CORRESP 1 filename1.htm

June 6, 2007

VIA FEDERAL EXPRESS

Ms. Jennifer Goeken

United States Securities and Exchange Commission

450 Fifth Street, N.W., Stop 4-5

Washington, D.C. 20549-0405

Re:

Southwestern Energy Company
Form 10-K for Fiscal Year Ended December 31, 2006
Filed March 1, 2007
Form 10-Q for Fiscal Quarter Ended March 31, 2007
Filed May 1, 2007
File No. 1-8246

Dear Ms. Goeken:

Reference is made to the letter dated May 23, 2007 to Greg D. Kerley, Chief Financial Officer of Southwestern Energy Company (the “Company”). This letter responds to the comments of the Staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) with respect to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2006 (the “2006 Form 10-K”) and Form 10-Q for Fiscal Quarter Ended March 31, 2007 (“2007 First Quarter Form 10-Q”) contained in the aforementioned letter (the “Comment Letter”). For your convenience, each of the Staff’s comments is reprinted in bold below.

Form 10-K for the Fiscal Year Ended December 31, 2006

Business, page 3

Exploration and Production, page 5

We note that you include within your filing a measure for pre-tax PV(l0). Please note that this disclosure is considered a non-GAAP measure. As such, you must provide all disclosures required by Item 10(e) of Regulation S-K. The disclosures should include reconciliation to the most directly comparable GAAP financial measure, which would be the standardized measure of discounted future net cash

Securities and Exchange Commission
June 6, 2007
Page 2

flows relating to proved oil and gas reserve quantities as set forth in paragraph 30 of FAS 69. Please revise your disclosure as appropriate.

In response to the Staff’s comment, the Company will revise its disclosures through the filing of an amendment to the 2006 Form 10-K (the “2006 Form 10-K/A”) to include the disclosures required by Item 10(e) of Regulation S-K in the discussion of pre-tax PV-10, including a reconciliation to the standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. Exhibit A sets forth the proposed revisions to the existing disclosures in the 2006 Form 10-K.

We note your statement here and elsewhere in your filing that “In 2005 and 2004, [y]our reserve replacement ratios were 399% and 365%, respectively.” Due to the variable components of this reserve replacement measure, presented for the fiscal year and on a three-year average, please expand your discussion to address each of the following, without limitation.

•

Describe how the measure is calculated. We would expect the information used to calculate this measure to be derived directly from the line items disclosed in the reconciliation of beginning and ending proved reserve quantities, which is required to be disclosed by paragraph 11 of FAS 69.

In response to the Staff’s comment, the Company confirms that the reserve replacement ratio is calculated using the line items titled “Extensions, discoveries and other additions,” “Acquisition of reserves in place,” “Revisions of previous estimates” and “Production” of the table set forth in Note (6) to the consolidated financial statements in the 2006 Form 10-K. The Company will include a definition in the glossary section of the 2006 Form 10-K/A that describes how the measure is calculated as set forth in Exhibit B.

•

Identify the status of the proved reserves that have been added (e.g., proved developed vs. proved undeveloped). It is not appropriate to calculate this measure using:

○

non-proved reserve quantities, or,

○

proved reserve additions that include both proved reserve additions attributable to consolidated entities and investments accounted for using the equity method.

In response to the Staff’s comment, the Company confirms that the reserve replacement ratio was calculated using only proved reserves and that it has fully consolidated each of its subsidiaries and does not have any ownership structures that would provide for any percentages of reserves from entities using the equity method of accounting.

Securities and Exchange Commission
June 6, 2007
Page 3

•

Identify the reasons why proved reserves were added.

○

The reconciliation of beginning and ending proved reserves, referred to above, includes several line items that could be identified as potential sources of proved reserve additions. 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.

In response to the Staff’s comment, the Company will revise its reserve replacement ratio discussions as set forth in Exhibit C to identify why proved reserves were added.

•

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.

