April 12, 2005
Securities and Exchange Commission
450 Fifth Street, N.W.
Washington, D.C. 20549-0405
Re: Comment Letter Received March 7, 2005
Credo Petroleum Corporation
Form 10-KSB, Filed January 27, 2005
File No. 000-08877
Attention: Ms. Jennifer Goeken
Dear Ms. Goeken:
This letter is Credo Petroleum Corporation’s (the “Company”) response to the comment letter received from the Securities and Exchange Commission (‘SEC”) dated March 7, 2005. This letter will address each of the SEC’s comments in the order that they appear in the comment letter along with the Company’s proposed response.
Through its year ended October 31, 2004, the Company has been a “small business issuer” as defined by Regulation S-B and has filed its 1934 Act filings using the limited disclosures required by Regulation S-B. Effective November 1, 2004, the Company no longer qualifies as a “small business issuer” and will file its future 1934 Act filings using the disclosures required by Regulation S-K and
S-X.
Management’s Discussion and Analysis, page 7
Drilling Activities, page 9
1. The Company replaced 183% of the reserves produced in fiscal 2004. This reserve replacement percentage is derived directly from the line items disclosed in the reconciliation of beginning and ending proved reserve quantities contained in Footnote 6 to the consolidated financial statements, Supplementary Oil and Gas Information, page 24 of the Company’s Form 10-KSB. The ratio is calculated in Mcf of gas-equivalent (‘Mcfge”) for the fiscal year ended October 31, 2004 as the sum of revisions of previous estimates, extensions and discoveries, and purchases of reserves in place divided by production in Mcfge for the same period. The table below shows the calculation used by the Company.
Description |
| Gas (Mcf) |
| Oil (Bbls) |
| Conversion |
| Oil |
| Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of previous estimates |
| 68,000 |
| 39,000 |
| 6 |
| 234,000 |
| 302,000 |
|
Extensions and discoveries |
| 2,999,000 |
| 23,000 |
| 6 |
| 138,000 |
| 3,137,000 |
|
Purchases of reserves in place |
| 130,000 |
| 1,000 |
| 6 |
| 6,000 |
| 136,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total reserve additions |
| 3,197,000 |
| 63,000 |
|
|
| 378,000 |
| 3,575,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
| 1,710,000 |
| 41,000 |
| 6 |
| 246,000 |
| 1,956,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserve replacement percentage |
|
|
|
|
|
|
|
|
| 183 | % |
1
For the year ended October 31, 2004 the Company’s finding cost per Mcfge was $1.98. Finding costs are derived from the line item Total Including Asset Retirement Obligation disclosed in the table identifying Acquisition, Exploration and Development Costs Incurred contained in Footnote 6 to the consolidated financial statements, Supplementary Oil and Gas Information, page 23 of the Company’s Form 10-KSB and from the line items disclosed in the reconciliation of beginning and ending proved reserve quantities contained in Footnote 6 to the consolidated financial statements, Supplementary Oil and Gas Information, page 24 of the Company’s Form 10-KSB. Finding costs have been calculated by dividing the line item called Total Including Asset Retirement Obligation by the amount of estimated net proved reserves added through revisions of previous estimates, discoveries and purchases expressed in Mcfge. The table below shows the calculation used by the Company.
Description |
| 2004 |
|
Total Acquisition, Exploration and Development Costs Incurred including |
|
|
|
Asset Retirement Obligation |
| 7,089,000 |
|
|
| Divided By |
|
Total reserve additions (see above calculation) |
| 3,575,000 |
|
|
|
|
|
Finding cost per Mcfge |
| 1.98 |
|
Net proved reserve additions including the portions that are proved developed versus proved undeveloped can be calculated from the information in Footnote 6 to the consolidated financial statements, Supplementary Oil and Gas Information, page 24 of the Company’s Form 10-KSB. Net proved reserve additions from extensions and discoveries totaled 3,137,000 Mcfge consisting of proved developed reserves of 1,857,000 Mcfge and proved undeveloped reserves of 1,280,000 Mcfge. As is stated in Management’s Discussion and Analysis of Financial Condition and Results of Operations, Oil and Gas Activities, Drilling Activities, and Calliope Gas Recovery System on page 9 of the Company’s Form 10-KSB, these proved reserve additions for the fiscal year ended October 31, 2004 were primarily the result of activity on the Company’s two core projects, drilling along the shelf of the Northern Anadarko Basin in northwest Oklahoma and application of the Company’s patented liquid lift system on low pressure gas wells. The remaining net proved reserve additions of 438,000 Mcfge were comprised of revisions of previous estimates of 302,000 Mcfge and purchases of proved developed reserves in place of 136,000 Mcfge.
