October 9, 2006
BY FACSIMILE (202-772-9369) AND COURIER
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549-7010
| Re: | Bill Barrett Corporation, Form 10-K for the Fiscal Year Ended December 31, 2005, File No. 001-32367 |
Dear Mr. Wojciechowski:
On behalf of Bill Barrett Corporation (the “BBC” or “Company”), this letter responds to the Staff’s comments in the Staff’s letter dated September 15, 2006 with comments to the Company’s Form 10-K for the fiscal year ended December 31, 2005, File No. 001-32367. The following responses are keyed to the Staff’s comments. We have discussed these responses with the chairman of the Audit Committee of our Board of Directors.
Based on our review of the Staff comment letter, and as further described herein, we believe that our filed Form 10-K is not materially inaccurate or misleading and, therefore, believe that any amendment to our existing filing is not necessary. Instead, as indicated in our responses below, we hereby propose to make appropriate clarifications or modifications to our disclosures in future filings. We respectfully request an opportunity to discuss this response letter further with the Staff if, following a review of this information, the Staff does not concur with our analysis.
Form 10-K for the Fiscal Year Ended December 31, 2005
Business and Properties, page 3
Oil and Gas Data, page 19
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
October 9, 2006
Page 2
Production and Price History, page 21
Comment 1. Footnote 3 to the table of Average Costs explains that the measure of general and administrative costs per Mcfe excludes stock-based compensation expense. A non-GAAP measure is defined as a numerical measure that excludes amounts that are included in the most directly comparable measure calculated and presented in accordance with GAAP in the statement of income. As such, your measure of general and administrative costs per Mcfe appears to meet the definition of a non-GAAP measure. Please provide the required disclosures of Item 10(e) of Regulation S-K as well as the disclosures outlined in the answer to question 8 of the Frequently Asked Questions Regarding the Use of Non-GAAP Financial Measures.
Response. In future filings, the Company will revise its disclosure in the table to include only GAAP measures, including General and Administrative Costs as shown on the face of the Consolidated Statements of Operations. The Company may include footnote disclosure of the amount of stock-based compensation expense included in the General and Administrative Expense in order to enable the reader to understand the impact of stock-based compensation on the Company’s General and Administrative Expense. Should we decide to include a non-GAAP measure, the Company will provide the required disclosures of Item 10(e) of Regulation S-K as well as the disclosures outlined in the answer to question 8 of the Frequently Asked Questions Regarding the Use of Non-GAAP Financial Measures.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 47
Contractual Obligations, page 60
Comment 2. Footnote 1 to the table of contractual obligations explains that the table excludes asset retirement obligations, liabilities associated with derivatives and liabilities associated with commitment or other fees on your credit facility. The guidance in Item 303(a)(5) of Regulation S-K states that other long term liabilities reflected on the balance sheet under GAAP should be disclosed in the table. Please revise your table of contractual obligations to include these long term liabilities, or explain in your footnote why you believe the amounts would not be meaningfully presented in the table.
Response. The Company excluded asset retirement obligations, liabilities associated with derivatives and liabilities associated with commitment and other fees on our credit facility because we are not able to precisely predict the timing or ultimate cash settlement amounts for these items and because we do not believe that these amounts are meaningful to the information presented in the table, and they could be misleading to the investor.
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
October 9, 2006
Page 3
Inherent in the calculation of the present value of our asset retirement obligations are numerous assumptions and judgments, including the ultimate cash settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. In addition, the fair value of derivatives is estimated using the Black-Scholes pricing model that incorporates assumptions such as volatility, expected term, and risk-free rate. As a result of the number and uncertainty of these calculations and assumptions, we are not able to predict the timing and ultimate cash settlement amount for these items.
We believe the intent of the contractual obligations table is to accurately reflect definite cash payments that the Company will make in the future. Given the uncertainty of the calculations as discussed above, we do not believe that including these estimates would be an accurate representation of the Company’s future cash obligations and, therefore, could be misleading to the investor.
We propose that in future filings we will explain in our footnote in greater detail why we have excluded these amounts and why they are not meaningful to the information presented.
