Mr. William Thompson

Branch Chief

Division of Corporation Finance

United States Securities and Exchange Commission

100 F Street, NE

Washington, D.C. 20549-7010

 

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:

 

 

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):

 

 

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:

 

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:

 

 

We have not made material contingency accruals for any of the above claims. As of the filing of our second quarter 2007 Form 10-Q, we had settled both the “PPM Energy Arbitration” and the “California Price Reporting and Anti-Trust Litigation” for immaterial amounts, as disclosed within our filings. The “Acquisition Earn-Out Agreement Lawsuit” is ongoing. While there have been accruals for payments that have been paid or offered for payment under the provisions of the related “Earn-out” agreement, additional accruals related to the litigation claims have not been made. Additional accruals have not been made because we do not believe that it is probable we will incur future losses, nor can any amount of loss be reasonably estimated. Accordingly, we have disclosed that the amount of any potential loss is uncertain. Further, we have disclosed that under the provisions of the related agreement the consideration may not exceed $35 million, of which we have already paid or offered payment of $11.3 million. This indicates the range of potential loss as required by paragraph 10 or SFAS 5.

 

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

 

Costs Incurred, page 146

 

Comment No. 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.

William Thompson

August 24, 2007

Page 8

 

 

Company’s Response:

 

In the course of preparing our response to your Comment No. 8, we determined that our disclosure table of costs incurred did not include “asset retirement costs capitalized during the year and any gains or losses recognized upon settlement of asset retirement obligations”. Instead of the ARO costs capitalized during the year and any gains or losses, we have included only the actual expenditures on plugging and abandonment activities during the year. Including the ARO costs capitalized during the year would have increased the total costs incurred in the summary table by approximately $4.5 million, $0.3 million and $0.2 million for the years 2006, 2005 and 2004, respectively. This would increase the total costs incurred within the summary table by approximately 2.8 percent in 2006 and less than 1 percent in 2005 and 2004. The omission of these costs only impacted our supplemental disclosure tables and had no impact on our financial position or results of operations. While we believe this impact is insignificant to our overall disclosures in our 2006 Form 10-K, in compliance with the staff’s comment we will ensure that the appropriate costs are included in the disclosures within our future filings.

 

Results of Operations, page 147

 

Comment No. 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.

 

Company’s Response:

 

We have included accretion expense related to oil and gas properties’ asset retirement obligations on the “Depreciation, depletion & amortization and valuation provisions” line within the summary table of the results of operations for producing activities.

 

We believe our presentation is in compliance with applicable guidance. The guidance we follow includes staff observations included in SEC Chief Accountant Carol A. Stacey’s 2004 letter to Oil and Gas Producers. Within the sample letter available on the SEC website, the following excerpt refers to the location of ARO accretion expense to be located in the required SFAS 69 disclosure for the results of operations for oil and gas producing activities:

 

“We believe accretion of the liability for an asset retirement obligation should be included in the Results of Operations disclosure either as a separate line item, if material, or included in the same line item as it is presented on the statement of operations.

 

Paragraphs 14 and B57 of FAS 143 specify that the accretion expense resulting from recognition of the changes in the liability for an asset retirement obligation due to the passage of time be classified as an operating item in the statement of income. Therefore, it follows that the accretion expense related to oil and gas properties' asset retirement obligations should be included in the FAS 69 Results of Operations disclosure.”

 

For reference, our asset retirement obligation (ARO) accretion expense is approximately 1.5 percent of total operating expenses within the table, which we believe is immaterial to the overall presentation.

 

William Thompson

August 24, 2007

Page 9

 

 

Standardized Measure of Discounted Future Net Cash Flows, page 148

 

Comment No. 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.

 

Company’s Response:

 

Included within our estimates of future net cash flows for calculating the standardized measure we have, based on our historical experience in our fields of operation, made the assumption that future cash outflows for retirement obligations would be substantially offset by the cash inflows from salvage values. Accordingly, we believe the net cash flows for the settlement of retirement obligations are insignificant, and therefore have not specifically been included within our standardized measure disclosure. Nonetheless, in preparing this response to Comment No. 10, we have determined that including the net cash flows for settlement of retirement obligations would have reduced the standardized measure for 2006 by approximately $2.0 million. This would be less than 1 percent of the total standardized measure of discounted future net cash flows, which we believe is immaterial.

 

Item 9A. Controls and Procedures, page 151

 

Comment No. 11:

 

You state that your Chief Executive and Chief 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.

William Thompson

August 24, 2007

Page 10

 

 

Company’s Response:

 

Our disclosure indicated that our Chief Executive and Chief Financial officers evaluated the effectiveness of our disclosure controls and procedures as defined in Exchange Act Rule 13a–15(e) as of December 31, 2006. We confirm that they concluded that our disclosure controls and procedures as defined in Rule 13a-15(e) were effective. We did not intend, through the language used, to suggest a different or incomplete conclusion.

