adjustment (J) on page 12.

David R. Emery
Black Hills Corporation
September 23, 2016
Page 3

 7. Please tell us the nature of the one -time and non -recurring expense associated with the
acquisition in pro forma adjustment (L) on page 12.

We urge all persons who are responsible for the accuracy and adequacy of the disclosure
in the filing to be certain that the filing includes the information the Securities Exchange Act of
1934 and all applicable Exchange Act rules require.   Since the compa ny and its management are
in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy
and adequacy of t he disclosures they have made.

 In responding to our comments, please provide  a written statement from the company
acknowledging that:

 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 filing; 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.

You may contact Yolanda Guoba dia, Staff Accountant,  at (202) 551 -3562, Donna Di
Silvio, Staff Accountant, at (202) 551 -3202  or me at (202) 551 -3344 if you have questions
regarding our comment s or any other questions.

Sincerely,

 /s/ William H. Thompson

 William  H. Thompson
Accounting Branch Chief
Office of Consumer Products

Mail Stop 3561
October 7, 2015

Mr. Richard W. Kinzley
Chief Financial Officer
Black Hills Corporation
625 Ninth Street
Rapid City, South Dakota 57701

Re: Black Hills Corporation
 Form 10-K for Fiscal Year Ended December 31, 2014
Filed February 25, 2015
File No. 1 -31303

Dear Mr. Kinzley :

We have completed our review of your filing .  We remind you that our comments or
changes to disclosure in response to our comments do not  foreclose the Commission from taking
any action with respect to the company or the filing 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 Unite d States.  We urge all persons who are responsible for the
accuracy and adequacy of the disclosure in the filing to be certain that the filing includes the
information the Securities Exchange Act of 1934 and all applicable rules require.

Sincerely,

 /s/ William H. Thompson

William H. Thompson
Accounting Branch Chief
Office of Consumer Products

cc:  Esther Newbrough
 Corporate Controller

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		CORRESP

625 Ninth Street / P.O. Box 1400

 P:  605.721.1700

Rapid City, SD  57709-1400

 www.blackhillscorp.com

September 29, 2015

William H. Thompson

Accounting Branch Chief

Office of Consumer Products

Division of Corporation Finance

United States Securities and Exchange Commission

Washington, D.C.  20549

Re:

 Black Hills Corporation (the “Company”, “we”, “our” or “us”)

Form 10-K for the Fiscal Year Ended December 31, 2014

Filed February 25, 2015

Form 8-K filed August 5, 2015

Amendment No. 1 to Form 10-K for Fiscal Year Ended December 31, 2014

Filed August 7, 2015

File No. 1-31303

Dear Mr. Thompson:

The purpose of this letter is to respond to your comments as set forth in your letter of September 15, 2015.  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.

We have carefully considered your comments.  Our responses provide the details of how we intend to comply with your comments by enhancing and, in some respects, clarifying our disclosures, and we have provided details surrounding our qualitative and quantitative assessment of materiality as it relates to our recently amended filings.

In connection with our response to your comments, we also 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 filing; 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.

FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2014

Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations

Liquidity and Capital Resources, page 99

Comment No. 1:

Reference is made to the first financing risk factor disclosed on page 61 which states a credit rating downgrade could result in counterparties requiring you to post additional collateral under existing contracts.  Please tell us your consideration of disclosing the nature of these contracts, collateral posted, and incremental collateral requirements resulting from a potential credit rating downgrade in your discussion of liquidity and capital resources.

Improving life with energy

www.blackhillscorp.com

William H. Thompson

U.S. Securities and Exchange Commission

September 29, 2015

Page 2

Company's Response:

In determining our disclosures related to additional collateral requirements under existing contracts which could be required in the event of a credit rating downgrade, the Company considered the following factors:

1)

 The amount of potential collateral calls under existing contracts which could be required in the event of a credit rating downgrade to below investment-grade.  We estimated at December 31, 2014, an aggregate total of approximately $62.3 million of additional collateral could be requested under such a downgrade.

2)

 The amount of the potential collateral calls noted above relative to the $390 million of available liquidity at December 31, 2014 under our revolving credit facility as disclosed on page 102 of our 2014 Form 10-K.

3)

 The additional measures the Company could take to prevent our corporate credit ratings from being downgraded to below investment-grade, including potential asset sales, capital markets transactions and changes to our dividend policy.

Considering these factors, we determined that we had sufficient liquidity to cover the additional collateral that could be required.  We acknowledge that including information in the Liquidity and Capital Resources discussion surrounding this risk would enhance our disclosures.  In response to the Staff’s comment, in future filings beginning with our 2015 third quarter 10-Q, we will expand the disclosure in Liquidity and Capital Resources, Significant Factors Affecting Liquidity to provide additional detail surrounding collateral requirements, including the nature of such contracts, collateral posted, and incremental collateral requirements.  This risk does not apply to the Cash Collateral disclosure on page 101 of our 2014 Form 10-K as these contracts do not include these performance assurance provisions.

In future annual and quarterly filings, we will include the expanded disclosure shown below.  We include the expanded discussion below (additional text shown in italics) to show what this disclosure would have looked like if it had been provided as of December 31, 2014:

Liquidity and Capital Resources

Significant Factors Affecting Liquidity

Although we believe we have sufficient resources to fund our cash requirements, there are many factors with the potential to influence our cash flow position, including seasonality, commodity prices, significant capital projects and acquisitions, requirements imposed by state and federal agencies and economic market conditions.  We have implemented risk mitigation programs, where possible, to stabilize cash flow; however, the potential for unforeseen events affecting cash needs will continue to exist.

Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance.  A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions.  The amount of credit support that the Company may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and the amounts owed by or to the counterparty.

The Company also maintains interest rate swap transactions under which we could be required to post collateral on the value of such swaps in the event of an adverse change in our financial condition, including a credit downgrade to below investment-grade.

At December 31, 2014 we had $4.5 million of collateral posted related to our wholesale commodity contracts transactions, and no collateral posted related to our interest rate swap transactions.  At December 31, 2014, we had sufficient liquidity to cover any additional collateral that could be required to be posted under these contracts.

Improving life with energy

www.blackhillscorp.com

William H. Thompson

U.S. Securities and Exchange Commission

September 29, 2015

Page 3

CASH GENERATION AND CASH REQUIREMENTS

Cash Collateral

Under contractual agreements and exchange requirements, BHC or its subsidiaries have collateral requirements, which if triggered, require us to post cash collateral positions with the counterparty to meet these obligations.

We have posted the following amounts of cash collateral with counterparties at December 31 (in thousands):

Purpose of Cash Collateral

 2014

 2013

Natural Gas Futures and Basis Swaps Pursuant to Utility Commission Approved Hedging Programs

 $

 20,007

 $

 10,123

Oil and Gas Derivatives

 4,392

 2,501

Total Cash Collateral Positions

 $

 24,399

 $

 12,624

FORM 8-K FILED AUGUST 5, 2015

Exhibit 99

Comment No. 2:

Reference is made to your disclosure of fiscal 2015 earnings, as adjusted, guidance in the range of $2.80 to $3.00 per share.  Please tell us your consideration of providing disclosure pursuant to Item 10(e)(1)(i)(A) and (B) of Regulation S-K.

Company's Response:

From time to time, we may provide guidance on non-GAAP Earnings per share, which reflects certain adjustments from our expected GAAP Earnings per share, because our investors are interested in understanding our expectations for the Company’s core operating performance.  Examples of the types of adjustments may include non-budgeted events, non-cash impairments of assets and acquisition and disposition costs.  In periods where we provide such forward-looking non-GAAP guidance, we will comply with Item 10(e)(1)(i)(A) and (B) of Regulation S-K and provide a reconciliation to the comparable GAAP guidance.  If a reconciliation cannot be provided without unreasonable effort, we will identify the information that is not available without unreasonable effort, and disclose its probable significance.

We had adjustments or special items in the August earnings release; therefore, we should have identified the Earnings per share, as adjusted, guidance we provided at the time for the year ended December 31, 2015 as a Non-GAAP financial measure and disclosed our GAAP Earnings per share guidance and provided a reconciliation.  Accordingly, we should have included the following to show the reconciliation as of June 30, 2015:

Improving life with energy

www.blackhillscorp.com

William H. Thompson

U.S. Securities and Exchange Commission

September 29, 2015

Page 4

RECONCILIATION OF NON-GAAP GUIDANCE

 Low

 High

GAAP Diluted Earnings Per Share

 $

 0.98

 $

 1.18

Adjustments, after tax:

Ceiling test impairment

 1.73

 1.73

Impairment of equity investments

 0.08

 0.08

Acquisition costs

 0.01

 0.01

Total Adjustments

 1.82

 1.82

Earnings per share, As Adjusted (Non-GAAP)

 $

 2.80

 $

 3.00

In future releases of earnings guidance or updates to our earnings guidance, we will include a reconciliation such as the one set forth above or, if a reconciliation cannot be provided without unreasonable effort, we will state the following:

Earnings per share, as adjusted, is a Non-GAAP financial measure.  Earnings per share, as adjusted, is defined as GAAP Earnings per share, adjusted for expenses and gains that the Company believes do not reflect the Company’s core operating performance.  Examples of these types of adjustments may include unique one-time non-budgeted events, impairment of assets, acquisition and disposition costs, and other adjustments noted in the earnings reconciliation table in this release.  The Company is not able to provide a forward-looking quantitative GAAP to Non-GAAP reconciliation for this financial measure because we do not know the unplanned or unique events that may occur later during the year.

AMENDMENT NO. 1 TO FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 2014

Item 8.  Financial Statements and Supplementary Data

Notes to Consolidated Financial Statements

(1) Business Description and Significant Accounting Policies

Correction of Immaterial Errors, page 65

Comment No. 3:

Please provide us with your qualitative and quantitative assessment of materiality which supports a conclusion that the year ended December 31, 2012 adjustments were not material to your year ended December 31, 2012 financial statements.  In addition, please explain why the audit report date refers to a "restatement" while there is no reference to a restatement in the audited financial statements and notes to financial statements.  Further, reference is made to Amendment No. 1 to Form 10-Q for the quarterly period ended March 31, 2015.  Please provide a similar analysis for your conclusion that the three months ended March 31, 2015 adjustments were not material to your three months ended March 31, 2015 financial statements.

Company's Response:

Our response to the Staff’s Comment No. 3 is separated in sections below, beginning with a brief background of the issue which required the correction of immaterial errors and continuing with the specific portion of the Staff Comment being addressed stated in italics prior to the specific response.

Improving life with energy

www.blackhillscorp.com

William H. Thompson

U.S. Securities and Exchange Commission

September 29, 2015

Page 5

Background

Under the full cost method of accounting used to account for our oil and gas activities, as defined in SEC Reg S-X, Rule 4-10, all costs attributable to these activities are capitalized.  These capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test that limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC plus the lower of cost or market value of unevaluated properties.  Any costs in excess of the ceiling are written-off as a non-cash charge.

The model applied in performing our oil and gas ceiling test impairment calculation was developed prior to 2008 and has been applied consistently each quarter in assessing the need to record an impairment and to calculate the amount of the impairment, if applicable.  In preparing our financial statements for the quarter ended June 30, 2015, we determined that we had not appropriately accounted for income taxes associated with the ceiling test impairment within the model.  This error in the model resulted in us incorrectly calculating and consequently understating the ceiling test impairment charge recorded in 2008, 2009 and 2012, and the quarter ended March 31, 2015.  In addition, this error resulted in depletion expense being overstated in all periods subsequent to 2008, and the 2012 calculation of gain recognized on the sale of oil and gas producing property being understated (see also footnote disclosure from 2012 Form 10K for further explanation regarding gain recognition under full-cost accounting).

In considering the impacts of these errors, we considered the primary users of our financial statements, including investors, banks/lenders, analysts, and regulatory agencies.  We also evaluated the quantitative and qualitative aspects of materiality as explained further in this response.  We concluded the errors were immaterial thus not requiring a restatement of historical information.  We also concluded that correcting the cumulative effect of the errors in the second quarter of 2015 via a larger impairment charge would materially misstate the second quarter 2015 financial statements.  However, based on a reassessment of the effectiveness of our internal controls over financial reporting, we concluded that there was a material weakness as of December 31, 2014 related to a deficiency in the level of training in performing the control over the full cost ceiling test write-down impairment calculation, specifically related to evaluating and correctly accounting for the treatment of tax amounts associated with the calculation.  Accordingly, we amended both our 2014 Form 10-K (“2014 10-K/A”) and Form 10-Q for the period ended March 31, 2015 (“2015 Form 10-Q/A) to reflect this material weakness.  In connection with amending our 2014 Form 10-K we corrected the errors by recording an adjustment to opening retained earnings as of January 1, 2012 equal to the cumulative amount of the errors attributable to periods prior to 2012, and then revised the presentation of the subsequent periods ending December 31, 2012, 2013 and 2014 and March 31, 2015.

•

 Please provide us with your qualitative and quantitative assessment of materiality which supports a conclusion that the year ended December 31, 2012 adjustments were not material to your year ended December 31, 2012 financial statements.  Further, reference is made to Amendment No. 1 to Form 10-Q for the quarterly period ended March 31, 2015. Please provide a similar analysis for your conclusion that the three months ended March 31, 2015 adjustments were not material to your three months ended March 31, 2015 financial statements.

In evaluating the errors for the year ended December 31, 2012, and for the three months ended March 31, 2015, and in concluding that the errors were not material to the year ended December 31, 2012 financial statements or the three months ended March 31, 2015 financial

Mail Stop 3561
September 15 , 2015

Mr. Richard W. Kinzley
Chief Financial Officer
Black Hills Corporation
625 Ninth Street
Rapid City, South Dakota 57701

Re: Black Hills Corporation
 Form 10-K for Fiscal Year Ended December 31, 2014
Filed February 25, 2015
Form 8 -K filed August 5, 2015
Amendment No. 1 to Form 10 -K for Fiscal Year Ended December 31, 2014
Filed August 7, 2015
File No. 1 -31303

Dear Mr. Kinzley :

We have reviewed your filing an d have the following comments.  In some of our
comments, we may ask you to provide us with information so we may better understand your
disclosure.

Please respond to these comments  within ten busine ss days by providing the requested
informat ion or advis e us as soon as possible when you will respond.  If you  do not believe our
comments apply to your facts and circumstances , please tell us why in your response.

After reviewing your response to these  comments, we may have  additional comments.

Form 10 -K for Fiscal Year Ended December 31, 2014

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations

Liquidity and Capital Resources, page 99

1. Reference is made to the first financing risk factor disclosed on page 61 which states a
credit rating downgrade could result in counterparties requiring you to post additional
collateral under existing contracts.  Please tell us your consideration of disclosing the
nature of these contracts, collateral post ed, and incremental collateral requirements
resulting from a potential credit rating downgrade in your discussion of liquidity and
capital resources.

 Richard W. Kinzley
 Black Hills Corporation
 September 15, 2015
 Page 2

Form 8 -K filed August 5 , 2015

Exhibit 99

2. Reference is made to your disclosure of fiscal 2015 earnings, as adjusted, guidance in the
range of $2.80 to $3.00 per share.  Please tell us your consideration of providing
disclosure pursuant to Item 10(e)(1)(i)(A) and (B) of Regulation S -K.

Amendment No. 1 to Form 10 -K for  Fiscal Year Ended December 31, 2014

Item 8. Financial Statements and Supplementary Data

Notes to Consolidat ed Financial Statements

(1) Business Description and Significant Accounting Policies

Correction of Immaterial Errors, page 65

3. Please provide us with your qualitative and quantitative a ssessment of materiality which
supports a conclusion that the year ended December 31, 2012 adjustment s were not
material to your year ended December 31, 2012  financial statements.   In addition, please
explain why the audit report date refers to a “restatement” while there is no reference to a
restatement in the audited financial statements and notes to financial statements.  Further,
reference is made to Amendment No. 1 to Form 10 -Q for the quarterly period ended
March 31, 2015.  Please provide a similar analysis for your conclusion that the three
months ended March 31, 2015 adjustment s were  not material to your three months ended
March 31, 2015 financial statements.

We urge all pe rsons who are responsible for the accuracy and adequacy of the disclosure
in the filing to be certain that the filing includes the information the Securities Exchange Act of
1934 and all applicable Exchange Act rules require.   Since the company and its man agement are
in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy
and adequacy of the disclosures they have made.

 In responding to our comments, please provide  a written statement from the company
acknowle dging that:

 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 filing;  and

 Richard W. Kinzley
 Black Hills Corporation
 September 15, 2015
 Page 3

  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.

You may contact Adam Phippen, Staff Accountant,  at (202) 551 -3336 or Donna Di
Silvio, Staff Accountant,  at (202) 551 -3202 with any questions.

Sincerely,

 /s/ William H. Thompson

William H. Thompson
Accounting Branch Chief
Office of Consumer Products

cc:  Esther Newbrough
 Corporate Controller

September 3 , 2013

Via E-mail
Anthony S. Cleberg
Executive Vice President and
Chief Financial Officer
Black Hills Corporation
625 Ninth Street
Rapid City, South Dakota 57701

Re: Black  Hills Corporation
 Form 10-K for Fiscal Year Ended December 31, 2012
Filed February 25, 2013
File No. 1 -31303

Dear Mr. Cleberg :

We have completed our review of your filing .  We remind you that our comment  or
changes to disclo sure in response to our comment  does not foreclose the Commission from
taking any action with respect to the company or the filing and the compa ny may not assert staff
comment  as a defense in any proceeding initiated by the Commission or any person under the
federal securitie s laws of the United States.  We urge all persons who are responsible for the
accuracy and adequacy of the disclosure in the filing to be certain that the filing include the
information the Securities Exchange Act of 1934 and all applicable rules require.

Sincerely,

 /s/ Jim Allegretto

Jim Allegretto
Senior Assistant Chief Accountant

CORRESP
1
filename1.htm

		SEC Comment Letter 071113

July 11, 2013

Jim Allegretto

Senior Assistant Chief Accountant

Division of Corporation Finance

United States Securities and Exchange Commission

Washington, D.C.  20549

Re:

 Black Hills Corporation (the “Company”, “we”, “our” or “us”)

Form 10-K for Fiscal Year Ended December 31, 2012

Filed February 25, 2013

File No. 1-31303

Dear Mr. Allegretto:

The purpose of this letter is to respond to your comments as set forth in your letter of June 13, 2013.  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.