In response to the Staff’s comment, the Company will revise its reserve replacement ratio discussions as set forth in Exhibit C to include a cross-reference to certain risk factors set forth in Item 1A and to “Forward Looking Information,” which explain the nature of and extent to which uncertainties exist with respect to newly discovered reserves.

•

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.

In response to the Staff’s comment, the Company will revise its discussions of its reserve additions as set forth in Exhibit C to disclose that the proved undeveloped reserve additions during 2006 are expected to be developed and to begin to generate cash inflows over the next three years.

•

Disclose how management uses this measure.

In response to the Staff’s comment, the Company will revise its reserve replacement ratio discussions as set forth in Exhibit C to disclose how management uses the reserve replacement measure.

Securities and Exchange Commission
June 6, 2007
Page 4

•

Disclose the limitations of this measure.

In response to the Staff’s comment, the Company will revise its reserve replacement ratio discussions as set forth in Exhibit C to disclose the limitations of the reserve replacement measure.

We also note your disclosure of finding and development costs per Mcfe on a year-to-date basis and a three-year average basis within the filing. Due to the variable components of these measures, please revise your discussion to address each of the following, without limitation.

•

Describe how the measure is calculated.

○

The information used to calculate this measure should be derived directly from the line items disclosed in the schedule of costs incurred and the reconciliation of beginning and ending proved reserve quantities, which is required to be disclosed by paragraphs 11 and 21 of FAS 69.

○

If the measure does not use data determined in accordance with FAS 69, please identify:

▪

the source of the data;

▪

indicate whether or not the measure is a non-GAAP measure, as defined by Item 10(e) (2) of Regulation S-K;

▪

if the measure is a non-GAAP measure, supplementally explain why it is appropriate to disclose it in Commission filings based on the conditions identified in Item l0(e)(l)(ii) of Regulation S-K; and,

▪

if it is determined that it is appropriate to disclose the nonGAAP measure in Commission filings, provide the disclosure required by Item 10(e) (1 )(i) and Question 8 of the Frequently Asked Questions Regarding the Use of Non-GAAP Financial Measures, located at http://www.sec.gov/divisions/corpfin/fags/nongaapfag.htm.

○

Note that finding costs include asset retirement costs. Therefore, this measure should also include asset retirement costs. Refer to the February 24, 2004 sample letter sent to oil and gas producers regarding FAS 69 and SFAS 143, located at http://www.sec.gov/divisions/corpfinlguidance/oilgasletter.htm.

Securities and Exchange Commission
June 6, 2007
Page 5

○

Note that future development costs expected to be incurred relative to the specific set of reserve additions included in the calculation of the measure should also be included in the calculation.

In response to the Staff’s comment, the Company confirms that the reserve additions used to determine the finding and development cost is calculated using the line items titled "Extensions, discoveries and other additions, "Acquisition of reserves in place," and "Revisions of previous estimates" of the table set forth in Note (6) to the consolidated financial statements in the 2006 Form 10-K. Additionally, the Company includes the FAS 69 costs presented in Note (5) to the consolidated financial statements plus all office equipment-related capital investments not disclosed per the requirements of FAS 69 in calculating finding and development costs. The office equipment-related costs are derived directly from the Company’s financial statements and have no material impact on the calculation of finding and development costs. The finding and development costs measure does not constitute a non-GAAP financial measure.

The Company will include a definition in the glossary section of the Form 10-K/A that describes how the measure is calculated as set forth in Exhibit B, including the effects of asset retirement obligations. The definition of finding and development costs does not include future development costs, which is consistent with approach taken throughout the industry in calculating this measure. The Company has enclosed supplemental examples of disclosures by other E&P companies of comparable measures that exclude future development costs. As finding and development costs is a measure utilized by investors to compare the Company with its peers, the Company believes that the inclusion of future development costs in its finding and development costs would not enhance investor understanding and would, in fact, mislead investors about the Company’s performance relative to its peers. As noted in the response to Item 2, the Company has revised its discussion of proved undeveloped reserves as set forth in Exhibit C to state the expected amount of future development costs for its proved undeveloped reserves at year-end. The Company believes the disclosure of expected future development costs provides investors with the necessary information without sacrificing the ability to compare peer companies.