Financial Statements
Note 14 – Supplementary Oil and Gas Information (unaudited), page F-29
Costs Incurred, page F-29
Comment 3. We note that you identify asset retirement costs as a separate line item in your table of costs incurred for each year, which is contrary to the guidance in paragraph 11 of SFAS 143, requiring adjustment to the asset to which an asset retirement liability relates. Accordingly, we believe that you should reclassify the asset retirement costs to the related line items to which the corresponding asset retirement obligation relates. The amount of asset retirement costs included may be described in a footnote to the schedule, if so desired. You may refer to our February 2004 industry letter for guidance on related topics, accessible on our website at the following address:
http://www.sec.gov/divisions/corpfin/guidance/oilgasletter.htm
Response. The cost incurred disclosure requirements are intended to provide a reader with a detail of oil and gas property costs incurred during a given year. SFAS 143 requires that costs associated with abandoning a long-lived asset be recorded when an asset is acquired or developed (in our case when a well is acquired or drilled) and then amortized with other costs over the property’s life. We believe the concept of SFAS 143 is that the obligation to
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
October 9, 2006
Page 4
plug and abandon a well is incurred when it is acquired or drilled, not at the end of its useful life. We believe our treatment is consistent with the Commission’s guidance based on theSample Letter Sent to Oil and Gas Producers by the Division of Corporation Finance dated February 24, 2004 (authored by Carol A. Stacey, Chief Accountant), which addresses SFAS 69 and SFAS 143. The section discussing SFAS 69, paragraphs 21-23, states, “We believe an entity should include asset retirement costs in its Costs Incurred disclosures in the year that the liability is incurred, rather than on a cash basis.” We considered including the costs within the components or within a single component of the cost incurred disclosure but concluded that Asset Retirement Obligation Costs (“ARO Costs”) did not meet any single component definition. As a result, we have presented the ARO Costs as a separate line item in the Costs Incurred disclosure.
Similar to previous discussion between the Company and the Staff in connection with our initial public offering (File No. 333-114554), the Company concluded it would be most useful to disclose “ARO Costs” as a separate line item of the cost incurred disclosure. The Company received a comment letter dated September 13, 2004 from H. Roger Schwall, Assistant Director, stating in Comment 18 in regard to the Costs Incurred table that “You may include a separate line item in the table representing the costs incurred to establish your asset retirement obligations to the extent these amounts are material.”
For the reasons mentioned above, and because we consider our ARO Costs to be material, we believe we are properly disclosing asset retirement obligations. Please advise whether the Staff has additional comments concerning our current intention to continue disclosures in this manner in our future filings.
Engineering Comments
Risk Factors, page 10
Risks Relating to Oil and Gas Reserves, page 10
Comment 4. Please reconcile for us the volume of net reserve reductions you report for each of the years 2003, 2004 and 2005 under this heading and on page 36, with the net reserve revisions you report for the same periods in the table of reserve changes on page F-30.
Response. The reserve revisions reported on page 10 refer to engineering revisions to proved reserves before price effect. The effect of price change, as depicted in the table below, is described on page 62 of the Form 10-K as follows:
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
October 9, 2006
Page 5
“At year end 2005, we revised our proved reserves downward from the 2004 reserve report by approximately 24.7 Bcfe, offset by approximately 7.5 Bcfe of upward revisions due to commodity price increases. At year-end 2004, we revised our proved reserves downward from the 2003 reserve report by approximately 32 Bcfe, offset by approximately 6 Bcfe of upward revisions due to commodity price increases. At year end 2003, we revised our proved reserves downward from the 2002 reserve report by approximately 41 Bcfe, offset by approximately 5 Bcfe of upward revisions due to commodity price increases.”
The sum of the engineering revisions and the reserve change due to price effect, listed below, is equivalent to the reserve changes reported on page F-30. This is true in all years with the exception of 2005. In 2005, a mathematical miscalculation resulted in an overstatement of “Extensions, discoveries, and other additions” of 14.8 Bcfe, which also resulted in an overstatement of “Revision of previous estimates” of the same amount. This is a reclassification between categories with no change to the year-ended December 31, 2005 reserves. We propose to make the reclassification in future filings and to provide footnote disclosure concerning the change.
Year | Engineering Revisions (Bcfe) (p10 & p36) | Revisions due to Commodity Pricing (Bcfe) | Other (Math miscalculation) (Bcfe) | Revisions of Previous Estimate (Bcfe) (p F-30) | |||||||
2003 | (41.0 | ) | 5.0 | — | (36.0 | ) | |||||
2004 | (32.0 | ) | 6.2 | — | (25.8 | ) | |||||
2005 | (24.7 | ) | 7.5 | (14.8 | ) | (32.0 | ) |
Piceance Basin, page 12
Gibson Gulch, page 12
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
October 9, 2006
Page 6
Comment 5. You state that you have received authority to further develop the Mesaverde reservoir on ten acre spacing. Please tell us the quantities of reserves you estimate to recover from these wells, and the percentages of those quantities that would be appropriately characterized as new reserves versus accelerated access to existing reserves. Tell us the basis for your view.
Response. Within the area, referenced in the Form 10-K, in which we have approval from the Colorado Oil & Gas Commission to develop on 10-acre spacing, we do not have any proved reserves, developed or undeveloped, associated with 10-acre spacing. We currently are drilling on a 20-acre pattern. We are planning 10-acre pilots in the 10-acre approved area in 2007. In order to estimate quantities of incremental and acceleration reserves, we plan to perform pressure testing and production analysis in the pilot area and integrate this information with our geologic model. Our technical analysis will be performed in the 2007 – 2008 timeframe.