We have carefully considered your comments and our following responses provide the details of how we intend to comply with your comments by enhancing and, in some respects, clarifying our disclosures.  In some limited cases where we believe further revision is unnecessary, we have provided an explanation.

In connection with our response to your comments, we also 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 filing; 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.

FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012

Summary of Oil and Gas Reserve Data, page 36

Proved Reserves, page 38

Comment No. 1:

In comparing the disclosure on pages 38 and 174 to the reserves report filed as Exhibit 99, it appears that you have included the net quantities classified as proved developed non-producing in the Exhibit as proved undeveloped reserves on pages 38 and 174.  Please revise or advise.

Company's Response:

We agree with the Staff's comment.  We included in proved undeveloped reserves within our disclosures on pages 38 and 174 2,090 MMcfe  that were classified as proved developed non-producing in the reserves report filed as Exhibit 99.  The net quantities involved represent 2.6% of total reserves at December 31, 2012, which we believe to be immaterial to the users of our financial statements.  For future filings, beginning with our 2013 Form 10-K, we will revise our presentation of reserves in the Form 10-K to be consistent with the classification in Exhibit 99.

Jim Allegretto

U.S. Securities and Exchange Commission

July 11, 2013

Page 2

Comment No. 2:

Revise the tables on pages 38 through 40 and elsewhere on pages 86 and 174 through 175 to present natural gas liquid reserves.  See FASB ASC paragraph 932-235-50-4 regarding the separate disclosure of reserve quantify information for natural gas liquids.  In that regard, the staff views natural gas liquids as a separate product type under Item 1202(a)(1) and (2) of Regulation S-K.

Company's Response:

We acknowledge this and other comments of the Staff regarding enhancements to our disclosures surrounding natural gas liquids (NGLs). In applying the requirements of Item 1202 and FASB ASC paragraph 932-235-50-4 to our disclosure of reserves, we note that Item 1202(a)(4) and FASB ASC paragraph 932-235-50-4 require separate disclosure of reserves for the product types listed if material.  We agree with the Staff view that NGLs are a separate product type; however, we do not view our NGL reserve quantities as material to our overall reserves. Accordingly, we have not reflected NGLs in our proved liquid reserve estimates as they have been an immaterial portion of our reserves.

In determining whether or not to present NGL reserve quantities separately, we also considered the guidance set forth in ASC 932-235-50-6B regarding (a) considering all facts and circumstances and not solely the quantity of reserves and (b) the 15% quantitative significance threshold.  Our evaluation of the significance of our NGL reserves is based on all relevant circumstances and not solely on a quantitative reserve basis.  We further referred to the guidance set forth in ASC 932-235-20, which defines "significant oil and gas producing activities".  We evaluated the significance of our NGL reserves (i) relative to our total oil and gas activity, and (ii) relative to the total consolidated financial statement amounts of our segment, as outlined in the ASC 932-235-20 definition.

Our NGL proved reserve quantities represented less than 5% of our total proved reserves as of December 31, 2012.  For the year ended December 31, 2012, our Oil & Gas segment revenue was approximately 6.7% of Black Hills Corporation consolidated revenue, and NGLs were 4.0% of our crude oil and natural gas production, 3.4% of our total Oil and Gas segment revenue, and 0.2% of our consolidated revenue.

We will continue to monitor our NGLs and make the separate disclosure if they become material.

Production Volumes, page 41

Comment No. 3:

We note your disclosure with respect to the net quantities of natural gas liquids (NGLs) production is presented variously as equivalent gas volumes on page 41, as production excluding NGLs on pages 39 through 40 and 174 and as separate quantities of NGLs on page 85.  As Item 1204(a) of Regulation S-K requires disclosure by final product sold of oil, gas, and other products, please advise or revise your disclosure relating to NGL production volumes to be on a consistent basis throughout your filing.

Company's Response:

We agree with the Staff's comment, to be consistent in our disclosure we should show NGL production volumes separately, rather than including those volumes with natural gas where we have done so.  We believe this additional separate disclosure of our NGL production volumes in past filings is immaterial to the users of our financial statements.  For future filings, beginning with our 2013 Form 10-K, we will show NGL production volumes separately in all disclosure of production volumes.

We include supplementally in our response to Comment No. 4 below a revised presentation of production volumes for the years ended December 31, 2012 and 2011.

Jim Allegretto

U.S. Securities and Exchange Commission

July 11, 2013

Page 3

Comment No. 4:

Please advise or expand your disclosure of production on page 41 to comply with the requirements set forth in Item 1204(a) of Regulation S-K to provide disclosure for each field that contains 15% or more of the Company's total proved reserves.

Company's Response:

We agree with the Staff's comment as Item 1204(a) of Regulation S-K requires disclosure of production by geographical area and for each country and field that contains 15% or more of our total proved reserves.  In response to the Staff's comment, in our future filings beginning with our 2013 Form 10-K, we will clarify our disclosure to include disclosure of production by each field that contains 15% or more of our total proved reserves.   We include supplementally the following tables to show this disclosure for the years ended December 31, 2012 and 2011:

Production Volumes

 Year ended Dec. 31, 2012

Location (Basin)

 Field

 Oil (in Bbl)

 Natural Gas (Mcfe)

 NGLs (Gallons)

 Total (Mcfe)

San Juan

 East Blanco

 1,423

 3,584,746

 —

 3,593,284

San Juan

 All others

 —

 1,338,843

 —

 1,338,843

Piceance

 Piceance

 —

 1,716,588

 244,339

 1,751,494

Powder River

 Finn Shirley

 202,698

 441,165

 2,742,039

 2,049,073

Powder River

 All others

 15,757

 4,667

 —

 99,209

Williston

 Bakken

 337,579

 404,466

 159,543

 2,452,732

All other properties

 Various

 2,514

 1,195,716

 339,593

 1,259,313

   Total Volume

 559,971

 8,686,191

 3,485,514

 12,543,948

Production Volumes

 Year ended Dec. 31, 2011

Location (Basin)

 Field

 Oil (in Bbl)

 Natural Gas (Mcfe)

 NGLs (Gallons)

 Total (Mcfe)

San Juan

 East Blanco

 1,746

 4,225,027

 —

 4,235,503

San Juan

 All others

 —

 837,635

 —

 837,635

Piceance

 Piceance

 —

 1,077,040

 240,667

 1,111,421

Powder River

 Finn Shirley

 248,089

 512,100

 2,983,700

 2,426,877

Powder River

 All others

 16,269

 4,230

 —

 101,844

Williston

 Bakken

 181,580

 167,367

 39,079

 1,262,429

All other properties

 Various

 4,139

 1,703,021

 411,368

 1,786,622

   Total Volume

 451,823

 8,526,420

 3,674,814

 11,762,331

Jim Allegretto

U.S. Securities and Exchange Commission

July 11, 2013

Page 4

Other Information, page 42

Comment No. 5:

We note your disclosure on page 85 of the average price received per gallon of natural gas liquids (NGLs) sold.  Please advise or expand your disclosure of the average wellhead prices used in the determination of the reserves provided on page 42 to include the price for NGLs.

Company's Response:

For the reasons set forth in our response above to Staff Comment No. 2, we have not reflected NGLs in our proved liquid reserves.  As a result, we have not used the average wellhead prices of NGLs in the determination of our reserves.

We will continue to monitor our NGLs and make the separate disclosure if they become material.

Oil and Gas Reserves (Unaudited), page 173

Reserves, page 173

Comment No. 6:

We note the following from your disclosure:

•

 On page 175 you disclose that you invested $5.7 million to develop PUD locations in 2012; however, the table on that page indicates $4.9 million of future development costs were incurred for PUD locations.

•

 On page 175 your disclosure is limited to the 3 gross PUD locations drilled in the Williston Basin during 2012; however, the table on page 43 indicates that in addition to wells drilled in the Williston Basin during 2012, you also drilled productive development and exploratory wells in the Powder River and Piceance Basins.

•

 On page 175 your disclosure is limited to the 1.4 Bcfe of proved reserves that you converted or added in the Williston basin; however, the table on page 39 discloses your total 2012 additions from extensions and discoveries were 5.6 Bcfe.

Please advise or expand you disclosure to reconcile the difference in the capital amounts invested and the net reserve additions and changes relating to your drilling activities during 2012 as required under Item 1203 of Regulation S-K and FASB ASC paragraph 932-235-50-5.

Company's Response:

•

 Staff Comment:  On page 175 you disclose that you invested $5.7 million to develop PUD locations in 2012; however, the table on that page indicates $4.9 million of future development costs were incurred for PUD locations.

Company's Response:  The $5.7 million and $4.9 million are not intended to be compared. The $5.7 million represents the amounts invested to develop three Williston Basin PUD locations in our remaining Williston Basin assets. The $4.9 million represents future development costs included in the table on page 175 that have not yet been incurred as of December 31, 2012.  These are costs that we would expect to incur in the future in connection with the development of these Williston Basin reserves.

For future filings, beginning with our 2013 Form 10-K, we will clarify the wording in our presentation by separating the information into two different bullets, one for historical spending and the other for future development costs, to read as follows:

•

 During 2012 we invested $5.7 million to develop three Williston Basin PUD locations in our remaining Williston Basin assets.

•

 At December 31, 2012, our proved reserves, PUD locations and future development costs are reflected in the following table.

Jim Allegretto

U.S. Securities and Exchange Commission

July 11, 2013

Page 5

•

 Staff Comment:  On page 175 your disclosure is limited to the 3 gross PUD locations drilled in the Williston Basin during 2012; however, the table on page 43 indicates that in addition to wells drilled in the Williston Basin during 2012, you also drilled productive development and exploratory wells in the Powder River and Piceance Basins.

•

 Staff Comment:  On page 175 your disclosure is limited to the 1.4 Bcfe of proved reserves that you converted or added in the Williston basin; however, the table on page 39 discloses your total 2012 additions from extensions and discoveries were 5.6 Bcfe.

Company's Response:    Final Release No. 33-8995, which generated Item 1203 of Regulation S-K, requires disclosure in narrative form of information relating to proved undeveloped reserves while FASB ASC paragraph 932-235-50-5 requires disclosure of changes in net quantities of an entity's proved reserves.  In applying the requirements of Item 1203, we included only information related to proved undeveloped reserves required under this Item.  In applying the requirements of FASB ASC paragraph 932-235-50-5, we included information related to all of our proved reserves - developed and undeveloped - as required under this ASC.  Because our reserve report reflects year over year results, development and exploratory wells drilled during a current year may not have been booked as proved undeveloped locations in the previous year's reserve report.

In 2012, the only December 31, 2011 proved undeveloped reserves locations in which we invested were the 3 gross PUD locations drilled in the Williston Basin noted in our disclosure on page 175.  Drilling activity in 2012 created locations in the Powder River and Piceance Basins classified as proved undeveloped  that were also developed as proved developed producing during the year.  These Powder River and Piceance Basin productive development and exploratory wells were not classified as proved undeveloped at either December 31, 2012 or 2011; therefore, we did not include these in our disclosure of proved undeveloped reserves on page 175.

The narrative in the footnote on page 174 under the reserves tables references total reserve additions of 5.6 Bcfe, in agreement with the total 2012 additions from extensions and discoveries included in the table on page 39.  The narrative and table found later in that footnote on the bottom of page 174 and at the top of page 175 were provided to reflect only the activity associated with proved undeveloped reserves that were recorded as of December 31, 2011 and December 31, 2012, in accordance with the requirements of Item 1203.  The 1.4 Bcfe shown in that table is the portion of overall reserve additions from extensions and discoveries  that was attributable to those locations classified as proved undeveloped at December 31, 2011 and 2012.

In future filings, we will include additional headings in the footnote to more clearly delineate the information that is related to proved undeveloped reserves only.

Standardized Measure of Discounted Future Net Cash Flows, page 176

Comment No. 7:

Your disclosure of the standardized measure of discounted future net cash flows for each of the periods presented on page 176 does not appear to include the cost associated with the abandonment of your oil and gas assets as part of the future development costs.  Please tell us how you have considered the inclusion of such costs in the preparation of the standardized measure relating to your proved oil and gas reserve quantities.  Refer to the guidance provided by the Division of Corporation Finance at http://www.sec.gov/divisions/corpfin/guidance/oilgasletter.htm.

Jim Allegretto

U.S. Securities and Exchange Commission

July 11, 2013

Page 6

Company's Response:

We agree with the Staff's comment.  We did not include the cost associated with the abandonment of oil and gas assets as part of the future development costs.  We do not view these costs as material to the presentation of this estimate or to the users of our financial statements.  Including the cost associated with the abandonment of oil and gas assets as part of the future development costs reduces the standardized measure of discounted future net cash flows by 4.1% at December 31, 2012.  As reported, our stan

June 13, 2013

Via E-mail
Anthony S . Cleberg
Executive Vice President and
Chief Financial Officer
Black Hills Corporation
625 Ninth Street
Rapid City , South Dakota  57701

Re: Black Hills Corporation
 Form 10-K for Fiscal Year Ended December 31 , 2012
Filed February 25 , 2013
File No. 1-31303

Dear Mr. Cleberg :

We have reviewed your filing and have the following comment s.   In some of our
comment s, we may ask you to provide us with information so we may better understand your
disclosure.

Please respond to this letter within ten business days by amending your filing, by
providing the requested information, or by advising us when you will provide the requested
response.   If you d o not believe our comment s apply  to your facts and circumstances or do not
believe an amendment is appropriate, please tell us why in your response.

After reviewing any amendment to your filing and the information you provide in
response to these commen ts, we may have  additional comments.

Form 10 -K for Fiscal Y ear Ended December 31, 20 12

Summary of Oil and Gas Reserve Data, page 36

Proved Reserves, page 38

1. In comparing the disclosure on pages 38 and 174 to the reserves report filed as Ex hibit
99, it appears that you have included the net quantities classified as proved developed
non-producing in the Exhibit as proved undeveloped reserves on pages 38 and 174.
Please revise or advise.

2. Revise the tables on pages  38 through 40 and elsewher e on pages 86 and 174 through 175
to present natural gas liquid reserves .  See FASB ASC paragraph 932-235-50-4 regarding
the separate disclosure of reserve quantify information for natural gas liquids.  In that

Anthony S. Cleberg
Black Hills Corporation
June 13 , 2013
Page 2

 regard, the staff views natural gas liquids a s a separate product type under Item
1202(a)(1) and (2) of Regulation S -K.

Production Volumes, page 41

3. We note your disclosure with respect to the net quantities of natural gas liquids (NGLs)
production is presented variously as equivalent gas volumes on  page 41 , as production
excluding NGLs on pages 39 through 40 and 174  and as separate quantities of NGLs on
page 85 .  As Item 1204(a) of Regulation S -K requires disclosure by final product sold of
oil, gas, and other products, please advise or revise your disclosure relating to NGL
production volumes to be on a consistent basis throughout your filing.

4. Please advise or expand your disclosure of production on page 41 to comply with the
requirements set forth in Item 1204(a) of Regulation S -K to provide discl osure for each
field that contains 15% or more of the Company’s total proved reserves.

Other Information, page 42

5. We note your disclosure on page 85 of the average price received per gallon of natural
gas liquids (NGLs)  sold.  Please advise or expand your  disclosure of the average
wellhead prices used in the determination of the reserves provided on page 42 to include
the price for NGLs.

Oil and Gas Reserves (Unaudited), page 17 3

Reserves, page 173

6. We note the followi ng from your disclosure:

 On page 175 you disclose that you invested $5.7 million to develop PUD
locations  in 2012 ; however, the table on that page indicates  $4.9 million of future
development costs were incurred for PUD locations.

 On page 175 your disc losure is limited to the 3 gross PUD locations drilled in the
Williston Basin during 2012; however, the table on page 43 indicates that in
addition to wells drilled in the Williston Basin during 2012, you also drilled
productive development and exploratory  wells in the Powder River and Piceance
Basins.

 On page 175 your disclosure is limited to the 1.4 Bcfe of proved reserves that you
converted or added in the Williston basin; however, the table on page 39 discloses
your total 2012 additions from extensions  and discoveries were 5.6 Bcfe.

Please advise or expand you disclosure to reconcile the difference in the capital amounts
invested and the net reserve additions and changes relating to your drilling activities

Anthony S. Cleberg
Black Hills Corporation
June 13 , 2013
Page 3

 during 2012 as required under Item 1203 of Regulation S -K and FASB ASC paragraph
932-235-50-5.

Standardized Measure of Discounted Future Net Cash Flows, page 176

7. Your disclosure of the standardized measure of discounted future net cash flows for each
of the periods presented on page 176 does not appear to include the cost associated with
the abandonment of your oil and gas assets as part of the future development costs.
Please tell us how you have considered the inclusion of such costs in the preparation of
the standardized measure relating to yo ur proved oil and gas reserve quantities.  R efer to
the guidance provided by the Division of Corporation Finance at
http://www.sec.gov/divisions/corpfin/guidance/oilgasletter.htm .

Exhibit 99

8. We note the following:

 The reserve report lacks a tabular gra nd summary of the reserve and income data
relating to the summation of the individual reserve reports contained therein.

 The reserve report addresses the evaluation of all interests for Black Hills Gas
Exploration and Production, Inc.; however, Exhibit 21 does not list a subsidiary
with this name as part of the Black Hills Corporation.

 The net quantities of reserve and income data presented in the reserves report for
the entity Black Hills Exploration and Production, Inc. do not correspond to the
quanti ties attributed to Black Hills Exploration and Production, Inc. (BHEP) on
page 36 and elsewhere on pages 120 and 173 of the filing.

Please obtain and file an amended reserves report that addresses or clarifies each of these
points as part of the requireme nts relating to the summary of the third party’s conclusions
under Item 1202(a)(8)(ix).

