January 11, 2006
Ms. Jill S. Davis
Branch Chief
U.S. Securities and Exchange Commission
Division of Corporation Finance
100 F Street, NE
Mail Stop 7010
Washington, DC 20549-7010
Dear Ms. Davis:
Following are responses to the questions raised in your letter dated December 21, 2005. We believe that information provided in our Form 10-K for the year ended December 31, 2004 is correct and the disclosures are adequate. Even so, we appreciate the staff’s comments and always strive to improve our disclosures to investors and other users of Kerr-McGee’s financial statements. In an effort to enhance communication on the matters raised in your letter, we will make the indicated changes and expanded disclosures discussed below in our 2005 Form 10-K to be filed with the Commission within the next 45 business days. We respectfully request that we be allowed to update our disclosures at that time rather than amending our 2004 Form 10-K. The responses set forth below are numbered to correspond to the numbered comments in the staff’s letter, which have been reproduced here for ease of reference.
Developed and Undeveloped Acreage, page 5
| 1. | We note that the geographical distribution of your net developed acreage differs greatly from that of your net undeveloped acreage. We note that the majority of your net developed acreage is primarily concentrated in the United States and Europe, while your net undeveloped acreage is primarily located in the Asia-Pacific, Africa and Other areas. Please expand your management’s discussion and analysis, capital resources and liquidity disclosure to explain to investors the extent to which the geographical distribution of your operations is expected to change based on your current investment in developed and undeveloped acreage. Consider providing a time horizon over which this change could take place as well as a discussion of the additional risks associated with operating in different countries and operating environments (e.g., political, on versus offshore, primarily oil versus gas and other geological and development factors). |
Kerr-McGee’s undeveloped acreage represents investment in exploratory acreage, which may or may not be developed in the future once technical evaluation of the prospective acreage is complete. If any exploratory prospects are generated on this acreage and if those prospects were successfully drilled and subsequently developed, our operations logically would expand into those geographical areas. Kerr-McGee’s undeveloped acreage inventory presented under Developed and Undeveloped Acreage -- Other International in the 2004 Form 10-K consists of large exploration blocks which are typical for frontier exploration in foreign countries. The amount of the international acreage does not necessarily reflect the future direction of the company’s operations and, in most cases, our rights to explore these areas were granted with only a nominal upfront capital investment (lease bonus). Based on the current status of exploration activities on the undeveloped acreage listed under Other International, it would be difficult if not impossible to provide an accurate time horizon over which that acreage might be developed if ever. Any estimate would be entirely speculative in nature.
U.S. Securities and Exchange Commission
January 11, 2006
Page 2
The company’s activities in areas identified as Other International are discussed in the Exploration and Development Activities section of the 2004 Form 10-K beginning on page 15. Our operations in foreign countries do entail certain risks and we believe those risks are disclosed adequately under the Risk Factors section of the Form 10-K.
In future filings, we will add disclosure similar to the following in management’s discussion and analysis based on the appropriate facts and circumstances at the time. This example is based on circumstances in existence at the time our 2004 Form 10-K was filed:
The company has the right to explore undeveloped acreage in certain foreign countries, including Australia, Canada, Benin, Bahamas, Brazil and Morocco, under contractual arrangements that typically require the company to execute an agreed-upon work program. We plan to invest approximately $85 million in these international areas during 2005 and do not believe that future commitments under these contractual arrangements will have a material impact on our liquidity. Overall, the vast majority of our operations are based in the United States and the U.K. sector of the North Sea which offer stable operating and political environments. Based on our current plans, we don’t contemplate a significant near-term change in the overall geographic distribution of our operations or our risk profile. However, exploration success in these international areas followed by development and production activities could expose the company to additional risks, including the ability to secure equipment and hire experienced labor, working with foreign contractors and governments, less stable operating environments and certain political risks. Additional information related to risks associated with operating in foreign countries is discussed in the Risk Factors section of this annual report on Form 10-K under Items 1. and 2. Business and Properties.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Exploration and Production, page 32
| 2. | We note your disclosure that you “Replaced 280% of 2004 production largely as a result of the Westport merger,” and that you realized an “exploration-based production replacement of only 34%.” Due to the variable components of this ratio, please revise your discussion to address each of the following, without limitation. |