•

Identify the status of the proved reserves that have been added (e.g., proved developed vs. proved undeveloped).

○

It is not appropriate to calculate this measure using non-proved reserves or to use a figure for proved reserve additions that includes both proved reserve additions attributable to consolidated entities combined with proved reserve additions attributable to investments accounted for using the equity method.

○

When a significant portion of the proved reserve additions is proved undeveloped, disclose that additional development costs will need to be incurred before these proved reserves are ultimately produced, and the impact this has on the use and reliability of the measure.

Securities and Exchange Commission
June 6, 2007
Page 6

○

Disclose the amount of the estimated future development costs. Explain to investors, if true, that the amount of estimated future development costs related to the proved reserve additions is a component of amounts disclosed in the SFAS 69 disclosures.

In response to the Staff’s comment, the Company refers the Staff to its response to Item 2 above where the Company confirms that its reserve additions are comprised only of proved reserves. Further, the Company confirms its finding and development costs do not include non-proved reserves. The Company also refers the Staff to the revisions set forth in Exhibit C, which contains the requested disclosures that additional development costs will need to incurred before the proved undeveloped reserves are ultimately produced and provides an estimate of that cost for proved undeveloped reserves as of December 31, 2006.

•

Identify the reasons why proved reserves were added.

○

The reconciliation of beginning and ending proved reserves, referred to above, includes several line items that could be identified as potential sources of proved reserve additions. Explain to investors the nature of the reserve additions, 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.

○

Identify all situations that resulted in a reserve addition that did not require the expenditure of additional costs. We note for example that changes in commodity prices and foreign exchange rates routinely have a direct impact on the quantity of proved reserve quantities, but do not require the expenditure of additional exploration or development costs.

In response to the Staff’s comment, the Company refers the Staff to its response to the corresponding item in Item 2 above and the revisions contained in Exhibit C. All of the Company’s reserve additions required capital investments during the year or will require future capital investments. Changes in proved reserves due to changes in commodity prices and performance are included in “Revisions of previous estimates” of the table set forth in Note (6) to the consolidated financial statements in the 2006 Form 10-K and are reflected in the finding and development costs metrics which include reserve revisions.

•

Disclose how management uses this measure.

In response to the Staff’s comment, the Company refers the Staff to its response to the corresponding item in Item 2 above and the revisions contained in Exhibit C.

Securities and Exchange Commission
June 6, 2007
Page 7

•

Disclose the limitations of this measure.

In response to the Staff’s comment, the Company refers the Staff to its response to the corresponding item in Item 2 above and the revisions contained in Exhibit C.

•

Indicate whether or not the finding and development cost per unit measure is comparable to other like measures disclosed by other companies.

In response to the Staff’s comment, the Company refers the Staff to its response to the first bullet point in this Item 3, including the examples of disclosures by other companies provided supplementally herewith.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 38

Financing Requirements, page 48

We note your disclosure of a ratio of EBITDA to interest expense as of December 31, 2006 of 610.5. Please note that this disclosure is considered a non-GAAP measure because it has been calculated with an amount considered to be a nonGAAP measure. As such, please provide all disclosures required by Item 10(e) of Regulation S-K.

In response to the Staff’s comment, the Company notes that EBITDA and the required reconciliation is provided in the 2006 Form 10-K. Since the ratio of EBITDA to interest expense therefore can be calculated by an investor and the Company discloses that it is in compliance with all of its debt covenants, the Company proposes to delete the discussion of the ratio of EBITDA to interest expense in the 2006 Form 10-K/A.