9. We note the operating income (BFIT) shown in the reserves report for the entity Black
Hills Exploration and Production, Inc. includes revenue attributable to a 44.7%
ownership of the Newcastle Gas Processing Plant.  Please tell us what portion of the plant
revenue is for processing gas owned by Black Hills Exploration and Production, Inc. to
the Company’s interest.  Also quantify for us the net amounts of the proved reserves
disclosed in the report attributable to Black Hills Exploration and Production, Inc.
ownership in the Newcastle Gas Processing Plant.

10. Please tell us if any of the  natural gas or oil reserve quantities presented in the reserves
reports include natural gas liquid reserves (NGLs) and if so, how you have considered the
requirements contained in FASB ASC paragraph 932 -235-50-4 regarding the separate
disclosure of reserv e quantify information for natural gas liquids.

Anthony S. Cleberg
Black Hills Corporation
June 13 , 2013
Page 4

11. We note several references in each of the reserve reports to additional information that
are not included in Exhibit 99 such as:

 “The detailed forecasts of reserves and economics are presented in the attac hed
tables. Tables I -Proved, I -PDP, I -PDNP and I -PUD are summaries of the reserves
and associated economics by reserve category.  Under tabs by reserve category,
these tables are then presented along with corresponding Table II's, which are
summaries of th e ultimate recovery, gross and net reserves, ownership, revenue,
expenses, investments, net income and discounted cash flows for the individual
wells in each Table I.  These tables are sorted by state and then lease/well name.”

 “Page 1 of the Appendix exp lains the type of data in these tables.”

 “The methods employed in estimating reserves are described in page 2 of the
Appendix.”

 “The proved reserve classifications conform to criteria of the Securities and
Exchange Commission as defined in pages 3 -4 of the Appendix.”

Please advise or obtain and file an amend ed Exhibit 99 to includ e the referenced
information .

We urge all persons who are responsible for the accuracy and adequacy of the disclosure
in the filing s to be certain that the filing s include s the information the Securities Exchange Act of
1934 and all applicable Exchange Act rules require.   Since the company and its management are
in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy
and adequacy o f the disclosures they have made.

 In responding to our comments, please provide  a written statement from the company
acknowledging that:

 the company is responsible for the adequacy and accuracy of the disclosure in the filing s;

 staff comments or chan ges to disclosure in response to staff comments do not foreclose
the Commission from taking any action with respect to the filing; 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.

Anthony S. Cleberg
Black Hills Corporation
June 13 , 2013
Page 5

 You may contact Tony Watson, Accountant,  at (202) 551 -3318  or John Hodgin,
Petroleum Engineer, at (202) 551 -3699 if you have questions regarding our comments.  Please
contact me at (202) 551 -3849  with any  other questions.

Sincerely,

 /s/ Jim Allegretto

Jim Allegretto
Senior Assistant  Chief  Accountant

March 8, 2011
 David Emery Chief Executive Officer Black Hills Corporation 625 Ninth Street Rapid City, South Dakota 57701
Re: Black Hills Corporation
Form 10-K for the Fiscal Year Ended December 31, 2009 Filed February 26, 2010 File No. 1-31303

Dear Mr. Emery:
We have completed our review of your fili ng and do not have any further comments at
this time.
Sincerely,
  /s/ William H. Thompson
William Thompson Accounting Branch Chief

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March 3, 2011

William Thompson

Accounting Branch Chief

Division of Corporation Finance

United States Securities and Exchange Commission

100 F Street, N.E., MS 3561

Washington, D.C.  20002

Re:    Black Hills Corporation (the “Company”, “we”, “our” or “us”)

Form 10-K for Fiscal Year Ended December 31, 2009

Filed February 26, 2010

File No. 1-31303

Dear Mr. Thompson:

The purpose of this letter is to respond to your comments as set forth in your letter of February 16, 2011.  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.

We have carefully considered your comments and our following responses provide the details of how we intend to comply with your comments by enhancing and, in some respects, clarifying our disclosures.  In some limited cases where we believe further revision is unnecessary, we have provided an explanation.

FORM 10-K FOR THE FISCAL YEAR ENDED DECEMER 31, 2009

Items 7 and 7A. Management's Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk, page 68

Oil and Gas, page 88

Comment No. 1:

We note your response to our comment three that your development of proved undeveloped reserves “represented approximately 0.7 percent, 5.2 percent, and 8.3 percent of proved undeveloped reserves reflected in our reserve reports at the beginning of the year for 2009, 2008 and 2007, respectively.”  This development rate - an average of about 5 percent over three years - indicates 20+ years are required to develop your PUD reserves.  Rule 4-10(a)(31)(ii) states “Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.”  Item 1203(d) of Regulation S-K requires that registrants “Explain the reasons why material amounts of proved undeveloped reserves in individual fields or countries remain undeveloped for five years or more after disclosure as proved undeveloped reserves.”  Please explain to us the steps you will take to comply with Rule 4-10(a) and Regulation S-K.

Company's Response:

We believe that we have complied with Rule 4-10(a) and Regulation S-K in the preparation and disclosure of our oil and gas reserve estimates.  We prepare our reserve estimates in accordance with Rule 4-10 of Regulation S-X and specifically Rule 4-10(a)(31) when evaluating our undrilled locations.  Accordingly, the proved undeveloped (“PUD”) reserves included in our annual reserve estimates within our 2009 Form 10-K all had an adopted development plan scheduling them to be drilled within five years.

William Thompson

U.S. Securities and Exchange Commission

March 3, 2011

Page 2 of 3

Our response to comment three was focused on conversion of PUD reserves to proved developed producing (PDP) reserves and not the overall changes in our PUD reserves.  We respectfully submit that the Staff's calculation methodology indicating a 20 year development time horizon is not completely representative of our PUD reserve activity as it does not consider all of the year-to-year changes accounted for in our reserve estimates.  For example, our PUD natural gas reserves for December 31, 2008 and December 31, 2009 declined from 65,731 MMcf to 12,749 MMcf, respectively.  This decline of over 80 percent is almost entirely due to the drop in well-head price from $4.44 to $2.52, as disclosed on page 202 of our 2009 Form 10-K.  This example indicates that while our PUD reserves may not have been developed, we also did not continue to carry these undrilled locations as PUD reserves as they were removed from our proved reserves due to changes in economics.

As represented to the Staff above, we did not include any PUD reserves that were not scheduled to be drilled within five years in our annual reserve estimates disclosed in our 2009 Form 10-K.  We note to the Staff that if we include in future reserve estimates a material amount of PUD reserves that remain undrilled for five years or more after disclosure as PUD reserves, we will include an explanation as required by Item 1203 of Regulation S-K.

Item 8. Financial Statements and Supplementary Data, page 127

Notes to Consolidated Financial Statements, page 136

Note 21. Oil and Gas Reserves and Related Financial Data (Unaudited), page 201

Standardized Measure of Discounted Future Net Cash Flows, page 205

Comment No. 2:

In response eight, you present the “Previously estimated development costs incurred during the period” for 2008 as $44.5 million which is about 32 percent of the estimated future development costs presented in 2007.  However, this resulted in the development of only 5 percent of your PUD reserves during 2008 as we noted in your response three.  Please explain to us the reasons for the difference between your PUD development expenditures and the resulting PUD volume conversion to developed status.

Company's Response:

In our response eight, we indicated our intent to revise our presentation in future filings.  While preparing the revised presentation to be included in our 2010 Form 10-K, we determined that we inadvertently made an error in the numbers provided in our response eight.  The “Previously estimated development costs incurred during the period” should have been $4.6 million and $14.3 million for 2009 and 2008, respectively.  Following the Staff's calculation methodology, replacing the $44.5 million with the corrected $14.3 million results in 2008 “Previously estimated development costs incurred during the period” representing only about 10% of the estimated future development costs presented in 2007.

We have provided the revised presentation with the correct numbers in our 2010 Form 10-K, filed on February 25, 2011.  The revised presentation, as asterisked in the revised table below, was included in our 2010 Form 10-K as follows:

William Thompson

U.S. Securities and Exchange Commission

March 3, 2011

Page 3 of 3

The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31 (in thousands):

 2009

 2008

 Standardized measure - beginning of year

 $

 179,226

 $

 322,898

 Sales and transfers of oil and gas produced, net of production costs

 (26,836

 )

 (78,342

 )

 Net changes in prices and production costs

 (40,786

 )

 (191,784

 )

 Extensions, discoveries and improved recovery, less related costs

 3,324

 7,961

*

 Changes in future development costs

 83,000

 11,756

*

 Previously estimated development costs incurred during the period

 4,620

 14,306

 Revisions of previous quantity estimates

 (104,556

 )

 (41,861

 )

 Accretion of discount

 19,596

 42,485

 Net change in income taxes

 11,520

 85,218

 Purchases of reserves

 —

 6,592

 Sales of reserves

 —

 (3

 )

 Standardized measure - end of year

 $

 129,108

 $

 179,226

If we can assist with your review of this letter, or if you have any questions on any of the information in this letter, please feel free to call Jeff Berzina, Vice President - Corporate Controller at (605) 721-2346 at any time.

Sincerely,

BLACK HILLS CORPORATION

/s/ ANTHONY S. CLEBERG

Anthony S. Cleberg

Executive Vice President and

Chief Financial Officer

February 16, 2011
 David Emery Chief Executive Officer Black Hills Corporation 625 Ninth Street Rapid City, South Dakota 57701
Re: Black Hills Corporation
Form 10-K for the Fiscal Year Ended December 31, 2009 Filed February 26, 2010 File No. 1-31303

Dear Mr. Emery:
We have reviewed your letter dated January 27, 2011 in response to our comment
letter dated December 28, 2010 and have the following comments.  In some of our comments, we may ask you to provide us with information so we may better understand your
disclosure
.
 Please respond to this letter within te n business days by providing the requested
information, or by advising us when you will provide the requested response.  If you do not believe our comment applie s to your facts and circumstances please tell us why in
your response.
 After reviewing the information you provide  in response to these comments, we
may have additional comments.    Form 10-K for the Fiscal Year Ended December 31, 2009

 Items 7 and 7A. Management’s Discussion and Analysis of Financial Condition and
Results of Operations and Quantitative and Qualitative Disclosures About Market Risk,
page 68
 Oil and Gas, page 88

 1. We note your response to our comment th ree that your development of proved
undeveloped reserves “represented appr oximately 0.7 percent, 5.2 percent, and
8.3 percent of proved undeveloped reserves re flected in our reserve reports at the
beginning of the year for 2009, 2008 and 2007, respectively.”  This development rate – an average of about 5 percent ov er three years – indicates 20+ years are
required to develop your PUD reserves.  Rule 4-10(a)(31)(ii) states “Undrilled
locations can be classified as having unde veloped reserves only if a development

David Emery
Black Hills Corporation February 16, 2011 Page 2
 plan has been adopted indicating that they are scheduled to be drilled within five
years , unless the specific circumstances, ju stify a longer time.”  Item 1203(d) of
Regulation S-K requires that  registrants “Explain th e reasons why material
amounts of proved undeveloped reserves in individual fields or  countries remain
undeveloped for five years or more af ter disclosure as proved undeveloped
reserves.”  Please explain to us the step s you will take to comply with Rule 4-
10(a) and Regulation S-K.
 Item 8. Financial Statements and Supplementary Data, page 127

 Notes to Consolidated Financial Statements, page 136

 Note 21. Oil and Gas Reserves and Relate d Financial Data (Unaudited), page 201

Standardized Measure of Discounted Future Net Cash Flows, page 205
 2. In response eight, you present the “Pre viously estimated development costs
incurred during the period” for 2008 as $44.5 million which is about 32 percent of
the estimated future development costs pr esented in 2007.  However, this resulted
in the development of only 5 percent of your PUD reserves during 2008 as we noted in your response three.  Please expl ain to us the reasons for the difference
between your PUD development expend itures and the resulting PUD volume
conversion to developed status.
   You may contact Anthony Watson, Staff Accountant, at (202) 551-3318 or me at
(202) 551-3344 if you have questions regard ing comments on the financial statements
and related matters.  You may contact Rona ld Winfrey, Petroleum Engineer, at (202)
551-3704 about engineering comments.             S i n c e r e l y ,            /s/ William H. Thompson
William Thompson
        A c c o u n t i n g  B r a n c h  C h i e f

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January 27, 2011

William Thompson

Accounting Branch Chief

Division of Corporation Finance

United States Securities and Exchange Commission

100 F Street, N.E., MS 3561

Washington, D.C.  20002

Re:    Black Hills Corporation (the “Company”, “we”, “our” or “us”)

Form 10-K for Fiscal Year Ended December 31, 2009

Filed February 26, 2010

File No. 1-31303

Dear Mr. Thompson:

The purpose of this letter is to respond to your comments as set forth in your letter of December 28, 2010.  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.

We have carefully considered your comments and our following responses provide the details of how we intend to comply with your comments by enhancing and, in some respects, clarifying our disclosures.  In some limited cases where we believe further revision is unnecessary, we have provided an explanation.

In connection with our response to your comments, we also 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 filing; 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.

William Thompson

U.S. Securities and Exchange Commission

January 27, 2011

Page 2 of 8

FORM 10-K FOR THE FISCAL YEAR ENDED DECEMER 31, 2009

Items 1 and 2. Business and Properties, page 10

Oil and Gas Segment, page 34

Summary Oil and Gas Reserve Data, page 35

Comment No. 1:

Item 1202(a)(7) of Regulation S-K states “Disclose and describe the internal controls the registrant uses in its reserves estimation effort.  In addition, disclose the qualifications of the technical person primarily responsible for overseeing the preparation of the reserves estimates and, if the registrant represents that a third party conducted a reserves audit, disclose the qualifications of the technical person primarily responsible for overseeing such reserves audit.” Please expand your discussion concerning internal controls and describe the qualifications of the in-house technical person responsible for overseeing/liaising with your third party engineer.

Company's Response:

We duly note the Staff's comment to expand our discussion concerning disclosure of our internal controls used in our reserves estimation efforts and the qualifications of the technical people involved in the estimation process as per Item 1202(a)(7) of Regulation S-K.  In future filings, beginning with our Form 10-K for the fiscal year ended December 31, 2010 (“2010 Form 10-K”) to be filed by March 1, 2011, we will enhance our disclosures to include the following:

Preparation of Reserve Estimates

The Company believes it maintains adequate and effective internal controls over the reserve estimation process as well as the underlying data upon which reserve estimates are based.  The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data.  All field and reservoir technical information, which is updated annually, is assessed for validity when the reservoir engineers hold technical meetings with geoscientists, and operations and land personnel to discuss field performance and to validate future development plans.  The Company's internal engineers and our independent reserves engineering firm, Cawley, Gillespie & Associates (CG&A), work independently and concurrently to develop reserve volume estimates.  Current revenue and expense information is obtained from the Company's accounting records, which are subject to external quarterly reviews, annual audits and their own set of internal controls over financial reporting.   All current financial data such as commodity prices, lease operating expenses, production taxes and field commodity price differentials are updated in the reserve database and then analyzed to ensure that they have been entered accurately and that all updates are complete.  The Company's current ownership in mineral interests and well production data are also subject to the aforementioned internal controls over financial reporting, and they are incorporated in the reserve database as well and verified to ensure their accuracy and completeness.  Once the reserve database has been entirely updated with current information, and all relevant technical support material has been assembled, CG&A meets with Company technical personnel in the Company's Denver offices to review field performance and future development plans in order to further verify their validity.  Following these reviews the reserve database, including updated cost, price and ownership data, is furnished to CG&A so that they can prepare their independent reserve estimates and final report.  Access to the Company's reserve database is restricted to specific members of the reservoir engineering department.

William Thompson

U.S. Securities and Exchange Commission

January 27, 2011

Page 3 of 8

CG&A is a Texas Registered Engineering Firm.  Our primary contact at CG&A is Mr. Zane Meekins.  Mr. Meekins has been practicing consulting petroleum engineering at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas and has over 22 years of practical experience in petroleum engineering, with over 20 years experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a BS in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Our Manager of Planning and Analysis is the technical person primarily responsible for overseeing our reserve estimates.  He has over 30 years of Exploration and Production industry experience as a geologist.  He has over 20 years working closely with internal and third party qualified reserve estimators in major and mid-sized oil and gas companies.  He holds a Bachelor of Science degree in Geology and an MBA.

Acreage, page 38

Comment No. 2:

We note the disclosure of 261 thousand net undeveloped acres (64% of the total) to your ownership. Please expand the presentation of your undeveloped acreage to discuss the near term expiration of any material undeveloped acreage as contemplated in Item 1208(b) of Regulation S-K.

Company's Response:

We note the requirements of Item 1208(b) of Regulation S-K requiring, if material, disclosure of the minimum remaining terms of leases and concessions associated with our undeveloped acreage.  In preparation of our 2009 Form 10-K, we reviewed the minimum remaining terms of our leases on undeveloped acreage noting that approximately 4 percent and 5 percent of our 260,677 net acres could expire in 2010 and 2011, respectively.  At that time, we determined that the amounts were not material to the overall presentation within our 2009 Form 10-K.  Consistent with the Staff's comment, we will modify our disclosure in future filings, beginning with our 2010 Form 10-K, to include, if material, the minimum remaining terms of leases as contemplated in Item 1208(b) of Regulation S-K.

William Thompson

U.S. Securities and Exchange Commission

January 27, 2011

Page 4 of 8

Items 7 and 7A. Management's Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk, page 68

Oil and Gas, page 88

Comment No. 2:

Please expand your discussion here to disclose the information pertaining to your proved undeveloped reserves as required by Item 1203 of Regulation S-K. Note that changes due to conversion to proved developed are required by 1203(b) as well as those due to revisions, acquisition/divestiture, drilling, and improved recovery.

Company's Response:

Within our 2009 Form 10-K, discussion of our proved undeveloped reserves is included in two sections of the document.  First within the “Summary Oil and Gas Reserve Data” beginning on page 35 and second within “Reserves” beginning on page 202.  In drafting our disclosures, we considered the requirements of Item 1203 of Regulation S-K.  Specifically, regarding the requirements of Item 1203(b), we concluded that the conversion of proved undeveloped reserves to proved developed reserves was not material to the presentation.  If we had separately identified such conversions, they would have represented approximately 0.7 percent, 5.2 percent, and 8.3 percent of proved undeveloped reserves reflected in our reserve reports at the beginning of the year for 2009, 2008 and 2007, respectively.

