Confidential Treatment Requested by Newfield Exploration Company Pursuant to Rule 83
Page Code NFX 04/29/2010-1
| Terry W. Rathert | Tel. (281) 847-6036 |
Executive Vice President and Chief Financial Officer | Fax. (281) 405-4242 trathert@newfield.com |
FOIA Confidential Treatment Request
April 29, 2010
Via EDGAR and Overnight Delivery
United States Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, DC 20549
| Attention: | Mr. H. Roger Schwall |
| Mr. Donald F. Delaney |
| Re: | Newfield Exploration Company |
| Form 10-K for the Fiscal Year Ended December 31, 2009 |
| Filed February 26, 2010 |
| File No. 1-12534 |
Ladies and Gentlemen:
We are responding to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission” or the “SEC”) by letter dated March 31, 2010 regarding Newfield Exploration Company’s (“Newfield”) Form 10-K for the fiscal year ended December 31, 2009 (the “Form 10-K”). For your convenience, we have included the text of the Staff’s comments from the March 31, 2010 letter in bold text within this response letter. Where applicable, Newfield’s responses provide proposed revisions to the disclosures that Newfield anticipates making in future filings.
Pursuant to the Commission’s Rule 83, 17 C.F.R. §200.83, Newfield requests confidential treatment for portions of its responses to Comment Nos. 4, 10 (including the information presented on Annex A), 15 and 16 below. Specifically, Newfield requests that the portions of these responses that are marked by [***]*, be maintained in confidence, not be made part of any public record and not be disclosed to any person, because each such portion contains confidential business information, the disclosure of which would cause serious competitive harm to Newfield. In the event that the Staff receives a request for access to the confidential portions herein, whether pursuant to the Freedom of Information Act (“FOIA”) or otherwise, Newfield respectfull y requests that Brian L. Rickmers, Newfield’s Controller, be notified immediately of such request, so that Newfield may further substantiate this request for confidential treatment under Rule 83. Mr. Rickmers may be contacted at the following address and telephone number:
Brian L. Rickmers
Controller
Newfield Exploration Company
363 North Sam Houston Parkway East, Suite 100
Houston, Texas 77060
281-847-6071
Accordingly, this letter omits confidential information included in the unredacted version of this letter that is being sent via Federal Express to the Commission’s Division of Corporation Finance on the date hereof.
Confidential Treatment Requested by Newfield Exploration Company Pursuant to Rule 83
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Response to Comments:
Form 10-K for the Fiscal Year Ended December 31, 2009
Financial Statements and Supplementary Data, page 57
Note 4, Oil and Gas Assets, page 74
| 1. | We note you disclose, as of the end of each respective year presented, the balance of oil and gas properties not subject to amortization by separate category, one of which is “Other capital costs” incurred in each respective year and cumulatively for years prior to 2007. We also note that amounts included in “Other capital costs” incurred appear to be a significant part of your total oil and gas properties not subject to amortization in each period presented. |
However, your presentation does not appear to fully comply with the disclosure guidance in Rule 4-10(c)(7)(ii)(A) of Regulation S-X, which prescribes that you disclose the amounts (balance) of capitalized costs of unproved properties and major development projects that are excluded from amortization as of the most recent fiscal year, by category, and Rule 4-10(c)(7)(ii)(B) of Regulation S-X, which prescribes that you disclose the amounts that are excluded from amortization incurred (1) in each of the three most recent fiscal years (for each category, not solely for “Other capital costs” incurred), and (2) in the aggregate (not solely for “Other capital costs”) for any earlier fiscal years in which such costs were incurred. Accordingly, please revise your disclosure to ensure that it f ully complies with Rule 4-10(c)(7)(ii) of Regulation S-X and, to the extent practicable, allocate any significant amounts included now in “Other capital costs” to existing or additional categories that will more fully describe the nature and extent of such costs incurred.
As part of your response, please tell us the nature and magnitude of items included in “Other capital costs” and tell us the years that you incurred the costs that you include in each non-other category.