The Company used only proved reserves to calculate the reserve replacement percentage and finding costs described above and did not include any proved reserves attributable to consolidated entities or investments accounted for using the equity method.
The finding costs and production replacement measures are used by the Company as one way of measuring the Company’s performance and comparing it to that of its competitors and the industry. These performance statistics will subsequently be published by industry analysts. The calculation of both of these performance measures is reliant upon the Company’s estimate of its proved oil and gas reserve quantities. Additionally, both of these performance measures are historical in nature and are calculated as of a specific date and, may not be indicative of the Company’s future performance.
2
The Company will continue to actively pursue adding reserves through its two core projects in fiscal 2005 and expects these activities to continue to be the primary source of its reserve additions. However, the timing and extent of such activities can be dependent on many factors which are beyond the Company’s control, including but not limited to, the availability of oil field services such as drilling rigs, production equipment and related services and access to wells for application of the Company’s patented liquid lift system on low pressure gas wells. The prevailing price of oil and gas has a significant affect on demand and, thus, the related cost of such services and wells.
All of the Company’s oil and gas properties are located on-shore in the continental United States. The Company is not aware of any material adverse issues related to its reserves regarding regulatory approval, the availability of additional development capital, or the installation of additional infrastructure. The Company’s future drilling activities may not be successful, and its overall drilling success rate may change. Unsuccessful drilling activities could have a material adverse effect on the Company’s results of operations and financial condition. Also, the Company may not be able to obtain the right to drill in areas where it believes there is significant potential for the Company.
The Company’s reserves, and reserve values, are concentrated in 43 properties (“Significant Properties”). Some of the Significant Properties are individual wells and others are multi-well properties. At October 31, 2004, the Significant Properties represent 24% of the Company’s total properties but a disproportionate 75% of the discounted value (at 10%) of the Company’s reserves. Individual Calliope wells comprise 26% of the Significant Properties and represent 37% of the discounted reserve value of such properties. Wells drilled on the four prospects discussed in Item 2. Properties, General, comprise 30% of the Significant Properties and represent 30% of the discounted value of such properties.
Estimates of reserve quantities and values for certain Significant Properties must be viewed as being subject to significant change as more data about the properties becomes available. Such properties include wells with limited production histories (including wells on which the Company’s patented liquid lift system has been recently installed) and properties with proved undeveloped or proved non-producing reserves. In addition, the Company’s patented liquid lift system is generally installed on mature wells. As such, they contain older down-hole equipment that is more subject to failure than new equipment. The failure of such equipment, particularly casing, can result in complete loss of a well. At October 31, 2004, natural gas represented 86% and crude oil represented 14% of total reserves. At October 31, 2004, approximately 8% of the Company’s estimated reserves were classified as proved undeveloped.
Price changes will affect the economic lives of oil and gas properties and, therefore, price changes may cause reserve revisions. Historically, such price changes have not caused significant proved reserve revisions by the Company, except in 1986 when a 51% decline in oil prices and a 45% decline in gas prices resulted in an 8.7% reduction in estimated proved reserves.
3
One measure of the life of the Company’s proved reserves can be calculated by dividing proved reserves at fiscal year end 2004 by production for fiscal year 2004. This measure yields an average reserve life of nine years. Since this measure is an average, by definition, some of the Company’s properties will have a life shorter than the average and some will have a life longer than the average. The expected economic lives of the Company’s individual properties varies widely depending on, among other things, the size and quality of the reservoir, oil and natural gas prices, possible curtailments in consumption by purchasers, and changes in governmental regulations or taxation. As a result, the Company’s actual future net cash flows from proved reserves could be materially different from its estimates.
The Company’s success depends primarily on locating and producing new reserves, the level of production from existing wells, and prices of oil and natural gas. Production from the Company’s oil and gas properties declines over time. In order to maintain current production rates the Company must locate and develop or acquire new oil and gas reserves to replace those being depleted by production. In addition, competition for oil and gas leases, oil field services, and producing oil and gas properties is intense and many of the Company’s competitors have financial and other resources substantially greater than those available to it. Without success on its core projects, the Company’s reserves, production and revenues will decline rapidly.