While we drafted our disclosures to meet the requirements of Item 1203, we duly note the Staff's comment and will enhance our disclosures as required by Item 1203 of Regulation S-K, in future filings beginning with our 2010 Form 10-K.  To assist in identifying the information specific to our proved undeveloped reserves, the enhanced disclosures will include a separate section on our proved undeveloped reserves where we will discuss material activities required by Item 1203 of Regulation S-K.

Comment No. 3:

Please expand your discussion to include the information pertaining to your product delivery commitments, if any, as specified in Item 1207 of Regulation S-K.  If you have none, please so state.

Company's Response:

We have no product delivery commitments for our oil and gas activities.  We will include a statement to clarify this within our future filings.

William Thompson

U.S. Securities and Exchange Commission

January 27, 2011

Page 5 of 8

Item 8. Financial Statements and Supplementary Data, page 127

Notes to Consolidated Financial Statements, page 136

Note 1. Business Description and Summary of Significant Accounting Policies, page 136

Legal Costs, page 142

Comment No. 4:

We note that you record litigation settlement accruals net of probable insurance recoveries. Please tell us how you meet the right of set-off criteria in ASC 210-20-45-1.

Company's Response:

In review of the Staff's comment, we have determined that we have not met the right of set-off criteria in ASC 210-20-45-1.  Accordingly, our probable insurance recoveries should not have been netted against our litigation settlement accruals within our balance sheet presentation.

If we had not offset our probable insurance recoveries against our litigation settlement accruals, based upon subsequent settlements and amounts paid by insurance, at December 31, 2009 and 2008, both our total assets and total liabilities would have increased by approximately $3,387,000 and $6,965,000, respectively.  For each balance sheet date, these amounts would represent less than 0.30% of total assets and liabilities.  Additionally, we reviewed qualitative factors of materiality including the impact, if any, on loan and regulatory covenants, earnings, management compensation, et al.  Through this analysis, we believe these amounts to be immaterial to our overall financial statement presentation, both quantitatively and qualitatively.

We confirm that in the future, unless all of the stringent criteria of ASC 210-20 are met, we will not net probable insurance recoveries against litigation settlement accruals, and we will change the description of our accounting policy in Form 10-K Footnote (1) Business Description and Summary of Significant Accounting Policies, commencing with our 2010 Form 10-K.

Note 21. Oil and Gas Reserves and Related Financial Data (Unaudited), page 201

Comment No. 5:

We note that you do not disclose information about management's evaluation of capitalized exploratory well costs.  Please tell us what consideration you gave to providing the disclosures required by ASC 932-235-50-16.

Company's Response:

As noted within our Significant Accounting Policies on page 139, we account for our oil and gas activities under the full cost method.  Due to our utilization of the full cost method, our exploratory well costs are capitalized along with our other costs of developing oil and gas reserves.  This “full cost pool" is then amortized over a units-of-production method.  Since we do not make separate charges to expense for exploratory well costs, we did not view the specific disclosures required by ASC 932-235-50-16 to be relevant to the understanding of our oil and gas activities.

William Thompson

U.S. Securities and Exchange Commission

January 27, 2011

Page 6 of 8

Standardized Measure of Discounted Future Net Cash Flows, page 205

Comment No. 6:

It appears you have included future revenue from the Newcastle Gas Processing Plant in the future cash inflows of the standardized measure. Please tell us if these revenues are derived solely from processing gas production volumes in which you have a revenue interest.  If they are not, explain your reasons for claiming such third party processing revenues.  We may have further comment.

Company's Response:

The majority of the gas production volumes going through the Newcastle Gas Processing Plant, approximately 65%, are volumes in which we have a revenue interest.  While the gas plant revenues are not derived solely from processing volumes in which we have a revenue interest, we have included the revenue from our 44.7% plant ownership in the future cash inflows from our oil and gas properties due to the plant's close association with our operating properties in that field and the interconnected nature of the operations.

In reviewing the Staff's comment, we have determined that only the plant revenues associated with processing volumes in which we have a revenue interest should be included in our future cash flow assumptions.  Of the $519.9 million in future cash inflows and $207.8 million of future production costs reflected in our 2009 standardized measure, approximately $6.5 million and $3.6 million, respectively, is attributable to volumes processed that we do not have a revenue interest in.  If the amounts related to third party volumes were excluded from our standardized measure, the discounted future net cash flows for each period presented would have been lower by less than 1%, which we do not consider material.  Beginning with our 2010 Form 10-K, we will exclude all cash flows associated with volumes processed by the plant for third parties.

Comment No. 7:

Please tell us the portion of your proved liquid reserves that are NGLs and the NGL prices you used in proved reserve estimation.  Explain the reason you did not disclose NGL reserves separately from crude oil.

Company's Response:

We do not reflect NGLs in our proved liquid reserve estimates because our proved reserve estimates are based on wet gas volumes measured at the wellhead.  These volumes are used to forecast future production then shrunk to determine our proved gas reserve estimates.  As part of our proved reserve estimation, the future cashflow of the reserves reflects the value of NGLs through the price used for wellhead volumes of natural gas, which reflects the prices of both residue gas and NGLs.  NGL pricing is based on a percentage of the posted crude oil price, depending on the NGL product components in each area evaluated.

William Thompson

U.S. Securities and Exchange Commission

January 27, 2011

Page 7 of 8

Comment No. 8:

We note the omission of the line item “Previously estimated development costs incurred during the period” in the principal changes to the standardiz

December 28, 2010
 David Emery Chief Executive Officer Black Hills Corporation 625 Ninth Street
Rapid City, South Dakota 57701

Re: Black Hills Corporation
Form 10-K for the Fiscal Year Ended December 31, 2009 Filed February 26, 2010 File No. 1-31303

Dear Mr. Emery:
We have reviewed your filing and have the following comments.  In some of our
comments, we may ask you to provide us with  information so we may better understand your
disclosure.
 Please respond to this letter within te n business days by providing the requested
information, or by advising us when you will provide the requested response.  If you do not believe our comments apply to your facts and circ umstances please tell us  why in your response.
 After reviewing the information you provide in response to these comments, we may
have additional comments.  Form 10-K for the Fiscal Year Ended December 31, 2009

 Items 1 and 2.  Business and Properties, page 10

 Oil and Gas Segment, page 34

 Summary Oil and Gas Reserve Data, page 35

 1. Item 1202(a)(7) of Regulation S-K states “Discl ose and describe the internal controls the
registrant uses in its reserves estimation effort .  In addition, disclose the qualifications of
the technical person primarily responsible fo r overseeing the preparation of the reserves
estimates and, if the registrant represents that a third party conducted a reserves audit, disclose the qualifications of  the technical person primarily  responsible for overseeing
such reserves audit.”  Please expand your discussion concerning internal controls and
describe the qualifications of the in -house technical person responsible for
overseeing/liaising with your third party engineer.

David Emery
Black Hills Corporation December 28, 2010 Page 2  Acreage, page 38

 2. We note the disclosure of 261 thousand net unde veloped acres (64% of the total) to your
ownership.  Please expand the presentation of  your undeveloped acreage to discuss the
near term expiration of any material unde veloped acreage as contemplated in Item
1208(b) of Regulation S-K.
 Items 7 and 7A.  Management's Discussion and An alysis of Financial Condition and Results of
Operations and Quantitative And Qualitative Disclosures About Market Risk, page 68
 Oil and Gas, page 88

 2. Please expand your discussion here to disclose  the information pertaining to your proved
undeveloped reserves as requi red by Item 1203 of Regulation S-K.  Note that changes
due to conversion to proved developed are required by 1203(b) as well as those due to
revisions, acquisition/dive stiture, drilling, and improved recovery.
 3. Please expand your discussion to include th e information pertaining to your product
delivery commitments, if any, as specified in  Item 1207 of Regulation S-K.  If you have
none, please so state.

Item 8.  Financial Statements and Supplementary Data, page 127

 Notes to Consolidated Financial Statements, page 136

 Note 1.  Business Description and Summary of  Significant Accounting Policies, page 136

 Legal Costs, page 142

4. We note that you record litigation settlem ent accruals net of probable insurance
recoveries.  Please tell us how you meet the ri ght of set-off criteria in ASC 210-20-45-1.
 Note 21.  Oil and Gas Reserves and Rela ted Financial Data (Unaudited), page 201

 5. We note that you do not disclose informa tion about management’s evaluation of
capitalized exploratory well costs.  Please tell us what consideration you gave to
providing the disclosures re quired by ASC 932-235-50-16.
 Standardized Measure of Discounted Future Net Cash Flows, page 205

 6. It appears you have included future revenue from the Newcastle Gas Processing Plant in
the future cash inflows of the standardized m easure.  Please tell us if these revenues are
derived solely from processing gas produc tion volumes in which you have a revenue
interest.  If they are not, explain your reasons for claimi ng such third party processing
revenues.  We may have further comment.

David Emery
Black Hills Corporation December 28, 2010 Page 3  7. Please tell us the portion of your proved liq uid reserves that are NGLs and the NGL
prices you used in proved reserve estimati on.  Explain the reason you did not disclose
NGL reserves separately from crude oil.
 8. We note the omission of the line item “Previ ously estimated development costs incurred
during the period” in the principal changes to the standardized measure as required by
FASB ASC subparagraph 932-10-65 -1.  Please revise your presentation to comply with
ASC 932.
 Exhibit 99

 9. We note the omission of items prescribed by Item 1202(a)(8) of Regul ation S-K.  Please
procure a third party reserv e report that includes:

 (i) The purpose for which the report was prepared and for whom it was prepared;
 (ii) The date on which the report was completed;
 (iv) Discussion of the sources of  production and pressure data;
 (v) Adjusted average product prices (after  application of differentials for quality,
transportation, etc.) including NGLs a nd discussion of COPAS charges;
 (vi) A discussion of the possibl e effects of regulati on on the ability of the registrant to
recover the estimated reserves;
 (viii) A statement that the third party ha s used all methods and procedures as it
considered necessary under the circum stances to prepare the report; and
 (x) The third party’s responsible technical person’s qualifications.
 We urge all persons who are responsible for th e accuracy and adequacy of the disclosure
in the filing to be certain that the filing include s the information the Securities Exchange Act of
1934 and all applicable Exchange Act rules requir e.  Since the company and its management are
in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy
and adequacy of the disclosures they have made.
In responding to our comments, please provi de a written statement from the company
acknowledging that:
 the company is responsible for the adequacy an d accuracy of the disclo sure 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 filing; 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.

In addition, please be advise d that the Division of Enfo rcement has access to all
information you provide to the sta ff of the Division of Corporati on Finance in our review of your
filings or in response to our  comments on your filings.

David Emery
Black Hills Corporation December 28, 2010 Page 4

     You may contact Anthony Watson, Staff Accountant, at (202) 551-3318 if you have
questions regarding comments on the financial statem ents and related matters.   Please contact me
at (202) 551-3344 with a ny other questions.
          S i n c e r e l y ,
William Thompson
        A c c o u n t i n g  B r a n c h  C h i e f

Mail Stop 3561
     October 19, 2009
 David R. Emery Chairman, President and Chief Executive Officer Black Hills Corporation 625 Ninth Street Rapid City, SD 57701
  Re: Black Hills Corporation
   Form 10-K for Fiscal Year Ended December 31, 2008
   Filed March 2, 2009    File No. 001-31303
Dear Mr. Emery:

We have completed our review of your Form 10-K and have no further comments
at this time.

Sincerely,
    H. Christopher Owings
Assistant Director

CORRESP
1
filename1.htm

    secletter_sept30-09.htm

September 30, 2009

H. Christopher Owings

Assistant Director

Division of Corporation Finance

United States Securities and Exchange Commission

100 F Street, NE

Washington, D.C.  20549-7010

Re:

Black Hills Corporation

Form 10-K for Fiscal Year Ended December 31, 2008

Filed March 2, 2009

Proxy Statement on Schedule 14A

Filed April 7, 2009

Form 10-Q for the Fiscal Quarter Ended March 31, 2009

Filed May 11, 2009

Form 10-Q for the Fiscal Quarter Ended June 30, 2007

Filed August 10, 2007

File No. 001-31303

Dear Mr. Owings:

The purpose of this letter is to respond to your comments as set forth in your letter of September 8, 2009.  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.

We have carefully considered your comments and, as requested in your letter, we acknowledge that we intend to comply with your comments in all future filings, as applicable.  Our following responses provide the details of how we intend to comply with your comments by enhancing and, in some respects, clarifying our disclosures.  In
some limited cases where we believe further revision is unnecessary, we have provided an explanation.

In connection with our response to your comments, we also 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 filing; 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.

H. Christopher Owings

U.S. Securities and Exchange Commission

September 30, 2009

Page 2 of 14

FORM 10-K FOR FISCAL YEAR ENDED DECEMER 31, 2008

Items 7 and 7A. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures about Market Risk, page 59

Critical Accounting Policies, page 83

Comment No. 1:

Please revise to describe the material implications of uncertainties associated with the methods, assumptions and estimates underlying your critical accounting measurements that have had or that you reasonably expect will have a material impact on financial condition and operating performance and on the comparability
of reported information among periods.  Your disclosures should supplement, not duplicate, the accounting policies disclosed in the notes to the financial statements.  For example, you should analyze to the extent material, such factors as how you arrived at each estimate, how accurate the estimate/assumption has been in the past, how much the estimate/assumption has changed in the past and whether the estimate/assumption is reasonably likely to change in the future.  We would expect
you to provide quantitative as well as qualitative disclosure when quantitative information is reasonably available and to provide greater insight into the quality and variability of information regarding financial condition and operating performance.  Also, since each critical accounting estimate and related assumptions are based on matters that are uncertain or difficult to measure, you should analyze and disclose their specific sensitivity to change, based on other outcomes that are reasonably likely
to occur and would have a material effect.  Please refer to Item 303(a)(3)(ii) of Regulation S-K as well as the Commission’s Guidance Regarding Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Company’s Response:

We considered Item 303 of Regulation S-K as well as section five of the Commission’s Interpretive Release on Management’s Discussion and Analysis of Financial Condition and Results of Operations, and we attempted to draft our disclosures to meet the requirements of this guidance.  However, we duly note the Staff’s
comment and will prospectively enhance our disclosures as noted below.

Regarding our Critical Accounting Policies “Impairment of Long-Lived Assets,” “Full Cost Method of Accounting for Oil and Gas Activities,” “Oil
and Natural Gas Reserve Estimates,” “Risk Management Activities,” “Contingencies” and “Valuation of Deferred Tax Assets,” we will enhance our disclosures of the uncertainties inherent in our estimates, the variability that could result from changes in key assumptions that are used to develop our
estimates, the accuracy of past estimates and the likelihood of a change in the estimate in the future.  In addition, we will include appropriate sensitivity analysis where meaningful and reasonably available.  We will also disclose, when appropriate, other reasonably available quantitative information, including historical information concerning our assumptions and their susceptibility to change, when there are highly subjective or complex judgments made by management or other uncertainties
associated with those events or calculations.

Examples of disclosure enhancements that we will consider, as relevant and meaningful at the time of the filing, include but are not limited to:  details of capital expenditures, cost of capital, growth rates in revenues and costs used in our impairment models and sensitivities around these assumptions; the impact of a percentage
decline in commodity prices and the effect it would have on our cost ceiling under the full-cost method of accounting.  Actual disclosure enhancements will be developed and analyzed prior to our Form 10-K filing for 2009.

We note to the Staff that within certain estimates, particularly our “Oil and Natural Gas Reserve Estimates” policy, we are faced with estimations and models that rely on a large number of variables that are interrelated and are difficult to examine independently.  If
a sensitivity analysis were carried out on any one variable while keeping the others constant, we believe that it likely would not yield meaningful information precisely because of the high correlation (positive or negative) between these variables.

Regarding our Critical Accounting Policy, “Pension and Postretirement Benefits,” we believe the disclosures within our 2008 Form 10-K provided the quantitative information and sensitivity analysis sought by the Staff.

H. Christopher Owings

U.S. Securities and Exchange Commission

September 30, 2009

Page 3 of 14

The interpretative guidance included in “Commission Guidance Regarding Management’s Discussion and Analysis of Financial Condition and Results of Operations” on Critical Accounting Estimates discusses “accounting estimates and assumptions that may be material due to the levels of subjectivity and judgment necessary
to account for highly uncertain matters or the susceptibility of such matters to change.”  After further consideration and in an effort to not obscure the impact of our truly critical estimates, we intend in future filings to remove from our list of Critical Accounting Policies the “Regulatory Accounting” and “Unbilled Utility Revenues” policies.  We
believe that the assumptions utilized in providing the estimates associated with these particular accounting policies are not as subjective, highly uncertain or susceptible to change as would rise to the level of a “Critical Accounting Policy.”

Non Regulated Trading Activities, page 103

Comment No. 2:

We note your disclosure of the non-GAAP measure of the fair value of your energy marketing position on page 103.  Please disclose the reasons why you believe the presentation of the non-GAAP measure provides useful information to investors.  Refer to Item 10(e)(1)(i)(B) of Regulation S-K.

Company’s Response:

The non-GAAP measure on page 103 is presented because we believe disclosing the fair value of all of our forward positions as of the balance sheet date provides a more comprehensive view for our investors of the value created or lost within our Energy Marketing portfolio during each period and thus a better understanding of these activities
than would be presented by GAAP measures alone.  We believe we explained the usefulness of the non-GAAP measure within the paragraphs preceding the non-GAAP measure on page 102.  However, in future filings we will enhance the language to connect these paragraphs to the non-GAAP measure as well as provide a footnote to the table with the non-GAAP measure to further highlight the usefulness that the measure provides the investor.

Report of Independent Registered Public Accounting Firm, page 112

Comment No. 3:

Please confirm to us that you received a manually signed copy of the audit opinion from the auditors.  In addition, please include the conforming signature in future filings as required by Regulation S-T.

Company’s Response:

We confirm that the Company received a manually signed audit opinion letter from our auditors.  In the future, we will include a conformed signed audit opinion in our filings as required by Regulation S-T.