Response: Although Newfield’s disclosure does not specifically denote the acquisition category as specified by Rule 4-10(c)(7)(ii) of Regulation S-X, the required amounts are appropriately disclosed in the table and fully described in the paragraphs on pages 74-75 of its Form 10-K (following the table on page 74). |
Substantially all of the amounts scheduled out by year incurred and set forth as “Other capital costs” in the table provided on page 74 of the Form 10-K are related to leasehold and property acquisition costs. To enhance its disclosure, in future filings Newfield will specifically label these costs as acquisition related costs.
Confidential Treatment Requested by Newfield Exploration Company Pursuant to Rule 83
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An example of our disclosures in the “Oil and Gas Assets” note to our consolidated financial statements in future filings (beginning with our Form 10-Q for the quarterly period ended March 31, 2010) is set forth below:
Property and equipment consisted of the following at:
| December 31, | ||||||||||
| 2009 | 2008 | 2007 | ||||||||
| (In millions) | ||||||||||
| Oil and gas properties: | ||||||||||
Subject to amortization | $ | 9,090 | $ | 8,961 | $ | 8,602 | ||||
Not subject to amortization | 1,223 | 1,303 | 1,189 | |||||||
| Gross oil and gas properties | 10,313 | 10,264 | 9,791 | |||||||
| Accumulated depreciation, depletion and amortization | (5,108 | ) | (4,550 | ) | (3,868 | ) | ||||
Net oil and gas properties | 5,205 | 5,714 | 5,923 | |||||||
| Other property and equipment | 93 | 85 | 66 | |||||||
| Accumulated depreciation and amortization | (51 | ) | (41 | ) | (31 | ) | ||||
Net other property and equipment | 42 | 44 | 35 | |||||||
| Total property and equipment, net | $ | 5,247 | $ | 5,758 | $ | 5,958 | ||||
The following is a summary of Newfield’s oil and gas properties not subject to amortization as of December 31, 2009.
| Costs Incurred In | ||||||||||||||||||||
| 2006 and | ||||||||||||||||||||
| 2009 | 2008 | 2007 | prior | Total | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Acquisition costs | $ | 155 | $ | 180 | $ | 172 | $ | 227 | $ | 734 | ||||||||||
| Exploration costs | 141 | 57 | 3 | 42 | 243 | |||||||||||||||
| Development costs | 54 | 38 | − | − | 92 | |||||||||||||||
| Fee mineral interests | − | − | − | 23 | 23 | |||||||||||||||
| Capitalized interest | 51 | 60 | 20 | − | 131 | |||||||||||||||
| Total oil and gas properties not subject to amortization | $ | 401 | $ | 335 | $ | 195 | $ | 292 | $ | 1,223 | ||||||||||
| 2. | In addition, revise your disclosure to provide a description of the current status of the significant properties or projects that are not subject to amortization pursuant to Rule 4-10(c)(7)(ii). |
Response: Newfield has provided the required disclosure of its evaluation of the properties whose costs are not subject to amortization in the paragraphs on pages 74-75 of its Form 10-K (following the table on page 74).
Confidential Treatment Requested by Newfield Exploration Company Pursuant to Rule 83
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| Engineering Comments |
| Resource Plays, page 4 |
| 3. | We note that you state that a key element of your strategy is to focus on domestic, unconventional resource plays of scale and that these reserves make up 80% of your proved reserves and 85% of your probable reserves. If your total costs per unit, including acreage costs, drilling costs, completion costs, stimulation costs, production costs, workover costs, transportation costs, taxes other than income tax, overhead, etc., are more than the current average gas price received in 2009, tell us how you considered disclosing these total unit costs by category in order to inform investors of the costs of these resource plays, and the actual unit price necessary to break even economically. |
Response: For our proved developed reserves, the average 2009 price received is greater than the remaining production costs required to produce these reserves. Therefore, these proved developed reserves generate positive free cash flow. Our production costs are set forth on page 6 of our Form 10-K.