Off-Balance Sheet Arrangements, page 48

We note your statement that “In accordance with our accounting procedures, the portion of the lease payments that represent drilling costs from our working interest in wells are capitalized to the full cost pool.” Please tell us what the remaining portion of the lease payments represent and where they are reported in your financial statements.

In response to the Staff’s comment, the Company notes that the remaining portion of the lease payments on the Company’s drilling rigs would represent costs incurred for third party working interest owners that participate in the Company’s operated wells. These

Securities and Exchange Commission
June 6, 2007
Page 8

costs are also recorded to the full cost pool but are considered offset by billings to these owners for rig operating costs. The Company’s subsidiary, Desoto Drilling, Inc. (“DDI”), was formed to operate drilling rigs for the purpose of drilling wells in areas where the Company’s E&P segment has concentrated interests, primarily in the Fayetteville Shale play. DDI is managed by the Company’s E&P executives and is an integral part of the Company’s overall exploration and development activities. The operating costs for DDI, including the lease payments for the rigs, as well as the credits generated from billings on a day-rate basis to third party working interest owners, are recorded to the full cost pool.

Quantitative and Qualitative Disclosures About Market Risk, page 56

We note that you recognized a $20.2 million gain in the fiscal year ended December 31, 2006 and a $9.4 million loss in the fiscal year ended December 31, 2005 related to the change in estimated ineffectiveness of your cash flow hedges. Please expand your disclosure to explain the facts and circumstances surrounding these gains and losses.

In response to the Staff’s comment, the Company will revise and amend the ‘gain on ineffectiveness of cash flow hedges’ disclosure in the 2006 Form 10-K as set forth in Exhibit E.

Balance Sheets, page 62

Please disclose the major classes of your inventory balances in accordance with Rule 5-02(6)(a) of Regulation S-X. In addition, please elaborate on the average cost methodology you use in determining the value of your inventory and the method by which amounts are removed from inventory, as contemplated by Rule 5-02(6)(b) of Regulation S-X.

In response to the Staff’s comment, the Company will revise its 2006 Form 10-K to add a new subsection headed “Inventory” to Note (1) of the consolidated financial statements to provide the additional disclosures set forth in Exhibit F.

Reconciliation of Accumulated Other Comprehensive Income (loss), page 65

Please explain the nature of the adjustment “Current period ineffectiveness” and why such amounts are presented in accumulated other comprehensive income/loss. In this regard, it is unclear why the ineffective portion of your hedging activities are not directly reported in earnings in accordance with FAS 133. Please advise.

In response to the Staff’s comment, the Company advises the Staff that the change in ineffectiveness regarding its cash flow hedges was a pre-tax gain of $20.2 million ($12.7 million after-tax as shown in the reconciliation) for the year ended 2006. The $20.2 million is discussed on page 56 of the 2006 Form 10-K, and the disclosure has been

Securities and Exchange Commission
June 6, 2007
Page 9

revised as indicated in the Company’s response to Item 6 of the Comment Letter. The ($12,726) line-item labeled “Current period ineffectiveness” represents the reclassification from accumulated other comprehensive income to gas or oil sales for the period presented, consistent with the application of FAS 133.

(1) Summary of Significant Accounting Policies, page 66

Property, Depreciation, Depletion and Amortization, page 67

We note your disclosure that “Retirements are credited to property, plant and equipment at cost and charged to accumulated depreciation, depletion and amortization with no gain or loss recognized, except for abnormal retirements.” Please expand your disclosure to explain what you mean by abnormal retirements.

In response to the Staff’s comment, the Company will revise and amend the ‘Gas Distribution Systems retirements’ disclosure on page 67 of its 2006 Form 10-K as follows: “Retirements are credited to property, plant and equipment at cost and charged to accumulated depreciation, depletion and amortization with no gain or loss recognized, except for abnormal retirements such as the sale or disposition of a large operating unit or system.”

Controls and Procedures, page 87

10.