H. Christopher Owings

U.S. Securities and Exchange Commission

September 30, 2009

Page 4 of 14

Consolidated Statements of Common Stockholder’s Equity and Comprehensive Income, page 116

Comment No. 4:

Please provide a more detailed analysis of the changes in each caption of stockholders’ equity in future filings.  The analysis should present all significant reconciling items, such as share-based compensation, tax effects of share-based compensation, purchases of securities, sales of securities
and other issuances of securities.  In addition, please include a reconciliation of the beginning and ending shares of common stock and treasury stock.  Refer to Rule 3-04 of Regulation S-X.

Company’s Response:

We note the requirements of Rule 3-04 of Regulation S-X.  Although we have disclosed information on common stock in Note 10 of the Notes to our Consolidated Financial Statements, we will include, in all material respects, additional analysis of the changes in each caption of stockholders’ equity and a reconciliation
of the beginning and ending shares of common stock and treasury stock in our Statement of Stockholders’ Equity in future 10-K filings.

Note (1) Business Description and Summary of Significant Accounting Policies, page 117

Regulatory Accounting, page 123

Comment No. 5:

Please disclose regulatory assets not earning a return and their remaining recovery periods.  Refer to paragraph 20 of SFAS 71.

Company’s Response:

Paragraph 20 of SFAS 71 states that a regulator may permit an enterprise to include a cost that would be charged to expense by an unregulated enterprise as an allowable cost over a period of time by amortizing that cost for rate-making purposes without providing a return during the recovery period.  If recovery of such major
costs is provided without a return on investment during the recovery period, Paragraph 20 requires that the enterprise disclose the remaining amounts of such assets and the remaining recovery period applicable to them.  Paragraph 34 of SFAS 71 requires the disclosures prescribed in Paragraph 20 if the amounts being recovered without a return on investment are material.

We will include additional disclosures, as modeled below, in our future 10-K filings regarding our regulatory assets, which will outline remaining recovery periods and amounts being recovered without a return.  As of December 31, 2008, the Company recovers the cost of our regulatory assets but does not earn a return on them.  An
example is as follows (in thousands):

Balance at

December 31,

Recovery Period

2008

Regulatory Assets:

Deferred energy and fuel costs adjustments

Less than one year

$
32,198

Deferred gas cost adjustment and gas price derivative

Less than one year

25,364

AFUDC

Up to seventeen years

8,719

Employee benefit plans

Two to thirteen years

98,414

Environmental

To be determined

2,406

Asset retirement obligations

Up to 65 years

2,598

Bond issue costs

Up to 15 ½ years

4,121

Other – Rate Case expenses

Up to five years

1,728

Other – Unamortized loss on reacquired debt

Up to 15 ½ years

2,628

Other

919

Total Regulatory Assets

$
179,095

H. Christopher Owings

U.S. Securities and Exchange Commission

September 30, 2009

Page 5 of 14

Note (4) Investments in Associated Companies, page 139

Comment No. 6:

Please tell us the nature and amounts of other items included in the investments line item in the consolidated balance sheets.

Company’s Response:

The items included in the investments line item in the consolidated balance sheets are our equity method investments of approximately $11.5 million (including those disclosed in Note 4), cash surrender value of life insurance policies of approximately $8.6 million, cost-method investments of approximately $2.3 million, and treasury
notes of approximately $0.4 million.  The investments line item on our December 31, 2008 balance sheet represents 0.67 percent of our total asset balance and therefore we do not believe the balances are significant enough to warrant additional footnote disclosure.

In the past we included the additional disclosure provided in Note 4 due to the fact that the value of our investments in associated companies used to be more material and there was a potential to show significant mark-to-market adjustments for our equity method power fund investments as disclosed.  As these funds have been
liquidating their assets over the last few years our investment balance in the funds and their potential to have significant mark-to-market adjustments has been reduced.  Accordingly, we no longer consider these investments to be significant to our business and are considering removing them from our note disclosures in future filings.

Note (10) Common Stock, page 145

Equity Compensation Plans, page 147

Comment No. 7:

Please tell us your rationale for using a blend of historical and implied volatility of your stock price in 2006 as opposed to historical and implied volatility over a period commensurate with the expected or contractual term of the awards in estimating the fair value of stock-based awards granted in 2006.  Refer
to Question 2 of SAB Topic 14:D.1.

Company’s Response:

We used a blend of historical and implied volatility of our stock price over the expected life of the awards, rather than just the year 2006.  The language “in 2006” was referring to the column heading “2006” in the table.  Footnote 3 to the table on page 147 of the 2008 Form 10-K would have
been more clear if the words “in 2006” were omitted.  The reason the words “in 2006” were specified was in 2006 we changed to a blend of historical and implied volatility whereas in prior years we only used the historical volatility.  The language “in 2006” was a carryover from the prior year when in the 2007 Form 10-K the footnote stated - “Based on a blended historical and implied volatility of the Company’s stock price in 2006 and historical
volatility only in 2005.”  We will clarify the language in future filings, as applicable.

H. Christopher Owings

U.S. Securities and Exchange Commission

September 30, 2009

Page 6 of 14

Dividend Restrictions, page 150

Comment No. 8:

We note that you are required to maintain a minimum net worth under the most restrictive covenants contained in your credit facility agreements.  As such, please disclose the amount of retained earnings or net income restricted or free of restrictions.  Refer to Rule 4-08(e)(1) of Regulation
S-X.  Also, it appears your consolidated subsidiaries are restricted from transferring funds to you in the form of loans, advances or cash dividends under the terms of your debt agreements and orders approved by regulatory agencies.  As such, tell us the amount of the restricted net assets of your consolidated subsidiaries and how you compute the amount.  If the restricted net assets of your consolidated subsidiaries exceed 25 pe

Mail Stop 3561
     September 8, 2009
 David R. Emery Chairman, President and Chief Executive Officer Black Hills Corporation 625 Ninth Street Rapid City, SD 57701
  Re: Black Hills Corporation
   Form 10-K for Fiscal Year Ended December 31, 2008
   Filed March 2, 2009   Proxy Statement on Schedule 14A    Filed April 7, 2009    Form 10-Q for the Fisc al Quarter Ended March 31, 2009
   Filed May 11, 2009    Form 10-Q for the Fisc al Quarter Ended June 30, 2007
   Filed August 10, 2007
   File No. 001-31303

Dear Mr. Emery:

We have reviewed your filings and ha ve the following comments.  You should
comply with the comments in all future filings, as applicable.  Please confirm in writing that you will do so, and also explain to us in  detail sufficient for an understanding of your
disclosure how you intend to comply by providing us with your proposed revisions.  If you disagree, we will consider your explanation as to why our comments are inapplicable
or a revision is unnecessary.  Please be as detailed as necessary in your explanation.
After reviewing this information, we may raise additional comments.
 Please understand that the purpose of our re view process is to assist you in your
compliance with the applicable disclosure requirements and to enhance the overall disclosure in your filings.  We look forward to working with you in these respects.  We
welcome any questions you may have about our comments or any other aspect of our review.  Feel free to call us at the telephone numbers listed at the end of this letter.

David R. Emery
Black Hills Corporation September 8, 2009
Page 6  Form 10-K for Fiscal Year Ended December 31, 2008

 Items 7 and 7A. Management’s Discussion and Analysis of Financial Condition and
Results of Operations and Quantitative and Qualitative Disclosures about Market Risk,
page 59

Critical Accounting Policies, page 83

1. Please revise to describe the material implications of uncertainties  associated with
the methods, assumptions and estimate s underlying your critical accounting
measurements that have had or that you reasonably expect will have a material
impact on financial conditi on and operating performan ce and on the comparability
of reported information among periods.  Y our disclosures should supplement, not
duplicate, the accounting policies disclo sed in the notes to the financial
statements.  For example, you should analyze to the extent material, such factors
as how you arrived at each estimate, how accurate the estimate/assumption has
been in the past, how much  the estimate/assumption has changed in the past and
whether the estimate/assumption is reasonably likely to change in the future.  We
would expect you to provide quantitative as  well as qualitativ e disclosure when
quantitative information is reasonably availa ble and to provide greater insight into
the quality and variabilit y of information regardi ng financial condition and
operating performance.  Also, since each critical accounting estimate and related
assumptions are based on matters that ar e uncertain or difficult to measure, you
should analyze and disclose their specific  sensitivity to change, based on other
outcomes that are reasonably likely to o ccur and would have a material effect.
Please refer to Item 303(a)(3)(ii) of Re gulation S-K as well as the Commission’s
Guidance Regarding Management’s Disc ussion and Analysis of Financial
Condition and Results of Operations.

Non Regulated Trading Activities, page 103

2. We note your disclosure of the non-GAAP measure of the fair value of your
energy marketing position on page 103.  Please disclose the reasons why you
believe the presentation of the non-GAAP m easure provides useful information to
investors.  Refer to Item 10(e )(1)(i)(B) of Regulation S-K.

Report of Independent Registered Public Accounting Firm, page 112

3. Please confirm to us that you received a manually signed copy of the audit opinion from the auditors.  In addition, pl ease include the conf orming signature in
future filings as required by Regulation S-T.

David R. Emery
Black Hills Corporation September 8, 2009
Page 6  Consolidated Statements of Common Stockhol der’s Equity and Comprehensive Income,
page 116

4. Please provide a more detailed analysis of the changes in each caption of stockholders’ equity in future filings.  The analysis should present all significant reconciling items, such as share-based compensation, tax effects of share-based
compensation, purchases of securities, sale s of securities and other issuances of
securities.  In addition, please include a reconciliation of the beginning and ending
shares of common stock and treasury stock.  Refer to Rule 3-04 of Regulation S-X.

Note (1)  Business Description and Summar y of Significant Accounting Policies, page
117

Regulatory Accounting, page 123

5. Please disclose regulatory assets not earning a return and their remaining recovery periods. Refer to paragraph 20 of SFAS 71.
 Note (4)  Investments in A ssociated Companies, page 139

6. Please tell us the nature and amounts of other items included in the investments line item in the consolidated balance sheets.
 Note (10)  Common Stock, page 145

Equity Compensation Plans, page 147

7. Please tell us your rationale for using a blend of historical and implied volatility of your stock price in 2006 as opposed to historical a nd implied volatility over a
period commensurate with the expected or  contractual term of the awards in
estimating the fair value of stock-based awards granted in 2006.  Refer to Question 2 of SAB Topic 14:D.1.

Dividend Restrictions, page 150

8. We note that you are required to maintain a minimum net worth under the most
restrictive covenants containe d in your credit facility ag reements.  As such, please
disclose the amount of retained earnings or net income restricted or free of
restrictions.  Refer to Rule 4-08(e)(1) of Regulation S-X.  Also, it appears your
consolidated subsidiaries are restricted from transf erring funds to you in the form
of loans, advances or cash dividends unde r the terms of your de bt agreements and
orders approved by regulatory agencies.  As such, tell us the amount of the
restricted net assets of your consolidated subsidiari es and how you compute the
amount.  If the restricted ne t assets of your consolidated subsidiaries exceed 25%
of consolidated net assets, please describe  the nature of the restrictions on the

David R. Emery
Black Hills Corporation September 8, 2009
Page 6
ability of consolidated subsidiaries to transfer funds to you, disclose the amount
of their restricted net assets as of the end of the most recently completed fiscal
year and provide Schedule I.  Refer to  Rules 4-08(e)(3) and 5-04 of Regulation S-
X.
 Note (14)  Income Taxes, page 152

9. Please tell us what deferred taxes associ ated with the IPP tr ansaction and property
basis differences in the table at the top of page 154 (which reconciles the change
in the net deferred income tax liability  to deferred income tax expense from
continuing operations) represent and how  the amounts are classified in the
financial statements.  In addition, please te ll us how to reconcile the change in the
net deferred income tax liability to the am ount reported in the statements of cash
flows.

10. Please tell us how the liability for unrecogni zed tax benefits disc losed in the table
on page 155 is classified in your conso lidated balance sheets.  In addition , please
show us how to reconcile unrecognized tax benefits to the liability for unrecognized tax
benefits disclosed in the table of contractua l obligations and commitments on page
96.

Exhibits

11. Please tell us why you are not required to  file the consent of Ralph E. Davis
Associate, Inc. in regard to the 2006 re serve report disclosed in Note (22)
beginning on page 175.
 Exhibit 23.1

12. Please confirm to us that you received a manually signed copy of the consent from the auditors.  In ad dition, please include the conf orming signature in future
filings as required by Regulation S-T.
 Proxy Statement on Schedule 14A

Components of Executive Compensation, page 13

13. We note that you disclose the percentage  of each component of total target
compensation in 2008.  Disclose whether these amounts provided total direct
compensation at the median of the market , as you indicate on page 12 is your
goal.

David R. Emery
Black Hills Corporation September 8, 2009
Page 6  Long-Term Incentive, page 16

14. We note the disclosure you provide at the top of page 17, where you provide a
table of the approved long-term co mpensation amounts and transaction
completion bonuses.  Please revise to disc uss how these amounts correlate to the
amounts you disclose in the table at the bot tom of the same page with respect to
restricted shares granted.
 Security Ownership of Management and Principal Shareholders, page 41

15. We note your disclosure of the holding s of Barclays Global Investors, NA,
Barclays Global Fund Advisors and Barclays Global Investors, Ltd . et al.   Please
provide the full name of principal sharehol ders and avoid terms like “et al.”  In
this regard, we could not locate th e Schedule 13G filed on February 5, 2009
referenced in your foot note.  Please advise.

Form 10-Q for the Fiscal Quarter Ended March 31, 2009

16. We note your footnote on page 5 of Exhi bit 10, the Third Amended and Restated
Credit Agreement, stating that “The Sche dules and Exhibits have been excluded
from this filing and will be furnished to the SEC upon request .”  We also note
similar language on  page  V of Exhibit 10.3, the Credit Agreement dated as of
May 7, 2007, filed with your Form 10-Q for the fiscal quarter ended June 30, 2007.  With your next current or periodic re port, please file complete copies of
these agreements, including all exhibits , attachments and schedules to these
agreements or advise why you are not requir ed to file these documents.  Please
also acknowledge that in future filings  you will provide these documents with
your exhibits rather than consenti ng to provide them upon our request.

*****

 As appropriate, please respond to these co mments within 10 business days or tell
us when you will provide us with a response.  Detailed cover letters gr eatly facilitate our
review.  Please understand that we may have  additional comments after reviewing your
responses to our comments.    We urge all persons who are responsi ble for the accuracy an d adequacy of the
disclosure in the filings to be certain that the filings includes all information required under the Securities Exchange Act of 1934 and that they have provided all information
investors require for an informed invest ment decision.  Since the company and its
management are in possession of all facts re lating to a company’s disclosure, they are
responsible for the accuracy and adequacy of the disclosures they have made.
  In connection with responding to our comments, please provide, in writing, a statement from the company acknowledging that:

David R. Emery
Black Hills Corporation September 8, 2009 Page 6
  ‚ 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 filing; 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.

In addition, please be advise d that the Division of Enfo rcement has access to all
information you provide to the staff of the Divi sion of Corporation Fi nance in our review
of your filing or in response to our comments on your filing.
You may contact Tony Watson, Account ant, at (202) 551-3318 or William
Thompson, Accounting Branch Chief, at (202)  551-3344, if you have questions regarding
comments on the financial statements and related matters.  Please contact Scott Anderegg, Staff Attorney, at (202) 551-3342, or  Mara Ransom, Legal Branch Chief, at
(202) 551-3264 or me at (202) 551- 3720 with any other questions.

Sincerely,
    H. Christopher Owings
Assistant Director

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-0405

       DIVISION OF
CORPORATION FINANCE

Mail Stop 3561

October 19, 2007

Mr. Mark T. Thies
Executive Vice President & Chief Financial Officer
Black Hills Corporation
625 Ninth Street
Rapid City, South Dakota 57701

 Re: Black Hills Corporation
   Form 10-K for Fiscal Year Ended December 31, 2006
Filed March 1, 2007
Form 10-Q for Fiscal Quarter Ended March 31, 2007
Filed May 10, 2007
  File No. 1-31303

Dear Mr. Thies:

 We have completed our review of your Form 10-K and related filings and have no
further comments at this time.

        S i n c e r e l y ,

         William Thompson
         B r a n c h  C h i e f

CORRESP
1
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            August 24, 2007

Mr. William Thompson

Branch Chief

Division of Corporation Finance

United States Securities and Exchange Commission

100 F Street, NE

Washington, D.C. 20549-7010

            Re:

            Black Hills Corporation (the “Company”, “we” or “our”)

Form 10-K for Fiscal Year Ended December 31, 2006

Filed March 1, 2007

Form 10-Q for Fiscal Quarter Ended March 31, 2007

Filed May 10, 2007

File No. 1-31303

Dear Mr. Thompson:

The purpose of this letter is to respond to your comments as set forth in your letter of July 17, 2007.  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.

We have considered carefully your comments and are willing to enhance and, in some respects, clarify our disclosures as set forth in the responses below.  However, because we do not believe that our investors would consider any of these changes to be significant to an investment decision in the Company, we do not believe that the staff’s comments should require an amendment to our 2006 Form 10-K or to our first quarter 2007 Form 10-Q.  We respectfully request that we be allowed to include the requested information in future filings as indicated in the responses below.  If this is acceptable to the staff, we will modify our future filings accordingly.  Prior to providing this response letter to you, we filed our second quarter 2007 Form 10-Q with the SEC on August 9, 2007.  To the extent that your comments were applicable to that interim filing, we incorporated those comments as indicated in our responses below.

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.

William Thompson

August 24, 2007

Page 2

FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 2006

Item 8. Financial Statements and Supplementary Data, page 85

Comment No. 1:

Please disclose accumulated balances for each classification of accumulated other comprehensive income on the face of the consolidated balance sheets, in the consolidated statements of common stockholders’ equity and comprehensive income or in the notes to the financial statements.  Refer to paragraph 26 of SFAS 130.