Company Proposed Response:
The Company has addressed comment number 1 from the SEC by providing expanded disclosure, supplemental information and calculations that address each of the points raised. The Company proposes to expand its current disclosure by including the applicable information contained in this response on a prospective basis for any 1934 Act filings where this disclosure is required beginning with the second quarter ended April 30, 2005.
Critical Accounting Policies and Estimates, page 11
In response to SEC comment number 2, the Company proposes to expand its Critical Accounting Policy disclosure as set forth below.
2. Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that its estimates are reasonable and that actual results will not vary significantly from the estimated amounts. The Company believes the following accounting policies and estimates are critical in the preparation of its consolidated financial statements: the carrying value of its oil and gas properties, the accounting for oil and gas reserves, and the estimate of its asset retirement obligations.
4
OIL AND GAS PROPERTIES. The Company uses the full cost method of accounting for costs related to its oil and gas properties. Capitalized costs included in the full cost pool are depleted on an aggregate basis using the units-of-production method. Depreciation, depletion and amortization is a significant component of oil and gas properties. A reduction in proved reserves without a corresponding reduction in capitalized costs will cause the depletion rate to increase.
Both the volume of proved reserves and any estimated future expenditures used for the depletion calculation are based on estimates such as those described under “Oil and Gas Reserves” below.
The capitalized costs in the full cost pool are subject to a quarterly ceiling test that limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and result in lower depreciation and depletion in future periods. A write-down may not be reversed in future periods, even though higher oil and gas prices may subsequently increase the ceiling.
The Company has made only one ceiling write-down in its 26-year history. That write down was made in 1986 after oil prices fell 51% and gas prices fell 45% between fiscal year end 1985 and 1986.
Changes in oil and gas prices have historically had the most significant impact on the Company’s ceiling test. In general, the ceiling is lower when prices are lower. Even though oil and gas prices can be highly volatile over weeks and even days, the ceiling calculation dictates that prices in effect as of the last day of the test period be used and held constant. The resulting valuation is a snapshot as of that day and, thus, is generally not indicative of a true fair value that would be placed on the Company’s reserves by the Company or by an independent third party. Therefore, the future net revenues associated with the estimated proved reserves are not based on the Company’s assessment of future prices or costs, but rather are based on prices and costs in effect as of the end the test period.
OIL AND GAS RESERVES. The determination of depreciation and depletion expense as well as ceiling test write-downs related to the recorded value of the Company’s oil and gas properties are highly dependent on the estimates of the proved oil and gas reserves. Oil and gas reserves include proved reserves that represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the Company’s control. Accordingly, reserve estimates are often different from the quantities of oil and gas ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.
5
The Company’s reserves, and reserve values, are concentrated in 43 properties (“Significant Properties”). Some of the Significant Properties are individual wells and others are multi-well properties. At October 31, 2004, the Significant Properties represent 24% of the Company’s total properties but a disproportionate 75% of the discounted value (at 10%) of the Company’s reserves. Individual wells on which the Company’s patented liquid lift system is installed comprise 26% of the Significant Properties and represent 37% of the discounted reserve value of such properties. Relatively new wells comprise 30% of the Significant Properties and represent 30% of the discounted value of such properties.
Estimates of reserve quantities and values for certain Significant Properties must be viewed as being subject to significant change as more data about the properties becomes available. Such properties include wells with limited production histories and properties with proved undeveloped or proved non-producing reserves. In addition, the Company’s patented liquid lift system is generally installed on mature wells. As such, they contain older down-hole equipment that is more subject to failure than new equipment. The failure of such equipment, particularly casing, can result in complete loss of a well. Historically, performance of the Company’s wells has not caused significant revisions in its proved reserves.
Price changes will affect the economic lives of oil and gas properties and, therefore, price changes may cause reserve revisions. Price changes have not caused significant proved reserve revisions by the Company except in 1986 when a 51% decline in oil prices and a 45% decline in gas prices resulted in an 8.7% reduction in estimated proved reserves. Based upon this historical experience, the Company does not believe its reserve estimates are particularly sensitive to prices changes within historical ranges.