We note your statement that “All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a reasonable assurance with respect to financial statement preparation and presentation.” Please confirm, if true, that your disclosure controls and procedures are effective at the reasonable assurance level or otherwise advise. Please revise your conclusion as to effectiveness of your disclosure controls and procedures to ensure that the reader understands their effectiveness is based upon the reasonable assurance level. This comment also applies to your Form l0-Q for the fiscal quarter ended March 31, 2007.

In response to the Staff’s comment, the Company will revise the fifth sentence of the first paragraph of its Item 9A disclosure in its 2006 Form 10-K and the 2007 First Quarter Form 10-Q as follows: “Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of December 31, 2006 and provided a level of reasonable assurance with respect to financial statement preparation and presentation.”

Securities and Exchange Commission
June 6, 2007
Page 10

Exhibits 31.1 and 31.2

11.

We note that your certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 is worded such that it does not precisely match the language as set forth in the Act. Refer to Item 601(b)(31) of Regulation S-B for the exact text of the required Section 302 certifications, and amend your exhibits as appropriate. In this regard and without limitation, there is no provision for your certifying officer to identify the position held with the Company in the first line of the certification. Please refer to Item 60l(b)(3 1) of Regulation S-K for the exact text of the required Section 302 certification and revise your exhibits as appropriate. This comment also applies to your Form l0-Q for the fiscal quarter ended March 31, 2007.

In response to the Staff’s comment, in connection with the filing of the 2006 Form 10-K/A and an amendment to its 2007 First Quarter 10-Q, the Company confirms that it will file its Section 302 certifications in accordance with Item 601(b)(31) of Regulation S-K.

Engineering Comments

Business, page 3

Exploration and Production, page 6

12.

We note the proved gas reserves in your Fayetteville shale play are 27% developed. Please submit to us the petroleum engineering reports - in hard copy and electronic spreadsheet format - you used as the basis for your 2006 Fayetteville shale proved gas reserve disclosures. The report should include:

The Company has provided a copy of the relevant portion of the audit letter issued by Netherland, Sewell & Associates, Inc. (“NSAI”) for the year-ended December 31, 2006 as well as the supplemental information requested relating to the proved reserve disclosures contained in the 2006 Form 10-K in a separate letter addressed to Mr. Ronald Winfrey dated even date herewith requesting confidential treatment of such information pursuant to Rule 83 (17 C.F.R. 2000.83) (the “Confidential Submission”).

One-line recaps for each well/location sorted by present worth within each proved reserve category including the dates of first booking and estimated first production for your proved undeveloped properties;

The requested information has been provided in the Confidential Submission.

Total play summary income forecast schedules for each proved reserve category with proved developed segregated into producing and non-producing properties;

Securities and Exchange Commission
June 6, 2007
Page 11

The requested information has been provided in the Confidential Submission.

Individual income forecasts for each of the three largest properties (net equivalent reserve basis) in the proved developed and in the proved undeveloped categories as well as the AFE for each of the three PUD wells;

The requested information has been provided in the Confidential Submission.

Engineering exhibits (e.g. maps, rate/time plots, volumetric calculations) for each of these six largest properties. Please explain your methodology for estimating the gas in place and compare representative proved gas reserves with corresponding GIP estimates; specifically address the role of gas well material balance in your GIP estimates. Discuss your methodology in determining type curve decline parameters such as “b factor”, representative initial flow rate and terminal decline rate in light of the fact that pseudo-steady state is generally not achieved. Tell us if all your horizontal well PUD locations are adjacent to and parallel with (rather than a colinear extension of) productive horizontal well laterals. You may contact us for assistance in this or any other matter.

The requested information has been provided in the Confidential Submission.

Glossary of Certain Industry Terms, page 20

Proved developed reserves, page 22

13.

Please be advised that the current SEC website location for Rule 4-10(a) of Regulation S-X is www.sec.gov/about/forms/regs-x.pdf, page 41. Please amend your future documents to reflect this change.