 

In accordance with the staff’s recommendation, we will clarify our disclosure in future filings. Accordingly, disclosure included within our second quarter 2007 Form 10-Q filed with the SEC on August 9, 2007 stated the following:

 

 

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934), as of June 30, 2007. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

 

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2007 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

 

FORM 10-Q FOR QUARTERLY PERIOD ENDED MARCH 31, 2007

 

Comment No. 12:

 

Please address the comments above as applicable.

 

Company’s Response:

 

Prior to providing these responses to the staff, we filed our second quarter 2007 Form 10-Q with the SEC on August 9, 2007. To the extent the above comments were applicable to our second quarter 2007 Form 10-Q, we updated our interim information and other relevant disclosures within that filing.

William Thompson

August 24, 2007

Page 11

 

 

Petroleum Engineering Comments

 

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

 

Comment No. 13:

 

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

 

Company’s Response:

 

The following expanded Risk Factor has been included under Part II. Other Information - Item 1A. “Risk Factors” within our second quarter 2007 Form 10-Q filed with the SEC on August 9, 2007:

 

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.

 

There are many uncertainties inherent in estimating quantities of proved reserves and their values. The process of estimating oil and natural gas reserves requires interpretation of available technical data and various assumptions, including assumptions relating to economic factors. Significant inaccuracies in interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. The accuracy of reserve estimates is a function of the quality of available data, engineering and geological interpretations and judgment, and the assumptions used regarding quantities of recoverable oil and gas reserves and prices for oil and natural gas. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those assumed in our estimates. These variances may be significant. Any significant variance from the assumptions used could cause the actual quantity of our reserves and future net cash flow to be materially different from our estimates. In addition, results of drilling, testing and production and changes in oil and natural gas prices after the date of the estimate may result in substantial upward or downward revisions.

 

In each of the last three years the estimated proved reserve additions achieved through drilling activity and acquisition have been partially offset by significant negative revisions to previous estimates of our proved developed and undeveloped oil and gas reserves. These downward revisions were 29.6 Bcfe, 21.6 Bcfe and 39.1 Bcfe for the 2006, 2005 and 2004 year-end reserve estimates, respectively. In addition to other factors, these negative revisions were primarily driven by the results of our ongoing drilling and completion activities in our East Blanco Field located in New Mexico. The operations and reserves of this property were initially acquired in a transaction completed in 2003. The revisions at the East Blanco Field were primarily attributed to lower than expected production results from drilling activities conducted to further delineate the boundaries of the field. The lower reserves from the delineation wells, in turn, prompted revisions to previous reserve estimates (proved undeveloped and proved non-producing) for properties offsetting the delineation wells drilled.

 

Similar disclosure, as appropriate, will be included in future filings with the SEC. Since the 2006 10-K risk factor has been updated in response to your comment through the second quarter 2007 Form 10-Q, we do not believe that any modification of the 2006 Form 10-K is required for this matter.

William Thompson

August 24, 2007

Page 12

 

 

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

 

Comment No. 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.

 

Company’s Response:

 

We agree that paragraph 11 of SFAS 69 requires separate disclosure for changes to our proved reserves due to “extensions and discoveries” and “purchases of minerals in place”. In addition, explanation of “significant changes” within the table should be disclosed.

 

Although our presentation combined the changes for “extensions and discoveries” and “purchases of minerals in place” into one line as “Additions – Extensions/Acquisitions”, we believe that our overall financial statement footnote disclosure provides adequate explanation of “significant changes” in proved reserves. Footnote 21, “Acquisitions”, provides detailed disclosure of acquisitions completed during 2006 that included approximately 62 Bcfe of proved reserves. This disclosure explains approximately 85 percent of the change in proved reserves included in the combined “Additions – Extensions/Acquisitions” line. The other “significant change” to proved reserves worthy of additional explanation was the “Revisions to previous estimates” line which is described in the narrative below the table within this related disclosure.

 

In future filings, we will provide separate disclosure for each specified line item within paragraph 11 of SFAS 69. In addition, we will provide additional explanation, as appropriate, of all “significant changes” within our proved reserves.

William Thompson

August 24, 2007

Page 13

 

 

Standardized Measure of Discounted Future Net Cash Flows, page 148

 

Comment No. 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.

 

Company’s Response:

 

The disclosure requirements of Paragraph 30 of SFAS 69 related to “Future development and production costs” are stated as follows:

 

“Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.”

 

We did not deem our estimated development expenditures to be significant in the context of the above requirements as they represented 10 percent, 14 percent and 21 percent of our estimated future production and development costs for 2004, 2005 and 2006, respectively. In consideration of the staff’s comment and the increasing significance of our estimated development expenditures, we will expand our related disclosures in our future filings, as appropriate, to clarify the estimated costs included in our Standardized Measure of Discounted Future Net Cash Flows.