Company’s Response:

We will include the necessary information in future filings and have included the following table within Note 7 “Comprehensive Income” of our second quarter 2007 Form 10-Q filed with the SEC on August 9, 2007, which included the balances as of December 31, 2006:

Balances by classification included within Accumulated Other Comprehensive Loss on the accompanying Condensed Consolidated Balance Sheets are as follows (in thousands):

            Derivatives

            Employee

            Amount from

            Designated as

            Benefit

            Equity

            Cash Flow Hedges

            Plans

            Investees

            Total

            As of June 30, 2007

            $

            2,892

            $

            (8,404)

            $

            (156)

            $

            (5,668)

            As of December 31, 2006

            $

            8,119

            $

            (8,404)

            $

            (230)

            $

            (515)

            As of June 30, 2006

            $

            (1,699)

            $

            (2,936)

            $

            (203)

            $

            (4,838)

Consolidated Statements of Cash Flows, page 91

Comment No. 2:

We believe that the classification of proceeds from the sale of discontinued operations should be presented on a basis consistent with the classification of gains and losses on sale of discontinued operations in the consolidated statements of income.  Please revise to present proceeds from the sale of business operations classified in discontinued operations in accordance with SFAS 144 as cash provided by investing activities of discontinued operations or tell us why a revision is unnecessary.

William Thompson

August 24, 2007

Page 3

Company’s Response:

We understand that our classification of proceeds from the sale of discontinued operations on our statements of cash flows is not on a basis consistent with the classification of gains and losses on the sale of discontinued operations in our statements of income.  However, we believe our original presentation is in accordance with SFAS 95 and SFAS 144.

While the presentation of gains and losses on the sale of discontinued operations is explicit within SFAS 144, there is no clear guidance addressing the cash flow statement classification of cash generated from the sale of discontinued operations.  The fact that the related gains and losses are not recurring seems consistent with the intent of a discontinued operations presentation.  However, since the cash proceeds are available for our ongoing operations either for reinvesting, debt reduction, payment of dividends, etc., a discontinued operations presentation here would seem inconsistent with SFAS 95.  Paragraph 5 of SFAS 95 states:

“The information provided in a statement of cash flows, if used with related disclosures and information in the other financial statements, should help investors, creditors, and others to (a) assess the enterprise's ability to generate positive future net cash flows; (b) assess the enterprise's ability to meet its obligations, its ability to pay dividends, and its needs for external financing; (c) assess the reasons for differences between net income and associated cash receipts and payments; and (d) assess the effects on an enterprise's financial position of both its cash and noncash investing and financing transactions during the period.”

Our presentation on the Consolidated Statement of Cash Flows was transparent, as the cash inflows related to the sale of discontinued operations were on a separate line titled, “Proceeds from sale of business operations”.  Further, our disclosure in Note 16 to the financial statements provides the reader with additional clarity to understand the cash flow implications of the sale.  We believe our presentation is an acceptable application of the standards as it provides the reader a clear picture of the actual investing cash flow activities for discontinued operations as well as provides an understanding of how the sale proceeds impact our ongoing ability to generate positive future cash flow, meet our obligations and external financing needs, and pay dividends.

Notes to Consolidated Financial Statements, page 93

Note 1.  Business Description and Summary of Significant Accounting Policies, page 93

Comment No. 3:

Please disclose the types of costs included in operations and maintenance and administrative and general expenses.  In doing so, please address production costs and ARO accretion expense.

Company’s Response:

We include our production related costs within the “Operations and maintenance” line item on our statements of income.  As discussed in more detail within our response to Comment No. 9 below, we include ARO accretion expense within the “Depreciation, depletion and amortization” line item on our statements of income.  In future filings, we will include in our footnotes to the financial statements language to clarify the location of these costs within our financial statements.

William Thompson

August 24, 2007

Page 4

Oil and Gas Operations, page 95

Comment No. 4:

Please tell us whether amortizable cost includes estimated future expenditures, including future ARO costs, to be incurred in developing proved reserves and estimated dismantlement and abandonment costs.  Please also tell us how you treat costs of investments in unproved properties and major development projects.  In addition, please clarify your disclosure regarding the costs included in the amortization base.  Refer to Rule 4-10(c)(3) of Regulation S-X.

Company’s Response:

In accordance with Rule 4-10(c) of Regulation S-X, within our costs to be amortized we include estimated future expenditures to be incurred in developing proved reserves as well as estimated dismantlement and abandonment costs, net of estimated salvage values.

We exclude those costs directly associated with unproved properties and major development projects, if any, from the costs to be amortized.  These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties.  The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized.

We intend to clarify our disclosures accordingly in our future filings.

William Thompson

August 24, 2007

Page 5

Note 3.  Investments in Associated Companies, page 107

Comment No. 5:

Please explain to us why an increase in your power fund partnership interests earned through fund performance triggered by “equity flips” resulted in impairment of goodwill.  In doing so, please describe the “equity flips” to us in detail.  Also, explain to us why the increase in partnership interests was triggered by the “equity flips” and any other facts useful to an understanding of the transactions, your accounting treatment and basis in GAAP therefore.

Company’s Response:

Our investments in multiple energy funds include performance based “equity flips” in the related limited partnership agreements.  The term “equity flip” has been used to describe a shifting in ownership interests among the fund partners.  The general partner’s interest in these partnerships originated at 1 percent and increased to 21 percent, in defined steps.  Each defined step is an “equity flip” that is structured to occur as the limited partners achieve a specified target internal rate of return based on actual cash distributions from the partnership.  Upon achieving a targeted return, the general partner’s interest in the fund income, losses and future cash distributions increases.

With cash distributions in 2005, the limited partners achieved the specified target rate that resulted in our recognizing the final “equity flip” to a 21 percent interest for the general partner.  For application of the equity method of accounting, Paragraph 6b of APB No. 18 states:  “The investment of an investor is also adjusted to reflect the investor's share of changes in the investee's capital”.   Accordingly, we recognized the earnings associated with the value of our additional general partnership interest.

In understanding how the final “equity flips” resulted in an impairment of associated goodwill, it is important to note that these energy funds follow the provisions of the AICPA Audit and Accounting Guide, “Audits of Investment Companies”, whereby the funds underlying investments are carried at fair value.  The fact that we account for our investments in these funds under the equity method of accounting results in our associated book carrying value being equal to our pro rata interest in the fair value based underlying fund equity.  Given the funds’ fair value based accounting practices and the fund manager’s intention and progress toward liquidating the fund assets, we anticipated that the future cash distributions from the funds would approximate the recorded fund equity.

Prior to the final “equity flip” occurring, we were able to carry the excess value of the associated goodwill on our books due to the potential to realize value and subsequent cash distributions from the additional partnership interest related to the final “equity flip”.  Once the final “equity flip” occurred, this value was recognized, and any justification for a carrying value in the investments over our pro rata share of the fair value based underlying fund equity was eliminated.  Therefore, the associated goodwill was impaired at the same time the value of our additional partnership interest was recognized.

William Thompson

August 24, 2007

Page 6

Note 4.  Property, Plant and Equipment, page 108

Comment No. 6:

Please tell us what the plant acquisition adjustment line item represents and why the adjustment is not depreciated.

Company’s Response:

The plant acquisition adjustment relates to the acquisition of our ownership interest in the Wyodak power plant by our rate regulated utility subsidiary, Black Hills Power.  The plant acquisition adjustment represents the amount by which our acquisition purchase price exceeded the undepreciated original purchase price of the plant.  The plant acquisition adjustment has been and continues to be amortized over the remaining life of the acquired plant.  Our disclosure indicating the lack of an average useful life for amortization purposes was an oversight that will be corrected in future filings.  For reference, as of December 31, 2006, the $4.9 million unamortized plant acquisition adjustment was approximately 0.2 percent of our gross property, plant and equipment, which we believe to be immaterial to the overall presentation.

Note 18.  Commitments and Contingencies, page 135

Legal Proceedings, page 137

Comment No. 7:

Please tell us when you accrued the loss related to the settled governmental claims arising from the forest fires disclosed under the “Forest Fire Claims” heading.  Also, given the significance of the settlement amount as disclosed in Form 10-Q for the quarterly period ended September 30, 2006 to the amount of reported net income, please tell us why you believe the settlement should not be described in Management’s Discussion and Analysis of Financial Condition and Results of Operations in accordance with Item 303(a)(3) of Regulation S-K.  In addition, tell us whether you have accrued estimated losses related to the private claims arising from the forest fires and, if so, the amounts accrued.  Further, with regard to loss contingencies disclosed pursuant to the requirements of SFAS 5, please disclose:

            •     the nature of accruals made pursuant to the provisions of paragraph 8 and to the extent material the amounts accrued; and

            •     in circumstances where no accrual is made because one or both of the conditions in paragraph 8 are not met, or if an exposure to loss exists in excess of the amount accrued, please give an estimate of the possible loss or range of loss or state that such an estimate cannot be made.

William Thompson

August 24, 2007

Page 7

Company’s Response:

We have sufficient confirmed insurance coverage for both the pending private party forest fire claims and the settled state and federal government forest fire claims.  Thus our assessment of the available facts at no time resulted in a loss accrual in accordance with SFAS 5.  As the estimated impact, net of insurance coverage, was immaterial to our results of operations, we did not expand our discussion into Management’s Discussion and Analysis of Financial Condition and Results of Operations in accordance with Item 303(a)(3) of Regulation S-K.

In addition to the forest fire claims, we disclosed certain additional contingencies pursuant to the provisions of SFAS 5.  In each instance we assessed the contingencies in accordance with paragraphs 8-10 of SFAS 5 to determine the applicable disclosure requirements.  Accordingly, we believe our original disclosures were in compliance with the disclosure requirements of SFAS 5.  The contingencies disclosed pursuant to SFAS 5 within our 2006 Form 10-K included the following:

            •     PPM Energ

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549-7010

DIVISION OF
CORPORATION FINANCE MAIL STOP 7010

Mail Stop 3561

July 17, 2007

Mr. Mark T. Thies
Executive Vice President & Chief Financial Officer
Black Hills Corporation
625 Ninth Street
Rapid City, South Dakota 57701

 Re: Black Hills Corporation
   Form 10-K for Fiscal Year Ended December 31, 2006
Filed March 1, 2007
Form 10-Q for Fiscal Quarter Ended March 31, 2007
Filed May 10, 2007
  File No. 1-31303

Dear Mr. Thies:

 We have reviewed your filings and have the following comments.  Where
indicated, we think you should revise your documents in response to these comments.  If you disagree, we will consider your explanation as to why our comment is inapplicable or a revision is unnecessary.  Please be as detailed as necessary in your explanation.  In some of our comments, we may ask you to provide us with information so we may better understand your disclosure.  After reviewing this information, we may raise additional comments.

 Please understand that the purpose of our review process is to assist you in your compliance with the applicable disclosure requirements and to enhance the overall disclosure in your filings.  We look forward to working with you in these respects.  We welcome any questions you may have about our comments or on any other aspect of our review.  Feel free to call us at the telephone numbers listed at the end of this letter.

Form 10-K for Fiscal Year Ended December 31, 2006

Item 8. Financial Statements and Supplementary Data, page 85

1. Please disclose accumulated balances for each classification of accumulated other comprehensive income on the face of the consolidated balance sheets, in the consolidated statements of common stockholders’ equity and comprehensive

Mr. Mark T. Thies
Black Hills Corporation
July 17, 2007 Page 2

income or in the notes to the financial statements.  Refer to paragraph 26 of SFAS 130.

Consolidated Statements of Cash Flows, page 91

2. We believe that the classification of proceeds from the sale of discontinued operations should be presented on a basis consistent with the classification of gains and losses on sale of discontinued operations in the consolidated statements of income.  Please revise to present proceeds from the sale of business operations classified in discontinued operations in accordance with SFAS 144 as cash provided by investing activities of discontinued operations or tell us why a revision is unnecessary.

Notes to Consolidated Financial Statements, page 93

Note 1. Business Description and Summary of Significant Accounting Policies, page 93

3. Please disclose the types of costs included in operations and maintenance and administrative and general expenses.  In doing so, please address production costs and ARO accretion expense.

Oil and Gas Operations, page 95

4. Please tell us whether amortizable cost includes estimated future expenditures, including future ARO costs, to be incurred in developing proved reserves and estimated dismantlement and abandonment costs.  Please also tell us how you treat costs of investments in unproved properties and major development projects.  In addition, please clarify your disclosure regarding the costs included in the amortization base.  Refer to Rule 4-10(c)(3) of Regulation S-X.

Note 3. Investments in Associated Companies, page 107

5. Please explain to us why an increase in your power fund partnership interests earned through fund performance triggered by “equity flips” resulted in impairment of goodwill.  In doing so, please describe the “equity flips” to us in detail.  Also, explain to us why the increase in partnership interests was triggered by the “equity flips” and any other facts useful to an understanding of the transactions, your accounting treatment and basis in GAAP therefore.

Note 4. Property, Plant and Equipment, page 108

Mr. Mark T. Thies
Black Hills Corporation
July 17, 2007 Page 3

6. Please tell us what the plant acquisition adjustment line item represents and why the adjustment is not depreciated.

Note 18. Commitments and Contingencies, page 135

Legal Proceedings, page 137

7. Please tell us when you accrued the loss related to the settled governmental claims arising from the forest fires disclosed under the “Forest Fire Claims” heading.  Also, given the significance of the settlement amount as disclosed in Form 10-Q for the quarterly period ended September 30, 2006 to the amount of reported net income, please tell us why you believe the settlement should not be described in Management’s Discussion and Analysis of Financial Condition and Results of Operations in accordance with Item 303(a)(3) of Regulation S-K.  In addition, tell us whether you have accrued estimated losses related to the private claims arising from the forest fires and, if so, the amounts accrued.  Further, with regard to loss contingencies disclosed pursuant to the requirements of SFAS 5, please disclose:

• the nature of accruals made pursuant to the provisions of paragraph 8 and to the extent material the amounts accrued; and

• in circumstances where no accrual is made because one or both of the conditions in paragraph 8 are not met, or if an exposure to loss exists in excess of the amount accrued, please give an estimate of the possible loss or range of loss or state that such an estimate cannot made.

Note 23. Oil and Gas Reserves and Related Financial Data (Unaudited), page 146

Costs Incurred, page 146

8. Please tell us whether costs incurred includes asset retirement costs capitalized during the year and any gains or losses recognized upon settlement of asset retirement obligations.  Please also tell us how these items are classified in the table of costs incurred.  If the items are excluded, please revise.  In addition, please clarify your disclosure as appropriate.

Mr. Mark T. Thies
Black Hills Corporation
July 17, 2007 Page 4

Results of Operations, page 147

9. Please tell us whether production costs include accretion expense related to oil and gas properties’ asset retirement obligations.  If not, please revise.  In addition, please clarify your disclosure as appropriate.

Standardized Measure of Discounted Future Net Cash Flows, page 148

10. Please tell us whether the net cash flows related to your oil and gas reserves include cash outflows associated with the settlement of asset retirement obligations and the line item that includes such cash outflows.  If the table excludes cash outflows associated with the settlement of asset retirement obligations, please revise.  In addition, please clarify your disclosure as appropriate.

Item 9A. Controls and Procedures, page 151

11. You state that your Chief Executive and Ch ief Financial officers concluded that
your disclosure controls and procedures are adequate and effective to ensure that material information related to you that is required to be disclosed in your reports filed under the Exchange Act is recorded, processed, summarized and reported within the required time periods.  Please revise to clarify, if true, that these officers concluded that your disclosure controls and procedures are also effective to ensure that information required to be disclosed in the reports that you file or submit under the Exchange Act is accumulated and communicated to your management, including your principal executive and principal financial officer, to allow timely decisions regarding required disclosure.  Refer to Exchange Act Rule 13a-15(e).  Alternatively, you may simply state that the officers concluded that your disclosure controls and procedures are effective.

Form 10-Q for Quarterly Period Ended March 31, 2007

12. Please address the comments above as applicable.

Petroleum Engineering Comments

Mr. Mark T. Thies
Black Hills Corporation
July 17, 2007 Page 5

Form 10-K for Fiscal Year Ended December 31, 2006

Risk Factors, page 30

Estimates of the quantity and value of our proved oil and gas reserves may change
materially due to numerous uncertainties inherent in estimating oil and natural gas
reserves., page 30

13. Please expand this to disclose and quantify your negative proved reserve revisions in each of the last three years.

Item 8. Financial Statements and Supplementary Data, page 85

Notes to Consolidated Financial Statements, page 93

Note 23. Oil and Gas Reserves and Related Financial Data (Unaudited), page 146

Reserves, page 146

14. Financial Accounting Standard 69, paragraph 11 requires the disclosure of the changes to your proved reserve figures due to “extensions and discoveries” separately from those due to “purchases of minerals in place” (acquisitions).  In addition, you should explain “significant changes” due to each of the six specified line items in each year reported.  Please amend your document to comply with these requirements.

Standardized Measure of Discounted Future Net Cash Flows, page 148

15. FAS 69, paragraph 30(b) requires the disclosure of production costs separately from significant development costs.  Please amend your document to comply with this requirement and explain the reasons for any significant difference between your projected unit production costs and the historical production costs for 2006 disclosed on page 19.

16. We note that your East Blanco property has had significant downward revisions in each of the last three years.  Please amend your document in an appropriate place to disclose the remaining East Blanco proved developed and proved undeveloped reserves that you claim as well as your revision history with this property.  Address the procedures you have adopted to avoid negative revisions in the future.

Mining Engineering Comments

Mr. Mark T. Thies
Black Hills Corporation
July 17, 2007 Page 6

Form 10-K for Fiscal Year Ended December 31, 2006

Coal Mining Segment, page 27

17. Please insert a small-scale map showing the location and access to your property.  See Item 102 (3) (B) of Regulation S-K.  Briefly describe the road, barge and/or railroad access to each of your properties in the text.  Please note that the EDGAR program now accepts digital maps.  So please include these in any future amendments that are uploaded to EDGAR.  It is relatively easy to include automatic links at the appropriate locations within the document to GIF or JPEG files, which will allow the figures and/or diagrams to appear in the right location when the document is viewed on the Internet.  For more information, please consult the EDGAR manual, and if you need addition assistance, please call Filer Support at 202-942-8900.  Otherwise provide th e map to the engineering staff for
our review.