As it respects proved undeveloped reserves, we have included all remaining capital costs and production costs required to develop these reserves. Similar to proved developed reserves, the average 2009 price received is greater than the total costs (capital and production costs). Therefore, these proved undeveloped reserves generate positive free cash flow.
Since our proved developed and proved undeveloped reserves generate positive free cash flow at average 2009 pricing, we do not believe it is necessary to disclose actual unit price required to break even economically.
| 4. | For the Woodford Shale and the Monument Butte fields please tell us the average well life you assume for reserve forecasting and the basis for that assumption. Please provide the type curve that you use to forecast the proved reserves for each field and the indicated estimated ultimate recovery based on that type curve. Please also include the decline factors such as the b factor and terminal decline rate for each curve. Please tell us for each field the largest cumulative production from a well and how long each of those wells have been on production. |
Response: Newfield uses 9 different type curves to determine the estimated ultimate recovery (“EUR”) and rate profile for the Woodford Shale. The type curves have been created using existing production history from horizontal Woodford Shale wells. To date, approximately 300 operated horizontal Woodford Shale wells have been drilled as well as approximately 250 horizontal non-operated Woodford Shale wells. The type curves are specific to a given area of the resource with known reservoir parameters and well performance histories. Please see the table below, which shows the parameters associated with the type curves that generate the lowest, average and highest EURs for the Woodford Shale. The largest cumulat ive production for a Woodford Shale horizontal well is the Sherman Ellis 4H-22. To date, the well has produced 3,894 MMcf and is now producing at a rate of 1,128 Mcf/d. The well has been on production for a little more than 3 years.
Newfield uses 9 different type curves to determine EUR and rate profile for Monument Butte. The type curves have been created using existing production history from Monument Butte wells. To date, approximately 1,937 Monument Butte wells have been drilled. The type curves are specific to a given area of the resource with known reservoir parameters, well performance histories, and well spacing. Please see the table below, which shows the parameters associated with the type curves that generate the lowest, average and highest EURs for the Monument Butte field. The largest cumulative production for a Monument Butte well is the Government 31-2-8-17. To date, the well has produced 854 MBbland is now producing at 1.5 BOPD. The well has been on production for more than 45 years.
Confidential Treatment Requested by Newfield Exploration Company Pursuant to Rule 83
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[***]*
*Confidential treatment requested by Newfield pursuant to Rule 83. Portions of the information requested by the Staff in Comment 4 are confidential. Accordingly, Newfield’s complete response is being provided separately to the Staff in hard copy only pursuant to 17 C.F.R. §200.83.
| Proved and Probable Reserves, page 7 |
| 5. | You name a number of common technologies and methods that have been used in reserve estimation for decades. Please tell us if you used any alternative methods and technologies instead of production flow tests in determining material amounts of proved reserves that you added in 2009 and why those methods or technologies are considered reliable in the geological environment in which they were used. Also tell us how many of the proved reserves added in 2009 were determined by these alternative methods and technologies. |
In addition, also tell us if you used any alternate technologies other than open-hole logs to determine gas-oil or oil-water contacts in determining material amounts of proved reserves that you added in 2009. If so, please tell us the amount of reserves and why those methods or technologies are considered reliable in the environment that they were used.
Response: We have not used any alternative methods or technologies in determining material amounts of proved reserves added in 2009. We have not used any alternative technologies other than open-hole logs to determine gas-oil or oil-water contacts in determining material amounts of proved reserves added in 2009.