One measure of the life of the Company’s proved reserves can be calculated by dividing proved reserves at fiscal year end 2004 by production for fiscal year 2004. This measure yields an average reserve life of nine years. Since this measure is an average, by definition, some of the Company’s properties will have a life shorter than the average and some will have a life longer than the average. The expected economic lives of the Company’s properties may vary widely depending on, among other things, the size and quality, natural gas and oil prices, possible curtailments in consumption by purchasers, and changes in governmental regulations or taxation. As a result, the Company’s actual future net cash flows from proved reserves could be materially different from its estimates.
ASSET RETIREMENT OBLIGATIONS. SFAS No. 143, “Accounting for Asset Retirement Obligations” requires that the Company estimate the future cost of asset retirement obligations, discount that cost to its present value, and record a corresponding asset and liability in its Consolidated Balance Sheets. The values ultimately derived are based on many significant estimates, including future abandonment costs, inflation, market risk premiums, useful life, and cost of capital. The nature of these estimates requires the Company to make judgments based on historical experience and future expectations. Revisions to the estimates may be required based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis.
6
Company Proposed Response:
The Company has addressed comment number 2 from the SEC by providing expanded disclosure that address each of the points raised. The Company proposes to modify its current disclosure with the disclosure outlined above on a prospective basis for any 1934 Act filings where it is required beginning with the second quarter ended April 30, 2005.
Financial Statements
Consolidated Balance Sheets
3. The Company’s disclosure in its Annual Report on Form 10-KSB for the fiscal year ended October 31, 2004 related to its exclusive license agreement intangible asset consists of a separate balance sheet line item identifying the net carrying value along with disclosure of accumulated amortization and by calculation from the amounts disclosed on the face of the balance sheet the amortization period, the original carrying value, the amortization expense for the current period and the estimated aggregate amortization expense for each of the five succeeding years. For the periods presented the Company did not specifically discuss its impairment assessment related to this asset.
In response to SEC comment number 3, the Company is providing expanded disclosure for this intangible asset as set forth below.
|
| October 31, 2004 |
| ||
|
| Gross Carrying |
| Accumulated |
|
|
| Amount |
| Amortization |
|
Amortized intangible assets: |
|
|
|
|
|
Exclusive license agreement |
| 699,283 |
| 291,350 |
|
|
|
|
|
|
|
Aggregate amortization expense: |
|
|
|
|
|
For the year ended October 31, 2004 |
|
|
| 69,924 |
|
|
|
|
|
|
|
Estimated amortization expense: |
|
|
|
|
|
For the year ended October 31, 2005 |
|
|
| 69,924 |
|
For the year ended October 31, 2006 |
|
|
| 69,924 |
|
For the year ended October 31, 2007 |
|
|
| 69,924 |
|
For the year ended October 31, 2008 |
|
|
| 69,924 |
|
For the year ended October 31, 2009 |
|
|
| 69,924 |
|
Total |
|
|
| 349,620 |
|
This amortizable intangible asset is an exclusive license agreement related solely to the Company’s patented liquid lift system for low pressure gas wells which is discussed in detail under Management’s Discussion and Analysis of Financial Condition and Results of Operations, Oil and Gas Activities, Calliope Gas Recovery System previously in this Form 10-KSB.
7
The Company reviews the value of its intangible assets in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets,” which requires that it evaluate these assets for impairment whenever events or changes in business circumstances indicate that the carrying amount of the assets may not be fully recoverable or that the useful lives of these assets are no longer appropriate.
At October 31, 2004, this amortizable intangible asset had a net book value of $407,933. The value of this asset is believed to be realizable based on the Company’s estimation of future cash flows from application of the Company’s patented liquid lift system. The Company’s impairment test compares the estimated undiscounted future net cash flows related to this asset with the related net capitalized costs of the asset at the end of each period. If the net capitalized cost exceeds the undiscounted future net cash flows, the cost of the asset is written down to estimated fair value. As of October 31, 2004, the Company has not recorded an impairment write-down for this asset. The estimated undiscounted value of future net cash flows is derived from estimates of proved reserve values. See “Oil and Gas Reserves” above.
Company Proposed Response:
The Company has addressed comment number 3 from the SEC by providing revised disclosure that addresses each of the points raised. The Company proposes to expand and modify its current disclosure with the disclosure outlined above on a prospective basis for any 1934 Act filings where it is required beginning with the second quarter ended April 30, 2005.