| · | Describe how the ratio is calculated. We would expect the information used to calculate this ratio to be derived directly from the line items disclosed in the reconciliation of beginning and ending proved reserve quantities, which is required to be disclosed by paragraph 11 of SFAS 69. |
U.S. Securities and Exchange Commission
January 11, 2006
Page 3
| · | Identify the status of the proved reserves that have been added (e.g., proved developed vs. proved undeveloped). It is not appropriate to calculate this ratio using: |
| ° | non-proved reserve quantities, or, |
| ° | proved reserve additions that include both proved reserve additions attributable to consolidated entities and investments accounted for using the equity method. |
| · | Identify the reasons why proved reserves were added. |
| ° | The reconciliation of beginning and ending proved reserves, referred to above, includes several line items that could be identified as potential sources of proved reserve additions. Explain to investors the nature of the reserve additions, and whether or not the historical sources of reserve additions are expected to continue, and the extent to which external factors outside of managements’ control impact the amount of reserve additions from that source from period to period. |
| · | Explain the nature of and the extent to which uncertainties still exist with respect to newly discovered reserves, including, but not limited to regulatory approval, changes in oil and gas prices, the availability of additional development capital and the installation of additional infrastructure. |
| · | Indicate the time horizon of when the reserve additions are expected to be produced to provide investors a better understanding of when these reserve additions could ultimately be converted to cash inflows. |
| · | Disclose how management uses this measure. |
| · | Disclose the limitations of this measure. |
The production replacement rate is calculated directly from line items disclosed in the reconciliation of beginning and ending proved reserve quantities shown on page 145 of the company’s 2004 Form 10-K. The following summarizes the calculations:
Production Replacement Rate | Barrels of Oil Equivalent (millions) |
Purchase of Reserves in Place | 282 |
Plus: Revisions of Previous Estimates | 14 |
Plus: Extensions, Discoveries & Other Additions | 25 |
| | |
Total Reserve Additions | 321 |
| | |
Divided By: Production | 114 |
| | |
Production Replacement Rate(A) | 281% |
(A) Production replacement rate was rounded to 280% in the 2004 Form 10-K.
U.S. Securities and Exchange Commission
January 11, 2006
Page 4
Exploration-Based Production Replacement Rate | |
Revisions of Previous Estimates | 14 |
Plus: Extensions, Discoveries & Other Additions | 25 |
| | |
Total Exploration-Based Reserve Additions | 39 |
| | |
Divided By: Production | 114 |
| | |
Exploration-Based Production Replacement Rate | 34% |
These calculations do not include non-proved reserve quantities. Also, we do not have any proved reserves attributable to investments accounted for using the equity method.
In future filings, we will add disclosure similar to the following in management’s discussion and analysis based on the appropriate facts and circumstances at the time. This example is based on circumstances in existence at the time our 2004 Form 10-K was filed:
The following characterizes the status of the proved reserve quantities added in 2004:
| | Barrels of Oil Equivalent (millions) |
Proved Developed | 412 |
Proved Undeveloped (A) | (91) |
| | |
Total Proved Reserve Additions | 321 |
(A) The proved undeveloped reserves shown above are negative as a result of a net positive movement of reserves from the undeveloped to developed category. In other words, our net level of undeveloped reserves declined as a result of development activity which occurred in 2004.
Proved reserve additions for 2004 (including purchases of reserves in place, revisions of previous estimates and extensions, discoveries and other additions) came from a variety of sources. The largest contributor for the year (87%) was the merger with Westport Resources, which added approximately 280 million barrels of oil equivalent. Mergers and other acquisitions are not predictable as a source of future proved reserve additions and depend on a variety of factors beyond management’s control.
Exploration-based reserve additions (including both revisions of previous estimates and extensions, discoveries and other additions) are dependent largely on future successful exploratory drilling. Exploration-based reserve additions added approximately 39 million barrels of oil equivalent in 2004. By its nature, exploratory drilling is unpredictable and reserve additions from exploration can vary greatly from year-to-year. Kerr-McGee controls this risk by limiting its working interest in individual prospects, in effect sharing the risk with other entities, and participating in a broad number of prospects in any given year. The company employs skilled geoscientists and makes substantial investments in technology to minimize exploration risk. However, the ultimate success of the company’s exploration efforts is dependent on factors that are not completely within management’s control.
U.S. Securities and Exchange Commission
January 11, 2006
Page 5
Changes in oil and gas prices can impact the company’s proved reserves by either extending or contracting the economic life of individual fields. As a general rule, Kerr-McGee’s proved reserves are not particularly sensitive to price changes. For example, varying 2004 year-end oil and gas prices by +/- 25% results in a change in proved reserves of only +/- 2%.