| 6. | We note that you disclose the basis of the disclosure of equivalent cubic feet of natural gas. Although this is the energy equivalent, it may be confusing to some investors who may also consider it to be a price equivalency. Therefore, please revise your disclosure to clarify that equivalent quantities based on price could be materially different than what you have presented. In this regard, explain how you have considered disclosing a price equivalency for an equivalent cubic foot of natural gas or barrel of oil. |
Response: We have not used or disclosed a price equivalency for an equivalent cubic foot of natural gas or barrel of oil for the following reasons: |
| a. | Realized prices in every location vary as they have unique location and quality differentials to traditional index prices such as West Texas Intermediate, NYMEX – Henry Hub, Tapis, Brent, etc. Accordingly, there is no single price equivalency applicable to our production. |
| b. | The relationship between realized prices varies from period to period and there would be no possible way to use a single conversion ratio and still be internally consistent between our annual reports filed on Form 10-K. By way of example, using the average realized prices we reported on page 35 of our Form 10-K, the ratio of oil to natural gas would have been 15.85, 11.09 and 10.01 for 2009, 2008 and 2007, respectively. |
| c. | We believe that reporting on the basis of price equivalency would materially compromise comparability between registrants. |
Confidential Treatment Requested by Newfield Exploration Company Pursuant to Rule 83
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Proved Reserves, page 9
| 7. | You state that you developed 123 million barrels equivalent of proved undeveloped reserves in 2009. This represents approximately 10% of your total proved undeveloped reserves at year end 2008 and 7% of your proved undeveloped reserves at year end 2009. This rate of development of your proved undeveloped reserves suggests that it will take approximately 10 to 13 years to develop all of your proved undeveloped reserves, assuming that no additional proved undeveloped reserves are added during that time. As proved undeveloped reserves should generally be developed within five years of initially booking them as proved, please tell us how you plan to accomplish this. |
Response: Our 2009 proved undeveloped reserves conversion rate is not indicative of the planned pace of development of our proved reserves at year-end 2009. We plan to develop our proved undeveloped reserves within a five-year time frame. The basis for our development plans are (i) allocation of capital to projects in our 2010 capital budget and (ii) in subsequent years, on the basis of capital allocation in our five-year business plan, each of which generally is governed by our expectations of internally generated cash flow. Reserve calculations at any end-of-year period are representative of our development plans at that time. Changes in commodity pricing, oilfield service costs and availability, and other economic factors may lead to changes in development plans.
Probable Reserves, page 9
| 8. | You state that 101 BCFe of developed reserves are included in your estimate of probable reserves. Please tell us the nature of these reserves as to why they were classified as probable reserves even though they are developed. Tell us why you believe you are as likely as not to recover these quantities of probable reserves. |
Response: The 101 Bcfe of probable reserves classified as developed are probable reserves that are associated with wells that have been drilled. These developed probable reserves are primarily based on improved well performance that cannot be classified as proved due to the reasonably certain criteria, but meet the definition of probable reserves as being as likely as not to be recovered. |
| 9. | We note that you have disclosed probable reserves. However, we could not find where you also discuss the uncertainty related to those reserve estimates. Please see Instruction 5 to paragraph (a)(2) of Item 1202 of Regulation S-K and revise your disclosure accordingly. |
Response: We believe that our Form 10-K accurately describes the uncertainty associated with our 1,893 Bcfe of probable reserves. Probable reserves are defined on page 20 of our Form 10-K as “those reserves that are less certain to be recovered than proved reserves but which are as likely as not to be recovered.” On page 22 of our Form 10-K, we included a risk factor entitled “Actual quantities of oil and gas reserves and future cash flows from those reserves will most likely vary from our estimates,” which specifically discusses the uncertainty associated with both our proved and probable reserves. In the discussion of our proved and probable reserves on page 7 of our Form 10-K, we included a cross reference to that specific risk factor. Additionally, on page 9 of our Form 10-K, we stated that included in our 1,893 Bcfe of probable reserves are “904 Bcfe that would otherwise meet the definition of proved undeveloped reserves except for the fact that they will not be developed during the 2010-2014 five year horizon,” specifically indicating the level of certainty associated with almost half of our probable reserves. |
Confidential Treatment Requested by Newfield Exploration Company Pursuant to Rule 83
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Drilling Activity, page 11
| 10. | You present that you drilled a total of 159.3 net productive exploratory wells and 4.8 non-productive wells. However, we could not find any disclosure concerning new discoveries that you made with these 159.3 net productive exploratory wells. Please provide us with a list of the 155 new field discoveries or new reservoir discoveries and their locations and the volumes of oil and gas these wells produced in 2009. Please see the definition of exploratory well as set forth in Rule 4-10(a)(13) of Regulation S-X. |
Response: Our definition of exploratory well set forth on page 19 of our Form 10-K is consistent with that set forth in Rule 4-10(a)(13) of Regulation S-X. For discussion and internal reporting and budgeting purposes, we define a class of exploratory wells that are drilled to find and produce probable reserves as exploitation wells. The majority of the 155 successful exploration wells were exploitation wells that developed probable reserves and were not new field or new reservoir discoveries. [***]* We have provided a list of the 155 successful exploration wells on Annex A attached hereto. |
*Confidential treatment requested by Newfield pursuant to Rule 83. Portions of the information requested by the Staff in Comment 10 (including the information presented on Annex A) are confidential. Accordingly, Newfield’s complete response is being provided separately to the Staff in hard copy only pursuant to 17 C.F.R. §200.83.
