November 3, 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 October 24, 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
Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 47
Results of Operations, page 50
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
November 3, 2006
Page 2
Comment 1. In your response to comment one of our letter dated September 15, 2006 you propose to revise your disclosure in the table to only include GAAP measures, including general and administrative costs as shown on the face of the consolidated statements of operations. We note in the table preceding your discussion of results of operations you present a similar measure of general and administrative costs per Mcfe, excluding the effects of non-cash stock based compensation. Please ensure you make corresponding revisions to the measures presented in this table.
Response. In future filings, if we include any non-GAAP measures, we will include a reconciliation to the most directly comparable GAAP measure and disclose why we believe this non-GAAP measure is useful to investors in accordance with 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.
Contractual Obligations, page 60
Comment 2. We have read your response to comment two in which you state that you exclude the items “…because [you] are not able to precisely predict the timing or ultimate cash settlement amount for these items and because [you] do not believe that these amounts are meaningful to the information presented in the table, and they could be misleading to the investor.” Therefore, you propose in future filings to explain in a footnote in greater detail why you have excluded these amounts and why they are not meaningful to the information presented. Item 303(a)(5) of Regulation S-K states that the presentation must include all of the obligations of the registrant that fall within the specified categories, and the tabular presentation may be accompanied by footnotes to describe provisions that create, increase or accelerate obligations, or other pertinent data to the extent necessary for an understanding of the timing and amount of the registrant’s specified contractual obligations. As such, in future filings please revise your table to include the items which are reflected on your balance sheet as long term liabilities, and provide additional disclosure as a footnote to the table describing the information necessary to understand the timing and amount of the specified contractual obligations. As part of your response, please include draft disclosure to be included in future filings.
Response. In future filings, we will revise our contractual obligations table to include the items which are reflected on our balance sheet as long term liabilities, and will provide additional disclosure as a footnote to the table describing the information necessary to understand the timing and amount of the specified contractual obligations. A draft of the form of our suggested disclosure is as follows:
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
November 3, 2006
Page 3
| Payments Due By Year | |||||||||||||||||||||
| 2006 | 2007 | 2008 | 2009 | 2010 | After 2010 | Total | |||||||||||||||
| (in thousands) | |||||||||||||||||||||
Long-term debt (1) | $ | — | $ | 86,000 | $ | — | $ | — | $ | — | $ | — | $ | 86,000 | |||||||
Other commitments for developing oil and gas properties | 19,920 | 22,265 | 2,345 | — | — | — | 44,530 | ||||||||||||||
Office and office equipment leases and other | 1,273 | 1,535 | 1,476 | 1,469 | 1,521 | 378 | 7,652 | ||||||||||||||
Firm transportation and processing agreements | 5,025 | 5,622 | 14,866 | 17,193 | 17,604 | 134,615 | 194,925 | ||||||||||||||
Asset Retirement Obligations (2) | 5,519 | 902 | 876 | 732 | 602 | 15,102 | 23,733 | ||||||||||||||
Derivative liabilities (3) | 29,058 | 6,992 | — | — | — | — | 36,050 | ||||||||||||||
Total | $ | 60,795 | $ | 123,316 | $ | 19,563 | $ | 19,394 | $ | 19,727 | $ | 150,095 | $ | 392,890 | |||||||
| (1) | Amount does not include future commitment fees, interest expense, or other fees on our credit facility because this is a floating rate instrument and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. |
| (2) | Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See “Critical Accounting Policies and Estimates,” below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations. |
| (3) | Derivative liabilities represent the fair value of liabilities for oil and gas commodity derivatives, primarily costless collars, as of December 31, 2005. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market risk. See “Critical Accounting Policies and Estimates,” below for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments. |
Engineering Comments
Risk Factors, page 10
Risks Relating to Oil and Gas Reserves, page 10
Comment 3. We have read your response to prior comment four of our letter dated September 15, 2006, explaining that the reserve changes do not include price effects. However, in the risk factor you list commodity prices as one of only two specific examples of why reserve estimates may be a risk. The reserve changes shown in the risk factor appear to need disclosure explaining that those changes do not include price changes. We believe you should clarify this to either explain that these changes do not include price effects or to disclose the changes that do include price effects.
Response. We propose in future filings to explain that the reserve changes in the risk factor entitled “Risks Relating to Oil and Gas Reserves” do not include price changes as follows:
“Reserve Estimates are based on many uncertainties for which estimates are made based upon the best available data, including
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
November 3, 2006
Page 4
commodity prices and production profiles, and our properties may not produce as we originally forecast. For example, we reduced our reserve estimates, excluding price effects, by approximately 41 Bcfe at year end 2003, 32 Bcfe at year end 2004, and 25 Bcfe at year end 2005. “
Piceance Basin, page 12
Gibson Gulch, page 12
Comment 4. We have read your response to prior comment five, indicating you do not have any reserves associated with 10-acre spacing; and that you are currently drilling on 20-acre spacing. Therefore, it appears that reserve estimates you determined for the 20-acre wells must include the reserves you may recover with future 10-acre infill wells. Please tell us whether this is consistent with your view. If so, this should be disclosed with your statement about future 10-acre development.