 

The estimated “Future development and production costs” must be based on year-end costs and assume continuation of existing economic conditions. Accordingly, projected unit production costs included in the standardized measure calculation averaged $2.19 per Mcfe for the life of the analysis compared to a 2006 historical production cost of $1.86. The difference is primarily related to the effect of forecasted production declines on the fixed operating costs. Even though the initial cost estimates in the calculation are consistent with the 2006 historical production costs, the per unit cost increased as production declined.

William Thompson

August 24, 2007

Page 14

 

 

Comment No. 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.

 

Company’s Response:

 

Pertaining to the staff’s request for additional disclosure of the remaining East Blanco proved reserves, we direct the staff to pages 16-20 within Part 1. Items 1 and 2, “Business and Properties”, of our 2006 Form 10-K. In these disclosures, we present our proved developed, proved undeveloped and total reserves by state. Within the narrative under "Oil and Gas Segment" and immediately preceding "Summary Oil and Gas Reserve Data", we explain that the reserves located in New Mexico are primarily located in the East Blanco Field. To supplement the disclosure of reserve revisions that was provided within Note 23 of our 2006 Form 10-K, we have added detail of our reserve revision history through an update to our risk factors in our second quarter 2007 Form 10-Q. This updated risk factor is provided within our response to Comment No. 13 above.

 

Regarding the staff’s inquiry of the procedures adopted to avoid future negative revisions, we believe it is most applicable to emphasize and describe the knowledge we have gained while developing the field since our 2003 acquisition of these properties.

 

The geology and completion history is complex in the East Blanco field. The field has four productive formations, and for many of the wells, the production is commingled. The three upper formations are shallow tertiary deposits that are more variable than originally thought and some of the areas have a water drive component which can be difficult to predict. Additional well and individual zone testing since the 2003 acquisition has continued to refine our understanding of these formations. This additional well control has enabled us to refine our initial production/decline reserve calculations with more detailed volumetrics. Improved well control also has helped differentiate the more productive areas from the higher water production areas for each formation, and has improved allocation of production from the various formations. The lower most formation is a fractured, tight gas sand reservoir which has benefited from the transition to horizontal drilling over the past two years.

 

We continue to strive to understand this complex geologic setting by improving completion techniques, by gathering additional well data (such as pressures, fracture identification logs, gamma ray logs on horizontal wells, individual zone tests, etc), and limiting commingling of zones. With each new well we gain a more extensive knowledge of the field.

 

In recognition of the field complexities and revisions we have experienced, during 2006 we added additional dedicated resources to our reserve evaluation process. We expended extra effort to assure we had all disciplines (geology, reservoir engineering, and operations) participating with the most current information for each well, well completion and potential offset locations. While our additional field knowledge and additional dedicated resources cannot eliminate the potential for revisions due to the inherent uncertainties associated with reserve estimates, we do believe we have continually taken the steps necessary to assess the available data and prudently manage our reserve evaluations.

William Thompson

August 24, 2007

Page 16

 

 

Mining Engineering Comments

 

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

 

Coal Mining Segment, page 27

 

Comment No. 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 additional assistance, please call Filer Support at 202-942-8900. Otherwise provide the map to the engineering staff for our review.

 

Company’s Response:

 

We have attached a small-scale map showing our mine site for the engineering staff’s information. Please note that the primary value of our coal mine is tied to our “mine-mouth” power generation facilities, not in our ability or intent to sell significant amounts of coal to off-site third parties. Accordingly, we do not believe that inserting a map significantly enhances our disclosures about the location and access to the mine beyond that which is already provided for in the 2006 Form 10-K.

William Thompson

August 24, 2007

Page 17

 

 

William Thompson

August 24, 2007

Page 18

 

 

Comment No. 18:

 

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

 

 

Company’s Response:

 

As Industry Guide 7 is applicable to issuers engaged in “significant mining operations”, we have historically determined that the disclosures within Guide 7 are not applicable to our coal mining operations. While we cannot find an explicit definition of “significant mining activities” within Guide 7, we believe there is a strong correlation to SFAS 69 and its additional disclosure requirements for “significant oil and gas producing activities”. The significance tests set forth in SFAS 69 include revenue, pre-tax operating income and asset tests with significance set at a 10 percent threshold. Applying these tests to our coal mining activities results in less than 5 percent significance in each instance for all years presented. Accordingly, we continue to believe that the additional disclosure requirements of Guide 7 are not applicable to our coal mining activities.

 

William Thompson

August 24, 2007

Page 19

 

 

Comment No. 19:

 

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

 

 

Company’s Response:

 

As noted in our response to Comment No. 18 above, since we are not engaged in “significant mining operations”, we do not believe the additional disclosure requirements of Guide 7 are applicable to our activities.

 

William Thompson

August 24, 2007

Page 20

 

 

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, Assistant Corporate Controller at (605) 721-2346 at any time.

 

Sincerely,