April 25, 2012
VIA EDGAR
Mr. H. Roger Schwall
Assistant Director
U.S. Securities and Exchange Commission
Division of Corporation Finance
100 F. Street, N.E.
Washington, D.C. 20549
| Re: | Continental Resources, Inc. |
Form 10-K for Fiscal Year Ended December 31, 2011
Filed February 24, 2012
File No. 1-32886
Dear. Mr. Schwall:
Set forth below are the responses of Continental Resources, Inc. (the “Company,” “we,” “us” or “our”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated April 16, 2012, with respect to the Company’s above-referenced filing (the “Form 10-K”).
Based on our review of the Staff comment letter and as further described herein, we believe our Form 10-K is materially correct, and no amendment of our existing filings is necessary. Instead, as indicated in our responses below, we propose to make certain clarifications or modifications to our disclosures in future filings.
If following a review of this information, the Staff does not concur with our analysis, we respectfully request an opportunity to discuss this response letter further with the Staff.
For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in italicized text.
Form 10-K for Fiscal Year Ended December 31, 2011
Crude Oil and Natural Gas Operations, page 4
Proved reserves, page 5
| 1. | Please tell us the quantity of natural gas liquids on an oil-equivalent-barrels basis that is reported in your total proved reserves as of December 31, 2011, 2010 and 2009. In your response, please tell us what consideration you have given to providing separate disclosure of natural gas liquids from crude oil and natural gas. |
Response: We report our natural gas production and reserves in accordance with Item 1204 of Regulation S-K which provides in relevant part:
Production of natural gas should include only marketable production of natural gas on an “as sold” basis. Production will include dry, residue, and wet gas, depending on whether liquids have been extracted before the registrant transfers title.
We do not extract natural gas liquids from our natural gas production prior to the sale and transfer of title of the natural gas stream to our purchasers. While some of our purchasers extract natural gas liquids from the natural gas stream sold by us to them, we have no ownership in such natural gas liquids. Therefore we do not report natural gas liquids in our production or proved reserves.
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Proved undeveloped reserves, page 7
| 2. | We note from your disclosure that “Our current 5 year plan anticipates that full development of our PUD inventory will comprise the majority of our currently projected level of drilling activity and generate additional PUD locations as our current inventory is harvested.” We also note from your disclosure that you developed approximately 13% of your PUD’s booked as of December 31, 2010 and your 2010 Form 10-K disclosure indicates that approximately 11% of your PUD’s were developed from those booked as of December 31, 2009. Given the conversion rates you’ve disclosed for 2011 and 2010, please clarify for us whether your representation that you will fully develop your PUD inventory in five years was calculated from the date of the initial booking. In this regard, it is not clear how historical conversion rates of less than 20% would result in the conversion of your PUD inventory in the five years required by Rule 4-10(a)(31) of Regulation S-X. |
Response: Our ongoing strategic focus is to drill wells that, to a large extent, accomplish our stated goal of assuring our acreage becomes held by production. Once a substantial portion of our acreage is held by production, our strategic plan shifts its focus to infill well development (i.e. PUD conversion). We fully anticipate as more acreage becomes held by production, the percentage of our expenditures related to PUD development will significantly increase. Various stress tests of development scenarios indicate, with reasonable certainty, that we can execute, or cause to be executed, development of all our PUDs in a manner compliant with the SEC five-year rule. We continue to anticipate full development of our PUD inventory within five years of the reserve booking date. The inventory we use in our calculation is from the year of initial booking. The following statement included in our 2011 Form 10-K is consistent with these calculations.
“While we will continue to drill strategic exploratory wells and build on our current leasehold position, we will simultaneously increase our focus on drilling programs over the next 5 years which harvest our PUD locations. Our current 5 year plan anticipates that full development of our PUD inventory will comprise the majority of our currently projected level of drilling activity and generate additional PUD locations as our current inventory is harvested.”
The following table shows our inventory of PUD locations at December 31, 2011 by the year they were initially booked, when we have them currently scheduled for development and the estimated future development costs related thereto for each of the five years ending December 31, 2016.
Initial PUD Booking Year | PUD Locations | Scheduled PUD Development Year | ||||||||||||||||||||||
| 2012 | 2013 | 2014 | 2015 | 2016 | ||||||||||||||||||||
2008 | 70 | 35 | 35 | – | – | – | ||||||||||||||||||
2009 | 504 | 249 | 182 | 73 | – | – | ||||||||||||||||||
2010 | 325 | 86 | 72 | 147 | 20 | – | ||||||||||||||||||
2011 | 618 | 79 | 147 | 216 | 132 | 44 | ||||||||||||||||||
Total | 1,517 | 449 | 436 | 436 | 152 | 44 | ||||||||||||||||||
Future Development Costs ($ billions) |
| $ | 1.5 | $ | 1.6 | $ | 1.4 | $ | 0.5 | $ | 0.2 | |||||||||||||
Based on this information, we believe we are in compliance with SEC rules and will be able to develop our PUD reserves within five years of initial booking as disclosed in our 2011 Form 10-K.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 45
| 3. | We note your statement that “Proved reserve additions from all sources amounted to 166,307 MBoe for the year ended December 31, 2011, generating a reserve replacement rate of 736% for the year.” Due to the variable components of calculating a reserve replacement measure, please enhance your discussion to address each of the following, without limitation. |
| • | Describe how the ratio is calculated. |
| • | Identify the status of the proved reserves that have been added (e.g., proved developed vs. proved undeveloped). |
| • | Identify the reasons why proved reserves were added. In this regard, 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, and 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. |
Response: The reserve replacement rate of 736% for the year ended December 31, 2011, was calculated by dividing net proved reserve additions for the year of 166,307 MBoe (the sum of extensions, discoveries, revisions and purchases) by production for the year of 22,581 MBoe. We intentionally used the wording “from all sources” so a reader is able to recompute it from the information contained in our 2011 Form 10-K on pages 6, 50 and 102. In our future filings, if we use this rate, we will add a definition of reserve replacement rate to our glossary.
