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410 17th Street, Suite 1500 Denver, CO 80202 (720) 440-6100 (720) 305-0804 Fax Bonanzacrk.com |
December 17, 2012
Mr. Karl Hiller
Branch Chief
U.S. Securities and Exchange Commission
Division of Corporate Finance
100 F Street, N.E.
Washington, D.C. 20549
Via EDGAR
Re: Bonanza Creek Energy, Inc.
Form 10-K for the Fiscal Year ended December 31, 2011
Filed March 22, 2012
File No. 1-35371
Dear Mr. Hiller:
On behalf of the above-captioned registrant (the “Company”), enclosed for your information and review are responses to the comments from the staff of the Commission (the “Staff”) set forth in your letter dated December 4, 2012 with respect to the above referenced Form 10-K for the Fiscal Year ended December 31, 2011 of the Company (the “Form 10-K”). Set forth below are the Company’s responses to the Staff’s comments.
This letter is submitted to respond on a point-by-point basis to the Staff’s comments. Each of the Staff’s comments is set forth below (with page references unchanged) and is followed by the Company’s response. All terms used but not defined herein have the meanings assigned to such terms in the Form 10-K.
COMMISSION COMMENTS FOLLOWED BY COMPANY RESPONSES
Business
Proved Undeveloped Reserves, page 16
1. Please quantify the proved undeveloped reserves converted to proved developed reserves during the year as required by Item 1203(b) of Regulation S-K.
Response:
In response to the Staff’s comment, the following proved undeveloped reserves reconciliation table is provided to clarify the changes in proved undeveloped reserves that occurred during the 2011 calendar year:
Proved Undeveloped Reserves, MBoe
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December 31, 2010 |
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21,334.5 |
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Converted to Proved Developed Producing |
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(4,184.3 |
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Additions from Drilling |
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10,190.5 |
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Acquisitions/Sales |
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0 |
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Revisions (pricing and engineering) |
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(688.7 |
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December 31, 2011 |
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26,652.0 |
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We believe that the disclosure required by Item 1203(b) of Regulation S-K is substantially contained within the Form 10-K (please see the tables on pages 14, 17 and 107). We will include a table essentially as noted above for the proved undeveloped reserves reconciliation in our future filings to increase the transparency of our disclosure.
Production, Revenues and Price History, page 18
2. It appears you have significant fields that contain 15% or more of your total proved reserves as of December 31, 2011. As such, please tell us how you have complied with the guidance in Item 1204(a) of Regulation S-K, in concluding that you would not disclose production by such fields for the prior three years.
Response:
We interpreted Item 1204(a) of Regulation S-K and the adopting release (SEC Release No. 33-8995) to require disclosure of regional and field level information only if the regions and fields were not all in the same country. Specifically, Release No. 33-8995, in regard to geographic disclosure, states as follows:
“[W]e have revised the definition of the term “by geographic area” to mean, as appropriate for meaningful disclosure under a company’s particular circumstances:
(1) By individual country;
(2) By groups of countries within a continent; or
(3) By continent.
***
With respect to production, the final rules require disclosure of production in each country or field containing 15% or more of the company’s proved reserves unless prohibited by the country in which the reserves are located.”
Similarly, in the Release commentary with respect to Item 1204 disclosure, the following similar statement is made: “this disclosure must be made by geographical area and for each country and field containing 15% or more of the registrant’s proved reserves, expressed on an oil-equivalent-barrels basis.” We interpreted these clauses from the Release, taken together and read as a whole, to indicate that disclosure would generally be required on a country by country basis. Because the Company has no operations outside the United States, we did not believe region and field level information was required to be included. Based upon our review of other disclosures by similarly situated companies, it appears that a number of other reporting companies may have made this same interpretation.
In response to this Staff comment, we further note that each of our geographic regions that contains more than 15% of our proved reserves contains only one field with significant production, i.e., for the one year period ended and as of December 31, 2011, the Wattenberg field in our Rocky Mountain region comprised
approximately 92% of the production and 97% of the reserves attributed to that region and the Dorcheat Macedonia field in our Mid-Continent region comprised approximately 90% of the production and 92% of the reserves attributed to that region. Regional production data for 2011 is included on page 7 and full Company production data for 2009-2011 on page 19 of the Form 10-K.
We do not believe that further break out of production information on a field or geographic region basis through 2011, given our specific circumstances, would result in any meaningful significant disclosure to investors. At the same time, we recognize that, as operations at our various fields progresses, the additional information may provide meaningful information to investors in the future. Accordingly, we will provide production information for our significant fields, substantially as set forth below in future filings.