Consolidated Statement of Stockholders’ Equity
4. The Company’s disclosure of the components of comprehensive income on the face of the Consolidated Statements of Shareholders’ Equity consisted of presenting the change in the fair value of derivatives, net of tax, with no specific disclosure of the tax amount. While this amount can be approximated by calculating the Company’s effective income tax rate from the information disclosed on the face of the Consolidated Statements of Operations and applying the calculated rate to the change in the fair value of derivatives disclosed on the face of the Consolidated Statements of Shareholders’ Equity, the Company elected to make a prospective change to its disclosure beginning with its Form 10-Q for the Company’s first fiscal quarter ended January 31, 2005. That disclosure was made as a Footnote disclosure in the following manner:
Comprehensive income includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The components of comprehensive income for the three months ended January 31, 2005 and 2004 are as follows:
|
| For the Three Months Ended |
| ||
|
| January 31, |
| ||
|
| 2005 |
| 2004 |
|
Net income |
| 909,000 |
| 1,165,000 |
|
Other comprehensive income(loss): |
|
|
|
|
|
Change in fair value of derivatives, net of tax expense of $177,000 and a tax benefit of $149,000, respectively |
| 429,000 |
| (363,000 | ) |
Total comprehensive income |
| 1,338,000 |
| 802,000 |
|
8
Company Proposed Response:
The Company has addressed comment number 4 from the SEC by providing revised disclosure that addresses the issue raised. The Company proposes to continue with the disclosure enhancements made to its Form 10-Q for the Company’s first fiscal quarter ended January 31, 2005 as outlined above on a prospective basis for any future 1934 Act filings where it is required.
5. The Company’s disclosure of the components of comprehensive income on the face of the Consolidated Statements of Shareholders’ Equity consisted of presenting the change in the fair value of derivatives, net of tax, with no specific disclosure separately identifying the beginning and ending accumulated derivative gain or loss, the related net change associated with current period hedging transactions, and the net charge or credit into earnings. To address SEC comment number 5, the Company will make the following disclosure in the Footnotes to the Consolidated Financial Statements.
|
| Three Months Ended |
| Year Ended |
|
|
| January 31, |
| October 31, |
|
|
| 2005 |
| 2004 |
|
Accumulated gain (loss) on derivatives: |
|
|
|
|
|
Balance beginning of period |
| (437,000 | ) | 180,000 |
|
Realization of hedging gain (losses) |
| 182,000 |
| 59,000 |
|
Net unrealized gain (losses) on price hedge contracts |
| 247,000 |
| (678,000 | ) |
Balance end of period |
| (8,000 | ) | (437,000 | ) |
Company Proposed Response:
The Company has addressed comment number 5 from the SEC by providing a sample of the disclosure that addresses the issue raised. The Company proposes to make the presented disclosure enhancements on a prospective basis for any 1934 Act filings where it is required beginning with the second quarter ended April 30, 2005.
Note 1 Summary of Significant Accounting Policies, page 17
General
6. The Company did not disclose a specific revenue recognition policy because the principles and methods used by the Company are the principles and methods generally followed in the oil and gas industry. In response to SEC comment number 6, the Company is providing an example of its proposed disclosure as set forth below.
9
Revenue Recognition
The Company derives its revenue primarily from the sale of produced natural gas and crude oil. The Company reports revenue gross for the amounts received before taking into account production taxes and transportation costs which are reported as separate expenses. Revenue is recorded in the month production is delivered to the purchaser at which time title changes hands. Payment is generally received between 30 and 90 days after the date of production. The Company makes estimates of the amount of production delivered to purchasers and the prices it will receive. The Company uses its knowledge of its properties; their historical performance; the anticipated effect of weather conditions during the month of production; NYMEX and local spot market prices; and other factors as the basis for these estimates. Variances between estimates and the actual amounts received are recorded when payment is received.
A majority of the Company’s sales are made under contractual arrangements with terms that are considered to be usual and customary in the oil and gas industry. The contracts are for periods of up to five years with prices determined based upon a percentage of a pre-determined and published monthly index price. The terms of these contracts have not had an effect on how the Company recognizes its revenue.