Acreage Data, page 13
| 11. | It appears that most of your undeveloped acreage in China will expire in 2010. However, we could not find where you have discussed this fact or described the impact that this might have on your future plans in China, including as it relates to your proved or unproved reserves. Please revise your disclosure to address these and any other material concerns this issue may raise. |
Response: China represents less than two percent and approximately one percent of our total company production and reserves, respectively. The 2010 acreage expiration in China has no impact on our production, reserves, or our future plans in China. Generally, concessions in China initially cover very large acreage tracts and are subject to significant acreage relinquishments in time by their terms. As a result of this fact, it is common for contractors to ask for or include in concessions large areas of less perspective acreage so that such relinquishments do not impact potential reserves or production. Such is the case here. As a result, we believe that we have included in our Form 10-K the appropriate disclosures regarding our business and operations in China. |
Risk Factors, page 21
There is limited refining capacity for our black wax crude oil…….., page 23
| 12. | As oil production from your Monument Butte field represents almost one third of your total oil production, please revise your disclosure to include this fact in your risk factor and the specific ramifications to the Company if there was no longer a market for this crude oil. |
Response: We believe that our risk factor accurately describes the risks related to our Monument Butte field because we do not believe that there is a risk to our business that there will no longer be a market for our Monument Butte field oil production. As a result, our risk factor instead addresses the possibility that a loss of a large purchaser, for financial reasons or a physical disruption at their facilities, could result in our inability to immediately shift sales to other purchasers on like terms and conditions since each refiner has some limit on the amount of our production they may be willing to take at a particular time. Additionally, we have identified alternative sources for sales away from the Salt Lake City market, although they are less economically attractive. |
Confidential Treatment Requested by Newfield Exploration Company Pursuant to Rule 83
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Results of Operations, page 34
| 13. | Because your prior year’s conversion rate of proved undeveloped to proved developed reserves was much lower than that necessary to convert all of your proved undeveloped reserves to proved developed reserves within five years, we believe more history of your prior record of conversions would be useful to investors. Expand your disclosure to include the amount of proved undeveloped reserves that were developed in each of the last three years. Please see Section V of Securities Act No. 33-8995, Modernization of Oil and Gas Reporting. |
Response: For the reasons described in response to Question 7 above, we do not believe that historical conversion rates of our proved undeveloped reserves would provide meaningful information to investors. In future filings, we will add disclosure to clarify that our historical conversion rates are not necessarily indicative of our planned pace of development of our proved reserves. |
| 14. | Since you disclose probable reserves, please also expand your disclosure to include your history of converting probable reserves to proved reserves. Please see Section V of Securities Act Release No. 33-8995, Modernization of Oil and Gas Reporting. |
Response: For the reasons described in response to Question 7 above, we similarly do not believe that our historical conversion rates of probable reserves to proved reserves would provide meaningful information to investors. Additionally, since we did not report probable reserves for years prior to 2009, we have not prepared a historical probable reserve report from which to determine such conversion as a percent of probable reserves for analysis. |
| 15. | You state that you added 693 Bcfe of proved reserves based on the change in rules of expanding the number of proved undeveloped locations beyond one offset location away from producing wells if such locations meet the definitions of proved reserves. Please expand your disclosure to include for the unconventional reserve areas how many locations away from a producing well were determined to meet the definition of proved reserves and the evidence and technology used that supports this determination. Provide corresponding disclosure for your conventional reserves. Please see Section V of Securities Act Release No. 33-8995, Modernization of Oil and Gas Reporting. |
Response: Of the 693 Bcfe, [***]* are related to the Woodford Shale and Monument Butte fields. Therefore, our response to this comment focuses on these fields. There is no standard number of locations away from a producing well that was used to determine proved reserves in either the Woodford Shale or Monument Butte fields. As a result, we do not believe a detailed discussion of how locations were determined, nor disclosure of an arithmetic average of the number of locations away from a producing well, would enhance investor understanding, absent disclosure of confidential business information.