Kerr-McGee’s proved reserves at year-end 2004 require an estimated $3.8 billion of future development costs as disclosed in the company’s Standardized Measure of Future Net Cash Flows (the “Standardized Measure”). These expenditures cover all estimated future development costs (including infrastructure). While realization of the full value of the company’s proved reserves is dependent on its ability to fund these expenditures, we are not constrained on our ability to fund future development costs. Our plans with regard to funding future capital expenditures are discussed in the Capital Spending section under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The time horizon for converting newly discovered proved reserve additions to cash inflows varies greatly depending upon the nature of the reserves. For certain long-lived tight gas reservoirs, the time horizon can be relatively long compared to other newly added reserves, such as those in the Gulf of Mexico which may be converted to cash inflows over a much shorter time horizon. Economic runs used to develop the company’s Standardized Measure give the following breakdown of the time horizon for production of the company’s proved reserves and a relative comparison to year-end 2003:
| | % of Total Proved Reserves |
Time Frame | 2003 | 2004 |
< 10 years | 79% | 76% |
> 10 years | 21% | 24% |
Kerr-McGee’s management uses the production replacement ratio as a measure of growth for the company’s proved reserve base. Management also uses the production replacement ratio to gauge Kerr-McGee’s performance relative to its peer group. The production replacement ratio does have certain limitations. In isolation, it does not indicate the cost of new proved reserve additions and therefore must be viewed in association with other metrics (such as Finding, Development and Acquisition costs) in order to gauge how cost effectively new reserves are being added. The ratio, used in isolation, also is not indicative of the profitability of newly added proved reserves relative to other companies. Other measures, such as Standardized Measure value or future production cost must be used in conjunction with production replacement ratios to get a more comprehensive assessment.
Liquidity and capital resources, page 30
| 3. | Please expand your managements’ discussion and analysis to explain how the age and decline rate composition of your upstream asset portfolio is expected to impact your cash flows in future periods. Also, identify the extent to which recent changes in the quantity of your proved reserves/capacity as a result of acquisitions and dispositions have changed the expected amount and/or timing of cash flows for next year and beyond. |
U.S. Securities and Exchange Commission
January 11, 2006
Page 6
In future filings, we will add disclosure similar to the following in management’s discussion and analysis based on the appropriate facts and circumstances at the time. This example is based on circumstances in existence at the time our 2004 Form 10-K was filed:
Future cash flows from the company’s upstream asset portfolio follow a time horizon which is logically similar to production of the company’s proved reserves. Economic runs used to develop the company’s 2004 Standardized Measure indicate that about 79% of the company’s future net cash flows will be realized over a ten year time horizon.
The most significant increase in proved reserves for 2004 was the Westport Resources merger. As a result of the merger, which consisted of predominantly long-life gas reserves, the company’s base decline rate improved. While this stabilizes the company’s overall production profile, it also increases the proportion of production and future cash flows which will be realized over a longer time horizon. Changes in the overall amount of future cash flows as a result of acquisitions and dispositions during 2004 are shown in the company’s Reconciliation of Changes in Discounted Future Net Cash Flows disclosure included under Note 33 to the Consolidated Financial Statements in Item 8 of this annual report on Form 10-K. As noted therein, as a result of purchases of reserves in place occurring in 2004, the company’s discounted future net cash flows increased by $3.85 billion. Sales of reserves in place occurring in 2004 resulted in a decrease in discounted future net cash flows of $204 million.
Financial Statements
Note 1. The Company and Significant Accounting Policies
Goodwill and Other Intangible assets, page 85
| 4. | We note that your second quarter 2004 goodwill impairment test did not result in an impairment charge. Please clarify i) when you test goodwill for impairment on an annual basis by reporting unit and ii) whether or not it is the same date each year. Refer to paragraph 26 of SFAS 142. In addition, please clarify whether or not the goodwill resulting from your June 2004 acquisition of Westport was tested for impairment as part of your second quarter 2004 goodwill impairment test. |
Most of our goodwill ($1.2 billion) arose from two major exploration and production company acquisitions - HS Resources in August 2001 and Westport in June 2004. We also have a minor amount of goodwill ($12 million) associated with our Chemical-Pigment segment. We test goodwill for impairment on an annual basis by reporting unit at the same time each year (June) and have not varied the timing of that analysis. Goodwill recognized in the Westport acquisition was not tested for impairment as part of our second quarter 2004 analysis since Westport had just been acquired on June 25, 2004, although it was subsequently tested in June 2005 with no impairment indicated.
U.S. Securities and Exchange Commission
January 11, 2006
Page 7
Note 27. Segment Information, page 128
| 5. | Please expand your disclosure to state the factors used to identify your reportable segments and whether or not operating segments have been aggregated as required by paragraph 26(a) of SFAS 131. |
We will expand our disclosures to state the factors we considered in determining our reportable segments in the company’s 2005 Form 10-K. Although paragraph 17 of SFAS 131 allows operating segments to be aggregated into reportable segments in certain circumstances, we have not aggregated our operating segments because they produce dissimilar products and have significantly different economic characteristics.