18. For your mine, please provide the disclosures required by Industry Guide 7 (b).  In particular, provide a brief discussion of:

• The coal beds of interest, including minable coal thickness.

• A brief description of and the capacities of the mine, mining equipment used, and other infrastructure facilities present.

• A list of your coal processing and/or handling facilities, if applicable.

• The road, barge and/or railroad access to each of your properties.

• The present condition of the mine and material events of interest concerning the mine, adverse or otherwise within the last three years.

• Any mine expansions, contractions or decommissioning within the last three years and any planned expansions or reductions in mining.

• Any joint ownership or use of mining contractors.

19. In a table, disclose proven and probable reserves as defined in Industry Guide 7 for your mine.

• Describe the drill density to designate proven and/or probable reserves.

Mr. Mark T. Thies
Black Hills Corporation
July 17, 2007 Page 7

• Indicate tonnages that are “assigned” to an existing facility and those that have not been “assigned.”  Assigned reserves means coal which has been committed by the coal company to operating mine shafts, mining equipment, and plant facilities, and all coal which has been leased by the company to others. Unassigned reserves represent coal which has not been committed, and which would require new mineshafts, mining equipment, or plant facilities before operations could begin in the property.  The primary reason for this distinction is to inform investors, which coal reserves will require substantial capital investments before production can begin.

• Disclose if the coal is steam or metallurgical, if it is leased or owned, and what is the Btu per pound and percent sulfur content.  Do not report Btu content as “dry,” but include natural moisture in the calculation.

• If coal is reported as tons in the ground, disclose in another column the average mining and wash plant recoveries in percent; and indicate whether these losses have or have not been reflected in the total recoverable reserves.

• In either case, with a footnote clearly disclose if the reserves reported are “in the ground” or “recoverable.”

• Provide totals to the tables where appropriate.

• Disclose your percentage of compliance and non-compliance coal.

 As appropriate, please amend your filings and respond to these comments within 10 business days or tell us when you will provide us with a response.  You may wish to provide us with marked copies of the amendments to expedite our review.  Please furnish a cover letter that keys your responses to our comments and provides any requested information.  Detailed cover letters greatly facilitate our review.  Please understand that we may have additional comments after reviewing your amendments and responses to our comments.  Please submit your response letter on EDGAR.

 We urge all persons who are responsible for the accuracy and adequacy of the disclosure in the filings reviewed by the staff to be certain that they have provided all information investors require for an informed decision.  Since the company and its management are in possession of all facts relating to a company’s disclosure, they are responsible for the accuracy and adequacy of the disclosures they have made.

Mr. Mark T. Thies
Black Hills Corporation
July 17, 2007 Page 8

 In connection with responding to our comments, please provide, in writing, a statement from the company acknowledging that:

• the company is responsible for the adequacy and accuracy of the disclosure in the filings;

• 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.

 In addition, please be advised that the Division of Enforcement has access to all information you provide to the staff of the Di vision of Corporation Finance in our review
of your filings or in response to our comments on your filings.

You may contact Adam Phippen at (202) 551-3336 if you have questions
regarding comments on the financial statements and related matters.  You may contact George Schuler, Mining Engineer, at ( 202) 551-3718 and Ronald Winfrey, Petroleum
Engineer, with questions about engineering comments.  Please contact me at (202) 551-3344 with any other questions.

Sincerely,

 William Thompson
Branch Chief

<DOCUMENT>
<TYPE>LETTER
<SEQUENCE>1
<FILENAME>filename1.txt
<TEXT>

Mail Stop 3561

				September 22, 2005

By Facsimile and U.S. Mail

Mr. David R. Emery
President and Chief Executive Officer
Black Hills Corporation
Black Hills Power, Inc.
625 Ninth Street
Rapid City, South Dakota 57701

		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. Emery:

	We have completed our review of your Form 10-K and related
filings and have no further comments at this time.

								Sincerely,

			Jim Allegretto
			Sr. Assistant Chief Accountant

</TEXT>
</DOCUMENT>

CORRESP
1
filename1.htm

September 14, 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 additional comments in review of our 2004 Form 10-K, as set forth in your letter of August 25, 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.

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

Note 1. Business Description and Summary of Significant Accounting Policies

Material, Supplies and Fuel, page 86

Comment No. 1

We note your response to comment 1 of our letter dated August 3, 2005.  It appears that your illustrative journal entries reflect a gross presentation of your energy trading activities.  In this regard, we note your example includes transactions to purchase and sell like amounts of natural gas in order to lock in your margin.  You indicate in your response that such transactions are energy trading activities and that you record gains or losses on a net basis in the income statement.  However, your illustrative example provides a gross presentation such that the cost to purchase natural gas is recorded as cost of sales while the contract to sell is recorded as revenues.  This is a gross presentation whereas a net presentation merely records the gain or loss associated with the energy trading derivative.  Please advise how your energy trading activities complies with net presentation requirements of EITF
02-3.  Similarly, your response quotes the 02-03 language requiring net presentation.  However our original question related to your offsetting net transaction gains/losses with derivative gains/losses.  Please explain.

In our response to comment 1 of your letter dated August 3, 2005, we reflected our journal entries as we record them in our general ledger, not as we present them in our financial statements.  Our intention was to add more detail on having the purchase and sale netting to our trading margin.  In hindsight, it appears we added some confusion.  To clarify, as the journal entries are presented all of the entries impacting the income statement are netted for financial statement presentation in Operating Revenues.

In response to your original question related to our offsetting net transaction gains/losses with derivative gains/losses we point to the last paragraph of our response to comment 1 of your letter dated August 3, 2005.  In summary, we believe EITF 02-3 intends for a net presentation that presents the margin earned through trading activities.  Given that fixing the currency rate is necessary to lock in our margin, we believe that not reflecting the transaction gains/losses with derivative gains/losses and other components of the trade would unnecessarily distort the financial presentation of our trading margins earned.

Earnings Per Share of Common Stock, page 89

Comment No. 2

We have read your response to comment 2 of our letter dated August 3, 2005.  We concur with recording the initial value of the stock as deferred compensation within equity and the amortization of compensation expense in subsequent periods.  However, your consolidated statements of common stockholders’ equity for the three years in the period ended December 31, 2004 do not reflect a contra-equity account.  Please tell us where you have classified the deferred compensation recorded in connection the issuance of restricted stock.

Further, we have studied your computation of assumed proceeds to be used in your calculation of diluted earnings per share for all three years.  Please tell us whether this illustrative computation was meant to be representative of your statement that some non-vested restricted shares were anti-dilutive in 2003 and 2002.  In this regard, it appears that the proceeds related to the restricted shares assumed to purchase common stock would approximate 8,177 shares in Year 1.  Since the 10,000 restricted shares were still subject to return, they would be excluded for purposes of computing basic earnings per share and included for dilutive earnings per share.  In this period, please confirm that your dilutive shares would increase by 1,823 shares.  Similar calculations for years 2 and 3 appear to show net dilutive shares.  If our understanding is not correct, please clarify it.  Please expand on your
illustrative computations to show the number of shares that you have determined to be anti-dilutive.

Deferred compensation recorded in connection with the issuance of restricted stock is recorded in a contra-equity account.  For purposes of our financial statement presentation it is netted into Additional-Paid-In-Capital due to the immateriality of the account balance.  At December 31, 2004, 2003 and 2002 the Deferred Compensation account balance was $1.5 million, $1.9 million and $1.0 million, respectively.  The December 31, 2004, Deferred Compensation account balance was equal to 0.4% of Additional-Paid-In-Capital, 0.2% of Total Stockholders’ Equity and 0.08% of Total Liabilities.  In addition, the Company has recognized pre-tax compensation cost, related to awards of restricted stock and restricted stock units, of $1.7 million in 2004, $0.9 million in 2003 and $0.4 million in 2002, as disclosed in Note 10 – Common Stock in our 2004 Annual Report on Form 10-K.

2

The computation that was included in our response to comment 2 of your letter dated August 3, 2005 was an illustrative example of the methodology we use to calculate assumed proceeds in our application of the treasury stock method.  As such, we confirm your conclusion that our dilutive shares would increase by 1,823 in Year 1 of the illustrative example.  The illustrative example was not meant to be representative of our statement that some non-vested restricted shares were anti-dilutive in 2003 and 2002.  To represent our statement on anti-dilutive shares, an actual calculation from 2002 for a restricted stock grant that resulted in anti-dilutive shares in our application of the treasury stock method is as follows:

2002

Grant

Date

12/31/02

Unvested

Shares

            2002

Weighted

Unvested

Shares

            FMV

On

Grant

Date

            Deferred

Compensation

Balance

12/31/01

            Deferred

Compensation

Balance

12/31/02

            Average

Deferred

Compensation

Balance

            05/30/2001

            8,119

            9,776

            $55.36

            $543,040

            $318,334

            $430,687

            Average Market Price in 2002

            $28.99

05/30/01 Restricted Stock Grant

            1.

            Assumed Proceeds for the 05/30/01 Restricted Stock Grant

            a.  Average unamortized deferred compensation balance during

            the year

            $ 430,687

            b. Tax benefits credited to capital on assumed taxable

            compensation based on average market price for year

            $ 283,406

            ($28.99 x 9,776 avg. unvested shares) x Tax Rate

            x            35%

            $    99,192

            Tax effect related to compensation for accounting purposes

            ($430,687 x 35%)

            150,740

            Excess

            (51,548)

            Total assumed proceeds

            $ 379,139

            2.

            Repurchase shares on the open market at the average price

            during the year with the assumed proceeds ($379,139/$28.99)

            13,078

            3.

            Incremental shares considered to be outstanding (9,776 – 13,078)

            (3,302)

            4.

            Dilutive or Anti-dilutive

            Anti-dilutive

3

FORM 10-Q FOR THE PERIOD ENDED JUNE 30, 2005

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 24

Liquidity and Capital Resources, page 35

Comment No. 3

Please ensure your discussion and analysis of historical cash flows is not merely a recitation of changes evident from the financial statements.  For example, you indicate that the increase in cash flow from operations for the six-month period ended June 30, 2005 was due to a $9.4 million increase in net income, an $11.7 million increase in cash flows from net derivative assets and liabilities and a $54.8 million increase in operating assets and liabilities.  Please provide analysis explaining the underlying reasons for the fluctuations in the working capital accounts.

In future filings, we will provide, to the extent meaningful, enhanced discussion and analysis of our historical cash flows including analysis of the underlying reasons for working capital fluctuations.

If you have any questions, please do not hesitate to contact me or Jeff Berzina at (605) 721-1700 at any time.

Sincerely,

BLACK HILLS CORPORATION

/s/ MARK T. THIES

Mark T. Thies

Executive Vice President and Chief Financial Officer

4

<DOCUMENT>
<TYPE>LETTER
<SEQUENCE>1
<FILENAME>filename1.txt
<TEXT>

Mail Stop 3561

				August 25, 2005

By Facsimile and U.S. Mail

Mr. David R. Emery
President and Chief Executive Officer
Black Hills Corporation
Black Hills Power, Inc.
625 Ninth Street
Rapid City, South Dakota 57701

		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. Emery:

	We reviewed your responses to our prior comments on the above
referenced filings as set forth in your letter dated August 17,
2005.
Our review resulted in the following accounting comments.

	As appropriate, please respond to this comment within 10
business days or tell us when you will provide us with a response.
Please provide us with a response letter that keys your response
to
our comment and provides any requested supplemental information.
Please file your response letter on EDGAR as a correspondence
file.

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

Note 1. Business Description and Summary of Significant Accounting
Policies

Materials, Supplies and Fuel, page 86

1. We note your response to comment 1 of our letter dated August
3,
2005.  It appears that your illustrative journal entries reflect a
gross presentation of your energy trading activities.  In this
regard, we note your example includes transactions to purchase and
sell like amounts of natural gas in order to lock in your margin.
You indicate in your response that such transactions are energy
trading activities and that you record gains or losses on a net
basis
in the income statement.  However, your illustrative example
provides
a gross presentation such that the cost to purchase natural gas is
recorded as cost of sales while the contract to sell is recorded
as
revenues.  This is a gross presentation whereas a net presentation
merely records the gain or loss associated with the energy trading
derivative. Please advise how your energy trading activities
complies
with net presentation requirements of EITF 02-3.  Similarly, your
response quotes the 02-03 language requiring net presentation.
However our original question related to your offsetting net
transaction gains/losses with derivative gains/losses.  Please
explain.

Earnings Per Share of Common Stock, page 89

2. We have read your response to comment 2 of our letter dated
August
3, 2005.  We concur with recording the initial value of the stock
as
deferred compensation within equity and the amortization of
compensation expense in subsequent periods.   However, your
consolidated statements of common stockholders` equity for the
three
years in the period ended December 31, 2004 do not reflect a
contra-
equity account. Please tell us where you have classified the
deferred
compensation recorded in connection the issuance of restricted
stock.

Further, we have studied your computation of assumed proceeds to
be
used in your calculation of diluted earnings per share for all
three
years.  Please tell us whether this illustrative computation was
meant to be representative of your statement that some non-vested
restricted shares were anti-dilutive in 2003 and 2002. In this
regard, it appears that the proceeds related to the restricted
shares
assumed to purchase common stock would approximate 8,177 shares in
Year 1.   Since the 10,000 restricted shares were still subject to
return, they would be excluded for purposes of computing basic
earnings per share and included for dilutive earnings per share.
In
this period, please confirm that your dilutive shares would
increase
by 1,823 shares. Similar calculations for years 2 and 3 appear to
show net dilutive shares.  If our understanding is not correct,
please clarify it.  Please expand on your illustrative
computations
to show the number of shares that you have determined to be anti-
dilutive.

FORM 10-Q FOR THE PERIOD ENDED JUNE 30, 2005

Item 2. Management`s Discussion and Analysis of Financial
Condition
and Results of Operations, page 24