The comment letter also asked the Company to discuss the nature of operating income. The Company’s supplemental response to the question concerning its operating income is set forth below:
The Company’s operating revenue is comprised of contractually based payments made to the Company, as operator, to drill and supervise oil and gas wells. The Company reports these revenues gross for the amounts received before taking into account related costs which are recorded as separate expenses. Revenue is recorded in the month it is received. The Company views providing these services as a profit center and a way to control the operations on wells in which it owns an interest.
Company Proposed Response:
The Company has addressed comment number 6 from the SEC by providing a sample of the disclosure and a supplemental response that addresses the issues raised. The Company proposes to make the presented disclosure enhancements on a prospective basis for any 1934 Act filings where it is required beginning with the second quarter ended April 30, 2005. In addition, the Company believes that the discussion related to operating income provides the information requested and that no further disclosure in 1934 Act filings is necessary.
Oil and Gas Properties, page 17
7. The Company’s disclosure of its accounting policies for Oil and Gas Properties is a component of the Company’s disclosure of Summary of Significant Accounting Policies in Footnote 1 to the Consolidated Financial Statements. The first issue raised by this comment is for the Company to enhance its disclosure about how it accounts for costs related to production activities. An example of the enhanced additional disclosure that the Company would provide is set forth as follows:
All costs relating to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.
10
The second issue raised by this comment is for the Company to disclose if applicable its disclosure about how it accounts for sales and abandonments of oil and gas properties; purchases of reserves; partnerships, joint ventures and drilling arrangements; and other services. The Company has not had any material transactions as described in Article 4-10 (c) (6) (i)-(iv) of Regulation S-X during the last three years. The Company’s response is as follows:
Any transactions that have occurred or may occur in the future have been or will be fully disclosed and accounted for in accordance with the rules described therein.
The third issue raised is for the Company to disclose the table required by Article 4-10 (c) (7) (ii) of Regulation S-X. An example of the form of the enhanced additional disclosure that the Company would provide is set forth as follows:
Unevaluated Oil and Gas Properties. Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization computation until they are evaluated. The following table shows, by category of cost and date incurred, the unevaluated oil and gas property costs (net of transfers to the full cost pool and sales proceeds) excluded from the amortization computation:
Net Costs Incurred |
|
|
| Unevaluated Properties |
|
| Acquisition |
| At October 31, |
| |
During Periods Ended: |
| Costs |
| 2004 |
|
|
|
|
|
|
|
October 31, 2004 |
|
|
|
|
|
October 31, 2003 |
|
|
|
|
|
October 31, 2002 |
|
|
|
|
|
Prior |
|
|
|
|
|
|
|
|
| 2,173,424 |
|
Unevaluated properties consist primarily of lease acquisition and maintenance costs. Prospect leasing and acquisition normally requires one to two years and the subsequent evaluation normally requires an additional one to two years. The Company does not expect to incur significant exploration or development costs related to unevaluated properties.
Company Proposed Response:
The Company has addressed comment number 7 from the SEC by providing a form of the sample disclosures for the first and third issue raised. The Company proposes to make the presented disclosure enhancements on a prospective basis for any 1934 Act filings where it is required beginning with the second quarter ended April 30, 2005. In addition, the Company believes that the discussion related to the second issue raised provides the information requested and that no further disclosure in 1934 Act filings is necessary.
11
Asset Retirement Obligation, page 19
8. As indicated in Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Policies and Estimates, Estimates of Asset Retirement Obligations on page 11 of the Company’s Annual Report on From 10-KSB, the Company considers asset retirement obligations to be a significant estimate. The Company periodically reviews the assumptions used in making this estimate. The values ultimately derived are based on many significant estimates, including future abandonment costs, inflation, market risk premiums, useful life, and cost of capital. The nature of these estimates requires the Company to make judgments based on historical experience and future expectations. These reviews may require revisions to the estimates based on such things as changes to cost estimates or the timing of future cash outlays. Any such changes that result in upward or downward revisions in the estimated obligation will result in an adjustment to the related capitalized asset and corresponding liability on a prospective basis. As a result of this review in 2004 it was determined that the Company’s prior year initial estimation of this liability was low and an upward revision of $503,000 was recorded.
Company Proposed Response:
The Company has addressed comment number 8 from the SEC by providing a supplemental discussion that addresses the issue raised. The Company believes that this discussion regarding the estimation of costs to plug and abandon wells provides the information requested and that no further disclosure in 1934 Act filings is necessary.