Oil and Gas Data, page 19
Proved Reserves, page 19
Comment 6. Please expand your disclosure to include the range of differences in the reserve estimates calculated by you and those prepared by the independent engineers at the property level.
Response. For estimates of proved reserves at December 31, 2005, our independent reserve engineers arrived at reserve estimates that are greater than 10% above or below our own estimates for approximately 59% of our wells, which represents approximately 37% of the total proved reserves covered in the review reports. In the case of the properties reviewed by each of the two independent engineers, our estimates of proved reserves at December 31, 2005, in the aggregate, were 8.1% above Ryder Scott Company, L.P., and at December 31, 2005, in the aggregate, were 7.7% above Netherland, Sewell & Associates, Inc. Disclosures along these lines were included in our prospectus in connection with our initial public offering in response to similar comments from the Staff received on October 13, 2004 in Comment 2 (File No. 333-114554).
Risk Factors, page 34
Prospects That We Decide to Drill, page 37
Comment 7. We note that you disclose the number of wells that you drilled which turned out to be dry holes. Please expand your disclosure to also include the number of wells completed but which are producing at levels materially less than you had originally forecasted.
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
October 9, 2006
Page 7
Response. We participated in drilling 797 gross wells from inception through December 31, 2005. While we are required to disclose the number of dry holes, we do not believe the number of wells with variance to forecast is material to an investor’s understanding of our business. We do, however, disclose the aggregate impact on total reserves of such variance. Of the 797 wells, 219 were producing at less than 75% of original forecast at December 31, 2005. The downward revision in forecast of these wells resulted in the reserve revisions described by basin on page 36 of the Form 10-K as follows:
At year-end 2003, we revised our proved reserves downward from our 2002 reserve report by approximately 41 Bcfe. The majority of the downward revision was due to reclassifying deep proved undeveloped reserves and reevaluating the economic potential of behind pipe reserves in the Wind River Basin as a result of a periodic review of our reserves and reserve evaluation methodologies and an analysis of the results of our recompletion program. At year-end 2004, we revised our proved reserves downward from our 2003 reserve report by approximately 32 Bcfe. The downward revision was primarily the result of infill drilling in depleted sands in the Wind River Basin and greater pressure depletion than expected in two areas in the Powder River Basin. At year-end 2005, we revised our proved reserves downward from our 2004 reserve report by approximately 24.7 Bcfe, primarily as a result of a reduction in proved undeveloped reserves in the Piceance Basin due to the use of completion techniques performed from January through September 2005 that yielded results lower than our expectations at year-end 2004.
As a result of this disclosure, we do not believe that further disclosure is necessary in response to this comment.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 47
Overview, page 47
Comment 8. We note your disclosure in the last paragraph on page 48, explaining that your finding and development costs are high relative to other operators. It would be helpful to include some quantification of these differences in your disclosure so that it is clear how much your costs are higher, on average, than other operators in the area; as well as to provide some indication of how these costs may change under the proportions of later stage development activities you regard as reasonably likely to occur in future periods.
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
October 9, 2006
Page 8
Response. The Company believes that the current disclosure provides readers with balanced and helpful information regarding the Company’s finding and development costs and adequately explains our beliefs concerning these costs based on our stage of development and how these costs will be impacted going forward. It would not be possible to provide current quantifiable disclosure concerning the differences between our finding and development costs and those of certain other exploration and production companies due to the required timing to file the Form 10-K and the lack of public companies with profiles similar to ours (Rocky Mountain exploration and production companies with several major properties at early stages of development and a large exploration focus). In addition, finding and development costs are calculated differently by different companies. We have prepared an internal benchmarking analysis for prior periods that forms the basis for our belief that we have higher finding and development costs than selected other companies in our industry. However, because of the lack of comparable companies and standard calculation methodology for finding and development costs, we believe our current disclosure is sufficient and appropriate. Finally, the Company believes that, in the near to medium term, its finding and development costs will be dropping, and the disclosure may not be necessary in future filings.
Oil and Gas Reserve Estimates, page 62
Comment 9. Your disclosure indicates that the net revisions in 2005 are negative 17.2 Bcfe. However, this is not consistent with the table of reserve changes on page F-30. Please revise your disclosure to resolve this inconsistency.
Response. Please see response to Comment 4 above.
Financial Statements
Supplemental Oil and Gas Reserve Information, page F-29
Analysis of Changes in Proved Reserves, page F-30
Comment 10. We note the large negative reserve changes in each of the last three years. Please describe for us, in as much detail as necessary, your controls and processes for the evaluation and estimation of proved reserves. Include in your explanation a discussion of the role the third party engineers have in the process. Identify any programs for awards or incentives you provide to your employees and others for the booking of proved reserves.