Liquidity and Capital Resources, page 35

3. Please ensure your discussion and analysis of historical
cashflows
is not merely a recitation of changes evident from the financial
statements.  For example, you indicate that the increase in cash
flow
from operations for the six-month period ended June 30, 2005 was
due
to a $9.4 million increase in net income, an $11.7 million
increase
in cash flows from net derivative assets and liabilities and a
$54.8
million increase in operating assets and liabilities.  Please
provide
analysis explaining the underlying reasons for the fluctuations in
the working capital accounts.

```````````````````````````````````````````````		If you have
any questions regarding these comments, please direct them to John
Cannarella, Staff Accountant, at (202) 551-3337 or, in his
absence,
to the undersigned at (202) 551-3849.  Any other questions
regarding
disclosure issues may be directed to H. Christopher Owings,
Assistant
Director, at (202) 551-3725.

                Sincerely,

		          Jim Allegretto
                                  Sr. Assistant Chief Accountant
`

??

??

??

??

Mr. David R. Emery
Black Hills Corporation
Black Hills Power, Inc.
August 25, 2005
Page 3

</TEXT>
</DOCUMENT>

CORRESP
1
filename1.htm

August 17, 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 additional comments in review of our 2004 Form 10-K, as set forth in your letter of August 3, 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.

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

Note 1. Business Description and Summary of Significant Accounting Policies

Material, Supplies and Fuel, page 86

Comment No. 1

We note your response to comment 7 of our letter dated June 29, 2005.  Please show us a representative transaction for a non-designated hedge.  Show us the accounting for the FX derivative and transaction gain or loss as of a quarter-end with a settlement date in the next quarter.  While we understand that disclosure of the transaction gain or loss by itself may not provide a complete portrayal of the economics from your foreign exchange activities including hedging, there is nothing to prevent you from disclosing the fair value of the derivative transactions that are not designated but mitigate economic risk from transaction gains/losses.  This would allow the reader to assess your hedging strategy since you do not designate and still comply with paragraph 30 of SFAS no. 52.  Please advise whether you concur with the above approach.  If you do not, explain to us your reasons.  Additionally help us
understand your rationale under GAAP in classification of the transaction gain/losses and any associated non-designated hedges as operating revenues.  While we understand that EITF 02-03 requires a net presentation, we understood that to be in the context of “net” of related costs in a “physical” derivative upon delivery.  We are unclear how the netting provisions of the above Consensus apply to mark-to-market as well as transaction gains or losses.  Please advise in detail.

1

Following is an example FX transaction in our gas marketing business:

FACT SET

Date

            3/15/04

            The Company enters into the following trades which export gas from Canada to the US:

            —

            Buy 100,000 Mmbtu at C$6.00 per Mmbtu for March 2004 delivery at a location in Canada (cash outlay will be C$600,000)

Assume transport fee = $0 for this example

            —

            Sell 100,000 Mmbtu at US$4.4187 per Mmbtu for March 2004 delivery at a location in the US (cash inflow will be US$441,870)

            Note:

            Since the physical purchase and sale are fixed price, financial transactions are not necessary to hedge commodity price risk.

            3/15/04

            The Company fixes C$ to fund the transaction through a currency swap (buy C$600,000 and sell US$407,880 with settlement on April 25 (industry payment date for March deliveries) => 0.6798 FEX rate).  This eliminates the currency exchange rate risk and secures the margin on this transaction.

Currency exchange rates and related transaction gain/loss assumptions are as follows:

            C$

            Transaction

            Accounts

            Exchange

            US$

            Gain/Loss

            Payable

            Rate

            Equivalent

            US$

            03/15/2004

            600,000

            0.6798

            407,880

            —

            03/31/2004

            600,000

            0.7000

            420,000

            12,120

            04/25/2004

            600,000

            0.7700

            462,000

            54,120

Gross margin secured on the deal will be as follows:

            C$

            US$

            Per

            Per

            Locked-in

            MMBTU

            MMBTU

            C$

            FEX Rate

            US$

            Purchase

            (6.0000)

            (4.0788)

            (600,000)

            0.6798

            (407,880)

            Sale

            6.5000

            4.4187

            650,000

            0.6798

            441,870

            0.5000

            0.3399

            50,000

            33,990

2

Journal entries related to the transaction will be as follows:

Account

C$ Debit

C$ Credit

Exchange Rate

US$ Debit

US$ Credit

            US$

Net expense (income)

            03/31/2001

            1

            Derivative asset

            0.7000

            $ 12,120

            Unrealized foreign currency gain/ loss

0.7000

$  12,120

$  (12,120)

            (to record fair value of currency swap)

            03/31/2001

            2

            Accounts Receivable

            $441,870

            Gas revenue

            $441,870

            $(441,870)

            Cost of sales

            $600,000

            0.6798

            $407,880

            $ 407,880

            Transaction currency gain/loss

            0.0202

            $  12,120

            $  12,120

            Accounts payable

            $600,000

            0.7000

            $420,000

            (To record gas purchases and sales)

            04/25/2004

            3

            Cash

            $441,870

            Accounts receivable

            $441,870

            (To record US$ received for sale)

            04/25/2004

            4

            Transaction currency gain/loss

            0.0700

            $  42,000

            $  42,000

            Accounts payable

            $600,000

            0.7700

            $462,000

            Accounts payable

            0.0700

            $  42,000

            Cash

            $600,000

            0.7700

            $462,000

            (To record C$ paid for purchase at

            the current exchange rate)

            04/25/2004

            5

            Realized foreign currency gain/loss

            $  54,120

            $ (54,120)

            Cash

            $  54,120

            (To record settlement on currency swap)

            04/25/2004

            R1

            Unrealized foreign currency gain/loss

$ 12,120

$  12,120

            Derivative asset

            $  12,120

            (To reverse 03/31/04 MTM entry 1 above)

            $(33,990)

We concur with the Staff’s advice on disclosure of our foreign exchange activities.  We will enhance our future disclosures in that regard, to the extent applicable.

The rational for the presentation used for our “energy trading activities” stems from paragraph 16 of EITF 02-3.  Paragraph 16 includes the following:

“The Task Force reached a consensus that gains and losses (realized and unrealized) on all derivative instruments within the scope of Statement 133 should be shown net when recognized in the income statement, whether or not settled physically, if the derivative instruments are held for trading purposes.”

3

We have relied on this guidance in determining to present results of our derivatives used in energy trading activities in Operating Revenues.  In addition to the above, we have presented the FX transaction gains/losses in with all other trading activities as to most accurately reflect the margins earned from our trading efforts.  Given that fixing the currency rate is one of the components necessary to lock in our margin, to not reflect it with the other components of the trade would unnecessarily distort our trading margins earned.  We believe this is the presentation necessary to most accurately reflect the results of our trading activities and apply it consistently.

Earnings Per Share of Common Stock, page 89

Comment No. 2

We note your response to comment 10 of our letter dated June 29, 2005.  Assumed proceeds with respect to applying the treasury stock method should include the amount of compensation cost attributed to future services and not yet recognized.  Please confirm that the assumed proceeds you used in applying the treasury stock method does not include compensation ascribed to past services.  In doing so, please tell us which balance sheet accounts are impacted upon issuance of restricted stock and the manner in which you amortize compensation expense for financial reporting purposes.  In this regard, an illustrated example with related entries may be the best way to convey this information.

The assumed proceeds that the Company used in applying the treasury stock method did not include compensation for past services.

The assumed proceeds that are used in applying the treasury stock method is the sum of (a) the amount the employee must pay upon exercise (this is zero for our employees), (b) the amount of compensation cost attributed to future services and not yet recognized (the unamortized compensation cost), and (c) the amount of tax benefits that would be credited to additional paid in capital (the amount resulting from a tax deduction for compensation in excess of compensation expense recognized for financial reporting purposes).

An illustrative example of our application follows:

Assume the Company granted 10,000 shares of restricted stock to Executive A on January 1, 2005 with a value of $300,000 or $30.00 per share.  The shares vest 1/3 a year over a 3-year period.  The Company’s common stock has a par value of $1 per share.

At the time of grant the Company would record the following entry:

            Deferred Compensation (contra-equity account) - RS

            $300,000

            Common Stock – Unvested Restricted Stock

            $  10,000

            Additional Paid In Capital – Unvested RS

            $290,000

Compensation expense is recorded by the Company over the 3-year vesting period

($300,000.00 ÷ 36 months = $8,333.33 per month).  The monthly entry would be as follows:

            Compensation Expense

            $8,333.33

            Deferred Compensation – RS

            $  8,333.33

4

Financial information by year is as follows:

            At Grant

            Year 1

            Year 2

            Year 3

            Deferred Compensation

            Balance

            $300,000

            $200,000

            $100,000

            $       0

            Vested Shares

            0

            0

            3,333

            6,666

            Unvested Shares

            10,000

            10,000

            6,667

            3,334

            Average Market Price

            for the Year

            $31.00

            $25.00

            $31.00

The computation of the assumed proceeds is shown below:

Year 1

            Assumed Proceeds

            a.

            Average unamortized deferred

            compensation balance during

            the year

            ([$300,000 + $200,000]/2)

            $250,000

            b.

            Tax benefits credited to capital on

            assumed taxable compensation

            based on average market price for year

            ($31.00 x 10,000 avg. unvested shares)

            $310,000

            x Tax Rate

            x35%

            $108,500

            Tax effect related to compensation

            for accounting purposes

            ($30.00 x 10,000 shares x 35%)

            105,000

            Excess

            3,500

            Total assumed proceeds

            $253,500

6

Year 2

            Assumed Proceeds

            a.

            Average unamortized deferred

            compensation balance during

            the year

            ([$200,000 + $100,000]/2)

            $150,000

            b.

            Tax benefits credited to capital on

            assumed taxable compensation

            based on average market price for year

            ($25.00 x 6,667 avg. unvested shares)

            $166,675

            x Tax Rate

            x35%

            $  58,336

            Tax effect related to compensation

            for accounting purposes

            ($30.00 x 6,667 shares x 35%)

            70,004

            Excess/(Deficiency)

            (11,668)

            Total assumed proceeds

            $138,332

Year 3

            Assumed Proceeds

            a.

            Average unamortized deferred

            compensation balance during

            the year

            ([$100,000 + $0]/2)

            $50,000

            b.

            Tax benefits credited to capital on

            assumed taxable compensation

            based on average market price for year

            ($31.00 x 3,334 avg. unvested shares)

            $103,354

            x Tax Rate

            x35%

            $  36,174

            Tax effect related to compensation

            for accounting purposes

            ($30.00 x 3,334 shares x 35%)

            35,007

            Excess

            1,167

            Total assumed proceeds

            $51,167

7

Oil and Gas Reserves and Related Financial Data, page 134

Reserves, page 135

Comment No. 3

Regarding your response to comment 20 of our letter dated June 29, 2005, the definition of proved reserves as stated in Rule 4-10(a) of Regulation S-X is the quantities which engineering and geological data demonstrate with reasonable certainty to be recoverable under existing conditions.  This implies that the data is compelling and clearly supports the quantities to be proved within reasonable certainty.  The definition does not say proved reserves may be attributed based simply on the best data available at the time and it does not strongly support proved reserves.  If the data that you have is not clear and compelling, proved reserves may not be able to be booked until such time additional data becomes available.  Please confirm that in the future you will only attribute proved reserves based on geological and engineering data that is clear, compelling and in support of recovering the quantities
disclosed as proved reserves.

We confirm to the Staff that we will continue to only attribute proved reserves based on geological and engineering data that is clear, compelling and in support of recovering the quantities disclosed as proved reserves as required by Rule 4-10(a) of Regulation S-X.

If you have any questions, please do not hesitate to contact me or Jeff Berzina at (605) 721-1700 at any time.

Sincerely,

BLACK HILLS CORPORATION

            /s/ MARK T. THIES

Mark T. Thies

Executive Vice President and Chief Financial Officer

8

<DOCUMENT>
<TYPE>LETTER
<SEQUENCE>1
<FILENAME>filename1.txt
<TEXT>

Mail Stop 3561

				August 3, 2005

By Facsimile and U.S. Mail

Mr. David R. Emery
President and Chief Executive Officer
Black Hills Corporation
Black Hills Power, Inc.
625 Ninth Street
Rapid City, South Dakota 57701

		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. Emery:

	We reviewed your responses to our prior comments on the above
referenced filings as set forth in your letter dated July 21,
2005.
Our review resulted in the following accounting comments.

	As appropriate, please respond to this comment within 10
business days or tell us when you will provide us with a response.
Please provide us with a response letter that keys your response
to
our comment and provides any requested supplemental information.
Please file your response letter on EDGAR as a correspondence
file.

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

Note 1. Business Description and Summary of Significant Accounting
Policies

Material, Supplies and Fuel, page 86

1. We note your response to comment 7 of our letter dated June 29,
2005.  Please show us a representative transaction for a non-
designated hedge.  Show us the accounting for the FX derivative
and
transaction gain or loss as of a quarter-end with a settlement
date
in the next quarter.  While we understand that disclosure of the
transaction gain or loss by itself may not provide a complete
portrayal of the economics from your foreign exchange activities
including hedging, there is nothing to prevent you from disclosing
the fair value of the derivative transactions that are not
designated
but mitigate economic risk from transaction gains/losses.  This
would
allow the reader to assess your hedging strategy since you do not
designate and still comply with paragraph 30 of SFAS no. 52.
Please
advise whether you concur with the above approach.  If you do not,
explain to us your reasons.  Additionally help us understand your
rationale under GAAP in classification of the transaction
gain/losses
and any associated non-designated hedges as operating revenues.
While we understand that EITF 02-03 requires a net presentation,
we
understood that to be in the context of "net" of related costs in
a
"physical" derivative upon delivery.  We are unclear how the
netting
provisions of the above Consensus apply to mark-to-market as well
as
transaction gains or losses.  Please advise in detail.

Earnings Per Share of Common Stock, page 89

2. We note your response to comment 10 of our letter dated June
29,
2005.  Assumed proceeds with respect to applying the treasury
stock
method should include the amount of compensation cost attributed
to
future services and not yet recognized.  Please confirm that the
assumed proceeds you used in applying the treasury stock method
does
not include compensation ascribed to past services.  In doing so,
please tell us which balance sheet accounts are impacted upon
issuance of restricted stock and the manner in which you amortize
compensation expense for financial reporting purposes.  In this
regard, an illustrated example with related entries may be the
best
way to convey this information.

Oil and Gas Reserves and Related Financial Data, page 134

Reserves, page 135

3. Regarding your response to comment 20 of our letter dated June
29,
2005, the definition of proved reserves as stated in Rule 4-10(a)
of
Regulation S-X is the quantities which engineering and geological
data demonstrate with reasonable certainty to be recoverable under
existing conditions.  This implies that the data is compelling and
clearly supports the quantities to be proved within reasonable
certainty.  The definition does not say proved reserves may be
attributed based simply on the best data available at the time and
it
does not strongly support proved reserves.  If the data that you
have
is not clear and compelling, proved reserves may not be able to be
booked until such time additional data becomes available.  Please
confirm that in the future you will only attribute proved reserves
based on geological and engineering data that is clear, compelling
and in support of recovering the quantities disclosed as proved
reserves.

```````````````````````````````````````````````		If you have
any questions regarding these comments, please direct them to John
Cannarella, Staff Accountant, at (202) 551-3337 or, in his
absence,
to the undersigned at (202) 551-3849.  Any other questions
regarding
disclosure issues may be directed to H. Christopher Owings,
Assistant
Director, at (202) 551-3725.

                Sincerely,

		          Jim Allegretto
                                  Sr. Assistant Chief Accountant
`

??

??

??

??

Mr. David R. Emery
Black Hills Corporation
Black Hills Power, Inc.
August 3, 2005
Page 3

</TEXT>
</DOCUMENT>

CORRESP
1
filename1.htm

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

<DOCUMENT>
<TYPE>LETTER
<SEQUENCE>1
<FILENAME>filename1.txt
<TEXT>

Mail Stop 3561

				June 29, 2005

By Facsimile and U.S. Mail

Mr. David R. Emery
President and Chief Executive Officer
Black Hills Corporation
Black Hills Power, Inc.
625 Ninth Street
Rapid City, South Dakota 57701

		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. Emery:

      We have reviewed your filing and have the following
comments.
In some of our comments, we may ask you to provide us with
supplemental information so we may better understand your
disclosure.
Please be as detailed as necessary in your explanation.   After
reviewing this information, we may or may not raise additional
comments.

	Please understand that the purpose of our review process is
to
assist you in your compliance with the applicable disclosure
requirements and to enhance the overall disclosure in your filing.
We look forward to working with you in these respects.  We welcome
any questions you may have about our comments or any other aspect
of
our review.  Feel free to call us at the telephone numbers listed
at
the end of this letter.

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

General

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.

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

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.

Electric Utility, page 53

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.

4. We note that you have provided mwh volumes sold by firm
electric
sales and wholesale off-system sales.  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.

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.

Note 1. Business Description and Summary of Significant Accounting
Policies

Material, Supplies and Fuel, page 86

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.

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.

Oil and Gas Operations, page 87

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).

Revenue Recognition, page 89

9. We note that you sell a substantial majority of your
unregulated
capacity and energy under tolling arrangements.  We assume you
classify such revenues net of the related fuel costs.  If you
classify such transactions on a gross basis explain your rationale
under EITF 99-19 and explain why such contracts do not constitute
energy trading.  In doing so, please reference each of the
indicators
of gross and net revenue reporting in EITF 99-19.

Earnings Per Share of Common Stock, page 89

10. We note that you granted restricted common shares and/or
restricted stock units in each of the last three fiscal years and
such awards could be subject to return.  Please tell us your
treatment of these shares in determining the number of shares
outstanding used in your calculation of basic and diluted earnings
per share.   Refer to paragraph 10 of SFAS 128.  In addition,
please
help us understand how you determined that your restricted shares
are
anti-dilutive.

Note 4.  Property, Plant and Equipment, page 98

11. You disclose that separate categories of property, plant and
equipment are depreciated over a wide range of useful lives.
Please
disclose the weighted average useful lives related to each
category.

12. If rate recovery of generation-related costs becomes unlikely
or
uncertain, due to competition or regulatory action, the provisions
of
SFAS 71 may no longer apply to Black Hill Power`s generation
operations.  In the event that Black Hills Power determines that
it
no longer meets the criteria for following SFAS 71, the accounting
impact could include a material charge to your consolidated
statement
of income.  Please disclose the amount of carrying value of your
regulated generation assets that would not exist if such plant
would
have been accounted for outside of SFAS 71 for all periods
presented.

Note 15. Gain on Sale of Assets, page 107

13. Please tell us your basis for offsetting the gain to
"Operating
expenses".  We may have further comment.

Note 18. Other Comprehensive Income (Loss), page 111

14. Please tell us your accounting treatment for payments on or
receipts from interest rate swap agreements designated as cash
flow
hedges whose underlying debt has interest expense that is
capitalized.  Please include the capitalization policy associated
with the payments or receipts on such interest rate swaps and the
period(s) in which such payments or receipts impact earnings.
Refer
to EITF 99-9.

15. We note that you included the reclassification adjustment in
2003
for interest rate swaps designated as cash flow hedges settled as
part of an asset sale and included in net income.  Please revise
your
Consolidated Statements of Stockholders` Equity and Note 11
Comprehensive Loss to include the reclassification adjustments
related to gains or losses on your cash flow hedges that were
realized and included in net income for all applicable periods.
Please refer to paragraphs 18-21 of SFAS 130.

Note 20. Employee Benefit Plans, page 114

16. Please explain to us how you calculate the market related
value
of plan assets as that term is defined in SFAS 87.   Since there
are
alternative ways to calculate the market value of plan assets and
it
has a direct impact on your pension expense, we believe you should
disclose how you determine this amount in future filings.

Note 23. Business Segments, page 129

17. Please provide information about the extent of reliance on
your
major customers. If revenues from transactions with a single
external
customer amount to 10 percent or more of your revenues, you should
disclose that fact, and the total amount of revenues from each
such
customer. Please refer to paragraph 39 of SFAS 131.

Note 25.  Cheyenne Acquisition, page 134

18. Please tell us how you accounted for any contracts between
yourself and CLF&P in the application of purchase accounting.  In
this regard, tell us whether any amounts existed on either your
books
of CLF&P relating to such contracts immediately prior to
consummation.

Note 26. Oil and Gas Reserves and Related Financial Data

Reserves, page 135

19. We note the large negative revision in gas reserves in 2004
which
you attribute primarily to the East Blanco Field in New Mexico.
Based on the drilling and well work and the apparent lower than
expected production, did you lower per well PUD reserves in 2004
for
the remaining PUD locations in the East Blanco Field?  Were the
total
East Blanco Field reserves reduced and if so by how much and what
was
the basis for the reduction?  Supplementally, please clarify this
reserve revision to us.

20. Supplementally, tell us how much the reserves that were
written
off at the East Blanco field in 2004 lowered your DD&A and
increased
earnings in 2003.  Do you consider this amount to be material?
We
may have additional comments.

		```````````````````````````````````````````````Please
respond to these comments within 10 business days or tell us when
you
will provide us with a response.  Please furnish a letter with
your
responses to our comments and provide any requested supplemental
information.  Please understand that we may have additional
comments
after reviewing your responses to our comments.  Please file your
response letter on EDGAR as a correspondence file.

	We urge all persons who are responsible for the accuracy and
adequacy of the disclosure in the filing reviewed by the staff to
be
certain that they have provided all information investors require
for
an informed decision.  Since the company and its management are in
possession of all facts relating to a company`s disclosure, they
are
responsible for the accuracy and adequacy of the disclosures they
have made.

In connection with responding to our comments, please provide, in
writing, a statement from the company acknowledging that:

* 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 filing; 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.

		In addition, please be advised that the Division of
Enforcement has access to all information you provide to the staff
of
the Division of Corporation Finance in our review of your filing
or
in response to our comments on your filing.

		If you have any questions regarding these comments,
please
direct them to John Cannarella, Staff Accountant, at (202) 551-
3337
or, in his absence, to the undersigned at (202) 551-3849.  Any
other
questions regarding disclosure issues may be directed to H.
Christopher Owings, Assistant Director, at (202) 551-3725.

                Sincerely,

		          Jim Allegretto
                                  Sr. Assistant Chief Accountant
`

??

??

??

??

Mr. David R. Emery
Black Hills Corporation
Black Hills Power, Inc.
June 29, 2005
Page 3

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