[***]*
Confidential Treatment Requested by Newfield Exploration Company Pursuant to Rule 83
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*Confidential treatment requested by Newfield pursuant to Rule 83. Portions of the information requested by the Staff in Comment 15 are confidential. Accordingly, Newfield’s complete response is being provided separately to the Staff in hard copy only pursuant to 17 C.F.R. §200.83.
Production, page 35
| 16. | Please tell us the amount of net oil and gas production you forecasted to produce in 2009 in the Total Proved Reserves case of your 2008 reserve report. Please reconcile any major differences between the net forecasted oil and gas volumes and actual net oil and gas volumes produced in 2009. |
Response: [***]*
*Confidential treatment requested by Newfield pursuant to Rule 83. The information requested by the Staff in Comment 16 is confidential. Accordingly, Newfield’s complete response is being provided separately to the Staff in hard copy only pursuant to 17 C.F.R. §200.83.
Estimated Quantities of Proved Oil and Gas Reserves, page 105
| 17. | We note that since 2003 your proved reserves have increased from 1.3 TCFe to 3.6 TCFe but your production has remained relatively flat during this time at around 240-250 BCFe per year. Please explain to us, in reasonable detail, the reasons why your production has not increased in a manner consistent with the increase in your proved reserves. |
Response: Our reserve base has changed dramatically over the last ten years as our focus and business have moved away from the Gulf of Mexico and Gulf Coast onshore. Oil and gas properties in those regions are characterized by short reserve life indices (“RLI”). RLI is determined by dividing the end of period reserves by the period production, expressed in years. Our RLI at the end of 2003 was 6.0. |
In 2003, we had just recently entered the Mid-Continent region and had not yet established a reserve base in a resource play. We entered the Rocky Mountains in 2004. In late 2007, we sold our Gulf of Mexico shelf properties. As a result, our asset base post-sale was comprised primarily of longer-lived reserves. Our RLI at the end of 2007 partially reflected the transformation of our asset base and was 10.0. The year-end 2008 RLI was 12.5. The year-end 2009 RLI of 14.1 is not comparable with prior periods because the basis for determining proved reserves at the end of the year changed.
Confidential Treatment Requested by Newfield Exploration Company Pursuant to Rule 83
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In responding to the comments received from the Staff by letter dated March 31, 2010, Newfield acknowledges that:
| · | Newfield 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 |
| · | Newfield 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 contact me at 281-847-6136 or Brian L. Rickmers at 281-847-6071 with any questions or comments regarding this response letter.
Yours very truly,
/s/ Terry W. Rathert
Terry W. Rathert
Executive Vice President and
Chief Financial Officer
cc: John H. Jasek
Michelle S. Miller
Brian L. Rickmers
Confidential Treatment Requested by Newfield Exploration Company Pursuant to Rule 83
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Annex A
Exploratory Well Discoveries and Related 2009 Production
[***]*
*Confidential treatment requested by Newfield pursuant to Rule 83. The information requested by the Staff in Comment 10 that is presented on this Annex A is confidential. Accordingly, Newfield’s complete response is being provided separately to the Staff in hard copy only pursuant to 17 C.F.R. §200.83.