In response to the Staff’s comment, the Company will correct the reference to Rule 4-10(a) in its 2006 Form 10-K/A.

Securities and Exchange Commission
June 6, 2007
Page 12

Risk Factors, page 23

Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate., page 24

14.

We note your statement, “The estimates of Netherland, Sewell & Associates, Inc. may differ significantly on an individual property basis from our estimates. When, in the aggregate, such differences are within 10%, Netherland, Sewell & Associates, Inc. is generally satisfied that the estimates of proved reserves are reasonable.” Please furnish to us the spreadsheet comparison and reconciliation between your estimates and those of your third party engineer.

The requested information has been provided in the Confidential Submission.

Critical Accounting Policies, page 51

Natural Gas and Oil Properties, page 52

15.

We note your statement, “In conducting its audit, the engineers and geologists of Netherland, Sewell & Associates study our major properties in detail and independently develop reserve estimates. For the year-ended December 31, 2006, Netherland, Sewell & Associates issued its audit opinion as to the reasonableness of our reserve estimates, stating that our estimated proved oil and gas reserves are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles.” While we understand that there are fundamentals of physics, mathematics and economics that are applied in the estimation of reserves, we are not aware of an official industry compilation of such “generally accepted petroleum engineering and evaluation principles’. With a view toward possible disclosure, please explain to us the basis for concluding that such principles have been sufficiently established so as to judge that the reserve information has been prepared in conformity with such principles. Address the portion of your reserves that were analyzed by your third party engineer. Tell us the data items that were necessary’ for the estimates, but were accepted by your third party engineer without further confirmation.

In response to the Staff comment, the Company acknowledges that there is not an official industry compilation of “generally accepted petroleum engineering and evaluation principles”. However, the Society of Petroleum Engineers in its “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” states:

Securities and Exchange Commission
June 6, 2007
Page 13

1.2

Estimating and Auditing Reserves Information in Accordance With Generally Accepted Engineering and Evaluation Principles

The estimating and auditing of Reserves Information is predicated upon certain historically developed principles of geoscience, petroleum engineering, and evaluation methodologies, which are in turn based on principles of physical science, mathematics, and economics. Although these generally accepted geological, engineering, and evaluation principles are predicated on established scientific concepts, the application of such principles involves extensive judgments by qualified individuals and is subject to changes in (i) existing knowledge and technology; (ii) fiscal and economic conditions; (iii) applicable contractual, statutory, and regulatory provisions; and (iv) the purposes for which the Reserves information is to be used.

The engineers within the Company who estimate its proved reserves under the supervision of management, including certified engineers in the State of Texas, and the engineers within Netherland, Sewell, & Associates who audit the Company’s estimates are qualified individuals based on their education and experience within the oil and gas industry.

NSAI’s audit of the Company’s proved reserves estimates consisted of a detailed review of major properties making up approximately 86% of the Company’s total proved reserves. Per NSAI’s audit letter, it did not independently verify the data the Company provided to them with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. NSAI, has advised us that if, in the course of its audit, something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved any questions relating thereto or had independently verified such information or data.

* * *

In connection with responding to the foregoing comments, the Company hereby acknowledges 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.

Securities and Exchange Commission
June 6, 2007
Page 14

Please do not hesitate to contact the undersigned at (281) 618-4859, or the Company’s Chief Financial Officer, Greg D. Kerley at (281) 618-4803 if you have any questions regarding the foregoing or the enclosures.

Very truly yours,

/s/ Trecia M. Canty

Trecia M. Canty

Assistant Secretary & Senior Attorney

cc:

Jill S. Davis

Securities and Exchange Commission (w/o enclosure)

Kimberly Calder

Ronald Winfrey

Securities and Exchange Commission

Greg D. Kerley

Executive Vice President and Chief

Financial Officer

Richard F. Lane

Executive Vice President

President, Southwestern Energy Production Company and

SEECO, Inc.

Mark K. Boling

Executive Vice President and

General Counsel

Enclosures