Note 5. Exclusive License Agreement Obligation, page 22
9. In Footnote 5 to the Company’s Consolidated Financial Statements, the Company made disclosures related to its exclusive license agreement obligation. Two questions have been raised regarding this disclosure. The first question relates to the meaning of carried interest. In this situation, carried interest means that the licensor’s share of the cost to install the Company’s patented liquid lift system will be paid by the other owners of the project. Once such installation is complete, the licensor will pay its share of all subsequent costs. The second question relates to the Company’s use of 10% as a discount factor when the exclusive license agreement obligation was initially recorded. Historically, the Company has not carried any debt, and, as a result, it was required to estimate a borrowing rate for the Company based upon its credit worthiness, existing interest rates and general market conditions. This transaction was recorded in September of 2000, and, at that time, the Wall Street Journal published prime rate was 9.5%. Based upon this information and the Company’s assessment of its creditworthiness and general market conditions, a determination was made that 10% approximated the Company’s borrowing rate.
Company Proposed Response:
The Company has addressed comment number 9 from the SEC by providing a supplemental discussion that addresses the issues raised. The Company believes that this discussion regarding the definition of carried interest and its use of 10% as a discount factor provides the information requested and that no further disclosure in 1934 Act filings is necessary.
12
Item 8A. Controls and Procedures, page 26
Comment Letter questions 10 - 13
In response to the aforementioned questions the Company will change this disclosure prospectively to the following as required in (1) Item 4. Controls and Procedures for all quarterly reports on Form 10-Q; and (2) Item 9A. Controls and Procedures for all annual reports on Form 10-K. The Company has incorporated changes to Item 4. Controls and Procedures in its Quarterly Report on Form 10-Q for the three month period ended January 31, 2005 and will continue to do so on all future filings. The Company’s current disclosure is as follows:
The effectiveness of the Company’s or any system of disclosure controls and procedures is subject to certain limitations, including the exercise of judgment in designing, implementing and evaluating the controls and procedures, the assumptions used in identifying the likelihood of future events, and the inability to eliminate misconduct completely. As a result, there can be no assurance that the Company’s disclosure controls and procedures will detect all errors or fraud. By their nature, the Company’s or any system of disclosure controls and procedures can provide only reasonable assurance regarding management’s control objectives.
Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, the Company evaluated the design and operation of its disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the “Exchange Act”) as of January 31, 2005. On the basis of this review, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, concluded that the Company’s disclosure controls and procedures are designed, and are effective, to give reasonable assurance that the information required to be disclosed by the Company in reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, in a manner that allows timely decisions regarding required disclosure. There were no changes in the Company’s internal controls over financial reporting that occurred in the first quarter of 2005 that materially affected or were reasonably likely to materially affect, its internal control over financial reporting.
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The Company makes the following acknowledgements:
1. The Company is responsible for the adequacy and accuracy of the disclosure in the filings;
2. 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
3. The Company may not assert staff comments as a defense in any proceedings initiated by the Commission or any person under the federal securities laws of the United States.
The Company has distributed an Annual Report to its shareholders and held its Annual Shareholders Meeting and would prefer that its Managements Discussion and Analysis of Financial Condition and Results of Operations, Consolidated Financial Statements and Footnotes in its Annual Report on Form 10-KSB remain identical to those found in its Annual Report to Shareholders. All of the Company’s responses have either described an expanded disclosure in the Quarterly Report on Form 10-Q for the first fiscal quarter ended January 31, 2005 or indicated an intent to expand disclosure on a prospective basis beginning with all 1934 Act filings where this disclosure is required beginning with the second fiscal quarter ended April 30, 2005.
CREDO PETROLEUM CORPORATION | ||
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By: | /S/ James T. Huffman |
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| James T. Huffman | |
| Chief Executive Officer | |
| (Principal Executive Officer) | |
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By: | /S/ David W. Vreeman |
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| David W. Vreeman | |
| Chief Financial Officer | |
| (Principal Financial and Accounting Officer) | |
Please contact me directly via telephone (303-297-2200) or fax (303-297-2204) to let me know the status of the Company’s response to this comment letter and what actions if any are required of the Company.
Sincerely,
/S/ David W. Vreeman |
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David W. Vreeman | |
Vice President and Chief Financial Officer | |
Credo Petroleum Corporation | |
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