The following table below sets forth annual production volumes for the Company as a whole and our largest fields (those whose reserves represent 15% or more of our total proved reserves).
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2009 |
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2010 |
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2011 |
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Oil: |
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Total Production (MBbls) |
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507.4 |
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484.9 |
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953.0 |
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Wattenberg Field |
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129.6 |
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134.6 |
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400.8 |
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Dorcheat Macedonia Field |
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119.3 |
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147.9 |
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359.8 |
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Natural Gas: |
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Total Production (MMcf) |
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939.0 |
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1,351.5 |
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2,776.4 |
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Wattenberg Field |
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406.9 |
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391.6 |
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1,072.2 |
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Dorcheat Macedonia Field |
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391.7 |
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828.6 |
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1,642.2 |
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Natural Gas Liquids: |
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Total Production (MBbls) |
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69.1 |
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129.8 |
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183.8 |
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Wattenberg Field |
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— |
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— |
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— |
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Dorcheat Macedonia Field |
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69.1 |
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129.8 |
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183.8 |
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Oil Equivalents: |
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Total Production (MBoe) |
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733.0 |
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840.0 |
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1,599.5 |
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Wattenberg Field |
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197.4 |
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199.8 |
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579.5 |
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Dorcheat Macedonia Field |
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253.7 |
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416.3 |
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817.3 |
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Average daily production (Boe/d) |
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2,008.0 |
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2,301.0 |
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4,382.0 |
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Wattenberg Field |
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540.8 |
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547.4 |
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1,587.7 |
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Dorcheat Macedonia Field |
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695.1 |
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1,140.5 |
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2,239.2 |
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Financial Statements
Note 2 - Summary of Significant Accounting Policies
Revenue Recognition, page 93
3. We note your disclosure that in exchange for gathering and processing services, you receive fees or commodities from natural gas producers. Tell us how you determined that Rule 5-03 of Regulation S-X did not apply to your situation in deciding not to disclose separately income from services provided. In addition, tell us if your natural gas plant is accounted for in accordance with the successful efforts recognition and measurement guidance in FASB ASC 932-360 and clarify how these assets are depreciated.
Response:
All gas entering our gas processing facilities is processed in accordance with percent-of-proceeds contracts with upstream counterparties. The natural gas is sold at the tailgate of the facilities into CenterPoint pipeline connections and the natural gas liquids are trucked out by the buyer. The Company is the upstream counterparty that contributes more than 95% of the natural gas entering the facilities. The revenues currently derived from percent-of-proceeds contracts are almost exclusively related to our own upstream operations and management does not believe the separate disclosure of service revenues would be meaningful to investors. If these facilities begin processing a material amount of gas for other operators the corresponding service revenues will be presented.
The successful efforts method of accounting; as codified by ASC 932-360, provides that it may be more appropriate, in some cases, to depreciate a natural gas processing facility by a method other than the unit-of-production method when such facilities serve a number of fields subject to individual amortization or when the facilities are used to process gas for other operators. Our facilities are currently processing gas from the Cotton Valley and Smackover formations. The Brown Dense formation, which is the source rock for the Smackover formation, is currently being developed by other operators in the vicinity of our gas processing facilities and is expected to extend the useful life of these facilities beyond the life of the Cotton Valley and Smackover formations. The depreciation of these facilities in accordance with the units-of-production method would not consider the undeveloped reserve formations such as the Brown Dense and would fully depreciate the facilities before the end of their expected lives. Management believes that the depreciation of these facilities in accordance with the units-of-production method using the proved developed reserve volumes from the Cotton Valley and Smackover formations would cause distortions to the depreciation rate and would not be consistent with the Company’s intention of using the plant to process more third party gas if our production from proved reserves declines and additional reserves are developed by us and others, nor do we believe it would be meaningful to investors. We have therefore selected the straight-line method of calculating depreciation using a 30 year life as we believe it best represents the most likely use of the plant in the future and the related benefits of the plant to the Company.
* * * *
Any questions regarding the above responses should be directed to either Wade E. Jaques at (720) 440-6117 or Christopher I. Humber at (720) 440-6120.
Thank you for your attention to this filing.
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Very truly yours, | |
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/s/ Wade E. Jaques | |
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Wade E. Jaques | |
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Vice President, Controller and | |
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Chief Accounting Officer | |
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cc: |
Michael R. Starzer |
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Christopher Humber, Esq. |
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Dallas Parker, Esq. |
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