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
October 9, 2006
Page 9
Response. In general, a reserve report is prepared by us for all Company properties on a well-by-well basis. Our independent engineering firms perform a well-by-well analysis of all of our properties and of our estimates of our proved reserves. In detail, our corporate engineering technical coordinator creates a CD of the BBC Aries (engineering economic software package) production volume data files and sends the CD to the independent engineering firms. The independent engineering firms utilize this information to calculate an independent evaluation of the reserve volumes. During this time, the reservoir engineering technicians at BBC update the economic data (interests, costs and pricing). BBC and each of the independent engineering firms periodically send new information and revisions to each other based on analysis and discussions. The independent engineering firms send their reserve estimates on a well-by-well basis to BBC. This information is updated into the BBC Aries database. A comparison of reserve volumes between BBC and the independent engineering firms is generated. The key process control involving the independent engineering firms occurs when the Reservoir Engineering Department at BBC and each of the independent engineering firms investigate and jointly resolve areas of significant differences between the reserve volumes determined by each party. This insures that BBC and the independent engineering firms separately determine reserve volumes on a well-by-well basis appropriately within SEC guidelines. If the total aggregate difference in the reserve volumes between BBC and each independent engineering firm is less than 10%, the reserve reporting process continues within the Reservoir Engineering Department at BBC. If the difference is greater than 10% and the technical discussions have been completed, it is the responsibility of the Reservoir Engineering Department at BBC to adjust their analyses such that a difference less than 10% exists in the total aggregate.
The Company has no programs for awards or incentives tied exclusively to the booking of proved reserves. The Compensation Committee has approved a broad range of metrics, 22 in total, developed by management to improve Company performance. One of these 22 metrics is reserve additions. Other metrics considered include the Company’s production for the year, lease operating expenses and gathering expenses on a total and unit of production basis, general and administrative expenses on a total and unit of production basis, capital expenditures, total year end reserves (after reserve additions, production, acquisitions, and positive and negative engineering adjustments), finding and development costs, and cash flow. These metrics in aggregate are used, along with subjective determinations, by management and the Compensation Committee in the process of making discretionary salary and bonus determinations. We do not have any programs for awards or incentives for our independent reserve engineering firms or any others based on the booking of proved reserves.
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
October 9, 2006
Page 10
Standardized Measure, page F-30
Comment 11. Please submit the calculations that you performed in estimating the future cash flows reported on page F-31 for 2004 and 2005, reconciling to the reserve quantities and oil and gas prices that you disclose as having been applied for each of those years.
Response. Our prices used in the calculations that we performed in estimating the future cash inflows reported on page F-31 for 2004 and 2005 are year-end prices, adjusted for the appropriate differentials, for all oil and gas reserves and projections. The table below shows the oil and gas pricing used before and after adjustments for transportation, quality and basis differentials and the calculations made to arrive at cash inflows for the years 2004 and 2005.
| 2004 | 2005 | |||||
Prices before adjustments: | ||||||
Gas (per Mcf) | $ | 5.52 | $ | 7.72 | ||
Oil (per Bbl) | $ | 43.46 | $ | 61.04 | ||
Prices after adjustments: | ||||||
Gas (per Mcf) | $ | 5.78 | $ | 8.22 | ||
Oil (per Bbl) | $ | 40.56 | $ | 62.75 | ||
Reserve Quantities: | ||||||
Gas (Mmcf) | 257,876 | 305,972 | ||||
Oil (MBbls) | 5,738 | 5,834 | ||||
Future cash inflows: (in thousands) | ||||||
Gas | $ | 1,489,636 | $ | 2,516,087 | ||
Oil | $ | 232,733 | $ | 366,078 | ||
Total cash inflows | $ | 1,722,369 | $ | 2,882,165 | ||
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
October 9, 2006
Page 11
The Company hereby acknowledges as follows:
| • | the Company is responsible for the adequacy and accuracy of the disclosure in the filing; |
| • | staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and |
| • | the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States. |
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
October 9, 2006
Page 12
If any member of the Staff has comments or questions, please call Thomas B. Tyree, Jr. (Chief Financial Officer) at (303) 312-8181, David R. Macosko (Vice President – Accounting) at (303) 312-8137, or Francis B. Barron (Senior Vice President – General Counsel) at (303) 312-8515.
| Very truly yours, | ||
| BILL BARRETT CORPORATION | ||
| By: | /s/ Thomas B. Tyree, Jr. | |
| Thomas B. Tyree, Jr. | ||
| Chief Financial Officer | ||
| cc: | Mr. James Murphy |
Ms. Jenifer Gallagher
Mr. Dennis Boylan
Ms. Chris LaFollette
Mr. Francis B. Barron
Mr. David R. Macosko
Mr. Randy Stein, Chair, Audit Committee