The status of the proved reserves that were added can be generally determined by reference to footnote “17. Supplemental Crude Oil and Natural Gas Information (Unaudited)” of Notes to Consolidated Financial Statements starting on page 101 with specific reference to the table on page 103 which shows Proved Developed Reserves, Proved Undeveloped Reserves and Total Proved Reserves for each of the last three years.
The proved reserve additions were primarily added as a result of our successful drilling activity in the Bakken field in North Dakota and Anadarko Woodford field in Oklahoma, as described on pages 4 through 16 under “Crude Oil and Natural Gas Operations”. We specifically discuss the 2011 extensions, discoveries and other additions on page 7. On page 7 we also discuss the expected sources of our future reserve additions.
Risks and uncertainties related to reserves are covered by several risk factors. See “Risk Factors” on pages 26 through 41 including specifically:
| • | “A substantial or extended decline in crude oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure needs and financial commitments.”; |
| • | “Volatility in the financial markets or in global economic factors could adversely impact our business and financial condition.”; |
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| • | “Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our crude oil and natural gas reserves and production.”; |
| • | “Reserve estimates depend 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.”; |
| • | “The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated crude oil and natural gas reserves.”; |
| • | “Our use of enhanced recovery methods creates uncertainties that could adversely affect our results of operations and financial condition.”; |
| • | “The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within budget and on a timely basis.”; |
| • | “Unless we replace our crude oil and natural gas reserves, our reserves and production will decline, which could adversely affect our cash flows and results of operations.”; |
| • | “Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.”; |
| • | “Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and inability to book future reserves.”; and |
| • | “We have limited control over the activities on properties we do not operate.” |
We provide production guidance consisting of a range of expected production volumes for the upcoming or current fiscal year. We do not believe it is appropriate to provide any further production information. As noted in “Risk Factors” as cited above, there are many factors that can affect the timing and volume of our production.
Management uses the reserve replacement rate as one of several indications of growth. This measure has several limitations. It is similar to calculations of year over year reserve growth and year over year production growth. While it is neither better nor worse than these measures, it is one we believe is widely used by analysts and investors. Further, while this measure does not provide a complete assessment of a company’s success, it does provide an indication of success. The ratio is limited because it will vary based on the extent and timing of discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not imbed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.
Non-GAAP Financial Measures, page 69
| 4. | We note your disclosure and reconciliation of EBITDAX as a non-GAAP financial measure used by management to evaluate operating performance and to evaluate compliance with certain financial covenants required by your credit facility. As EBITDAX is used as a measure of liquidity as it relates to the outstanding credit facility, please amend your disclosure to also include a reconciliation of the non-GAAP financial measure to the most directly comparable GAAP financial measure, or net cash provided by operating activities, as required by Item 10(e)(1)(i)(B) of Regulation S-K. |
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Response:We use EBITDAX to measure operating performance. On page 48 of our 2011 Form 10-K, under the headingHow We Evaluate Our Operations withinManagement’s Discussion and Analysis of Financial Condition and Results of Operations, we state “We use a variety of financial and operating measures to assess our performance. Among these measures are…EBITDAX (a non-GAAP financial measure).” Additionally, on page 70 of our 2011 Form 10-K, under the headingNon-GAAP Financial Measures, we state “Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure.” These disclosures highlight management’s use of EBITDAX as a performance measure.
We disclose EBITDAX to facilitate our investors understanding of the Company’s operating performance and return on capital associated with our capital programs. We believe EBITDAX is a widely followed measure of operating performance in the crude oil and natural gas industry and, in our experience, financial analysts that issue reports on our Company use EBITDAX to evaluate the operating performance of our Company from period to period in comparison with the performance of other entities within our industry. Consistent with this use and given management’s view of EBITDAX as a performance measure, we believe net income is the most directly comparable GAAP financial measure to our EBITDAX. Accordingly, we present a reconciliation of EBITDAX to net income in accordance with Question 103.02 of the Securities and Exchange Commission’s Compliance and Disclosure Interpretations for non-GAAP financial measures. We believe our existing disclosures adequately describe the use of EBITDAX as a performance measure and provide the required disclosures.
In connection with responding to the Staff’s comments, we acknowledge that:
| • | 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. |
If you have any questions regarding the foregoing responses, please contact the undersigned at (405) 234-9110.
| Sincerely, | ||
| /S/ JOHN D. HART | ||
John D. Hart | ||
Senior Vice President, | ||
Chief Financial Officer and Treasurer | ||
| cc: | Jennifer O’Brien, U.S. Securities and Exchange Commission |
Shannon Buskirk, U.S. Securities and Exchange Commission
Eric S. Eissenstat, Senior Vice President, General Counsel and Secretary, Continental Resources, Inc.
Michael Dillard, Latham & Watkins LLP
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