In future filings, we will revise our segment disclosure in response to the staff’s concerns. The following example presents revised segment disclosures for our 2004 Form 10-K based on circumstances in existence at that time (additions underscored):
The company has three operating segments: oil and gas exploration and production, production and marketing of titanium dioxide pigment, and production and marketing of other chemical products. These segments are managed separately because of their distinctly different products, operating environments and capital expenditure requirements. We routinely review the operating results of these segments individually to make decisions about resources to be allocated to the segment and to assess their individual performance. The exploration and production unit explores for . . . .
Note 29. Costs Incurred in Crude Oil and Natural Gas Activities, page 138
| 6. | We note your inclusion of asset retirement obligations and your footnote (4), which states that “Asset retirement costs represent the noncash increase in property, plant and equipment recognized when initially recording liability for abandonment obligations (discounted) associated with the company’s oil and gas wells and platforms.” Please remove the asset retirement obligations line item as there is no provision for this line item in paragraph 21 and Illustration 2 of SFAS 69. Refer to our February 2004 industry letter at http://www.sec.gov/divisions/corpfin/guidance/oilgasletter.htm. |
We have followed the guidance in the SEC staff’s February 2004 letter which requires that an oil and gas producer reflect asset retirement costs in its cost incurred disclosures in the period the obligation arose. We have shown this item separately in our cost incurred disclosures because we believe such presentation provides meaningful information to users of our financial statements - that is, the amount of ‘cash’ costs incurred in exploration and development activities (capital spend being an important metric in the oil and gas industry) separate from costs incurred which arose due to initial recognition of new abandonment obligations that will not result in a cash expenditure for many years. We believe that the alternative - including such amounts within other line items in the cost incurred table - would make our disclosures less transparent.
U.S. Securities and Exchange Commission
January 11, 2006
Page 8
We acknowledge that this line item is not contemplated in paragraph 21 and illustration 2 of SFAS 69, although that disclosure format predated the issuance of SFAS 143 by some time. Also, we believe that SFAS 69 sets forth the minimum disclosure requirements and that our presentation (which others in the industry also have adopted) is an improvement upon the basic standard.
Note 33. Standardized Measure of and Reconciliation of Changes in Discounted Future Net Cash Flows (Unaudited), page 146
| 7. | We note your footnote (2), which states that “Estimated future net cash flows before income tax expense, discounted at 10%, totaled approximately $17.0 billion, $13.2 billion and $10.3 billion, for 2004, 2003 and 2002, respectively.” As there is no provision for this measure in paragraph 30 and Illustration 5 of SFAS 69, this presentation appears to be a non-GAAP measure. Please explain how you have or intend to comply with the requirements of Item 10(e) of Regulation S-K and/or Regulation G. Clarify whether the measure is a liquidity or a performance measure. Refer to Release Number 33-8176: Conditions for Use of Non-GAAP Financial Measures, located at http://www.sec.gov/rules/final/33-8176.htm. |
Estimated future net cash flows before income tax expense, discounted at 10% (commonly referred to as “PV 10”) is simply the Standardized Measure associated with the company’s proved reserves before the tax calculations required by SFAS 69 are performed. This presentation is similar to what was required by SEC rules prior to SFAS 69 and is still disclosed by some oil and gas producers as additional supplemental information to the Standardized Measure table -- otherwise, such amounts are presented on exactly the same basis as the after-tax Standardized Measure.
We believe this disclosure provides somewhat useful incremental information to any investors interested in knowing pre-tax Standardized Measure, but will delete such non-GAAP measure from all future filings.
Exhibits 31.1 and 31.2
| 8. | We note the wording of your certifications pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 does not precisely match the language set forth in the Act. In this regard, your certifications include references throughout the certification to the annual report. Refer to Item 601(b)(31) of Regulation S-K for the exact text of the required Section 302 certification, and amend your exhibits as appropriate. This comment also applies to you Forms 10-Q. |
The company believes that the certifications made by the Chief Executive Officer and the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (the "Act") do not differ in any material respect from the language set forth in the Act. The only modifications were made for the purpose of conforming to the style used by the company in the rest of the Form 10-K ("annual report" instead of "report" and "company" instead of "registrant"). Nevertheless, the Company appreciates the staff's comment and will conform the certifications to the exact text provided in Item 601(b)(31) of Regulation S-K in all future Form 10-K and Form 10-Q filings.
U.S. Securities and Exchange Commission
January 11, 2006
Page 9
In addition to the foregoing, the company acknowledges that (i) the company is responsible for the adequacy and accuracy of the disclosure in its Form 10-K for the year ended December 31, 2004, (ii) 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 (iii) 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.
Please advise if you have additional questions or require further clarification.
Sincerely,
/s/ John M. Rauh