Response. We have not determined that the reserve estimates for our 20-acre wells include the reserves from future 10-acre wells. The reserve estimates on our 20-acre spaced wells are based on decline curve analysis. The direct offsetting proved undeveloped reserves are determined based on the reserves of the proved developed producing offset. We do not use volumetric calculations of the gas-in-place on 20-acres in the estimation of our 20-acre reserves. Since our 20-acre reserves are not based on gas-in-place estimates of a specified drainage area, we do not know, at this time, to what extent 10-acre infill drilling will recover reserves in addition to the reserves of the 20-acre wells. In order to estimate the quantity of incremental reserves resulting from 10-acre infill drilling, we need to perform pressure testing and production analysis and integrate this information with our geologic model. We will know the incremental reserve component of the 10-acre infill drilling after we have analyzed our technical data. The testing and analysis will be performed in the 2007 – 2008 timeframe.
We do not believe that further disclosure is necessary in response to this comment.
Oil and Gas Data, page 19
Proved Reserves, page 19
Comment 5. We have reviewed your response to prior comment six, regarding differences in the reserve estimates calculated by you and the independent engineers. We believe that having differences arise between your estimate and the third party engineers’ estimate on 59% of your wells, covering 37% of the total proved reserves should be disclosed. Given your frequent
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
November 3, 2006
Page 5
downward reserve revisions, some attention to your method of estimating and reporting proved reserves may be warranted. Any differences greater than 10% on individual properties should generally be reconciled, or you may opt to report the lower reserve number. Since you engaged independent engineers to review your proved reserve estimates, and reference this activity in your filing, we believe the degree of reliance conveyed would need to be qualified in those instances that material differences of this magnitude were noted but not revised. Please revise your document accordingly.
Response. We propose to disclose the following information in our future filings:
“For estimates of proved reserves at December 31, 2005, our estimates of proved reserves, 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. 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. On an individual property level, significant variance to our independent reserve engineer estimates may remain in our final reserve report.”
We believe that we are disclosing our method and verification of our method of estimating and reporting reserves by statements made by our independent engineers which are described on page 20 of the Form 10-K as follows:
“Ryder Scott Company, L.P. provided us with a report stating its opinion that the methods and techniques used in preparing our reserve report are in accordance with generally accepted procedures for the determination of estimating proved reserves, and that the total proved net reserves estimated would be within 10% of those estimated by Ryder Scott Company, L.P. Netherland, Sewell & Associates, Inc. stated in its report that our estimates of proved oil and gas reserves and future revenue as shown in its report and in certain computer printouts in its office are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles.”
As a result of this disclosure, we do not believe that further disclosure is necessary with regard to our method of estimating and reporting proved reserves.
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
November 3, 2006
Page 6
Risk Factors, page 34
Prospects That We Decide to Drill, page 37
Comment 6. We have reviewed your response to prior comment seven, regarding your disclosure indicating that your wells may not produce in commercial quantities, which is generally true for most oil and gas companies. Please understand that risk factors should be as specific to you as possible. As it appears that approximately 27.5% of the wells you participated in were producing less than 75% of the originally forecasted volumes, this would seem to constitute both material and specific information pertaining to you. Therefore, please revise your document to include this information in the risk factor.
Response. We have previously disclosed the details of our downward revisions on page 36 of the 10-K in “Risks Related to the Oil and Gas Industry and Our Business” under “Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” as follows:
“Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. 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.”
We believe that it is not necessary to restate the specific resulting risk associated with our history of downward revisions again under “Prospects that we decide to drill may not yield natural gas or oil in commercially viable quantities.” on the subsequent page. The risk for identifying prospects to drill is
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
November 3, 2006
Page 7
a dry hole, which we disclose. The impact of drilling on forecasted results is addressed in the estimated reserves risk factor disclosing the primary reasons. As noted, well results variations are true for most oil and gas companies at the initial prospect stage and, at that stage, the Company is not trying to estimate quantifiable reserves to record as proved reserves.
Standardized Measure, page F-30
Comment 7. We have read your response to our prior comment 11, regarding the prices utilized in your computations of future cash flows. It appears you compute a future cash inflow that is 2.9% higher in 2004 and 5.7% higher in 2005 than would result using the prices cited in the filing under this heading as being those that you utilized for this computation. Please reconcile the differences in prices between those stated in the filing that you used for the computation of future cash inflows and those mentioned in your response.
Response. The chart below reconciles the differences in prices between those stated in the filing and those used in the computation of future cash inflows. We state in the filing that prices used are $5.52 and $7.72 per Mcf for gas for 2004 and 2005, respectively. This statement should read that the prices used are $5.52 and $7.72 per Mmbtu rather than Mcf. This reference will be corrected in future filings.
Gas Pricing
| 2004 | 2005 | |||||||
Company Weighted Average BTU: | 1.068 | 1.105 | ||||||
Spot Price ($/MMBTU): | $ | 5.52 | $ | 7.72 | ||||
Basis Diff/Marketing/Transp | $ | (0.11 | ) | $ | (0.28 | ) | ||
Price at Wellhead($/MMBTU): | $ | 5.41 | $ | 7.44 | ||||
Wellhead Price ($/Mcf): | $ | 5.78 | $ | 8.22 | ||||
Mr. Mark A. Wojciechowski
U.S. Securities And Exchange Commission
November 3, 2006
Page 8
Oil Pricing
| 2004 | 2005 | ||||||
Spot Price ($/Bbl): | $ | 43.46 | $ | 61.04 | |||
Basis Diff/Marketing/Transp | $ | (2.90 | ) | $ | 1.71 | ||
Wellhead Price ($/Bbl) | $ | 40.56 | $ | 62.75 | |||
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. Please note that, as previously announced, Mr. Tyree is leaving the Company on November 17, 2006. Mr. Barron will serve as Chief Financial Officer beginning at that time until a successor has been appointed.
| 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
