August 12, 2010
VIA EDGAR & FEDERAL EXPRESS
H. Roger Schwall
Assistant Director
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 the Fiscal Year Ended December 31, 2009
Filed February 25, 2010
Definitive Proxy Statement
Filed April 6, 2010
File No. 1-08246
Dear Mr. Schwall:
Reference is made to the letter dated July 22, 2010 to Greg D. Kerley, Executive Vice President & 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, 2009 (the “2009 Form 10-K”) and Schedule 14A filed April 6, 2010 (“Schedule 14A”) contained in the aforementioned letter (the “Comment Letter”). For your convenience, each of the Staff’s comments is reprinted in bold below. With the Staff’s permission, where the responses indicate that the Company will revise its disclosures and/or make additional disclosures, the Company would like to include such disclosures in its future filings on the form to which the comment relates.
Form l0-K for the Fiscal Year Ended December 31, 2009
Business, page 3
Our Proved Reserves, page 5
Proved Undeveloped Reserves, page 7
1.
We note your significant increase in proved gas reserves and your statement, "[w]e used standard engineering and geoscience methods...." Describe for us in more detail what you mean by this statement. Please also explain to us the difference, if any, between your application of these methods for 2009 proved reserves versus your application for 2008. Tell us the number of proved undeveloped locations you booked that were more than one offset removed from a productive well(s) as well as the number of offsets these locations are displaced.
Mr. H. Roger Schwall
Securities and Exchange Commission
August 12, 2010
Page 2
The Company acknowledges the Staff’s comments and su pplementally confirms to the Staff that the Company did not change its application of the standard engineering and geoscience methods utilized in determining its 2009 proved reserves from the application utilized in determining the Company’s 2008 proved reserves. Specifically, consistent with the Company’s past practices, the Company advises the Staff that it did not book any proved undeveloped locations that were more than one offset removed from a productive well.
With respect to the engineering and geoscience methods employed by the Company, where applicable, the Company supplementally advises the Staff that it utilized one or more of the following methodologies in determining the estimates of its proved reserves: (1) performance and test data analysis; (2) offset statistical analogy of performance data; (3) volumetric evaluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil & gas) and permeability) in combination with estimated reservoir parameters (including reservoir temperature and pressure, formation depth, formation volume factors); (4) geological analysis, including structure and isopach maps; (5) seismic analysis, including review of 2-D & 3-D data to ascertain faults, closure, etc. It has been the Company’s experience that the utilization of these computational methods and technologies have historically proven to provide reasonably certain results in evaluating each field’s booked reserves, maintaining consistency and repeatability in the reserves analysis process for the formation being evaluated.
The Company has long-standing operations in each of the areas in where its proved reserves are located. The Company’s operations in the Arkoma Basin date to 1943, while its oper ations in East Texas and the Fayetteville Shale date to 2000 and 2004, respectively. The Company has not experienced any material revisions of its proved reserves relating to the inaccuracy or unreliability of its analyses and methodologies. Based upon the foregoing, the Company believes that its operating history in these areas demonstrates that its analyses and methodologies provide reasonably certain results with consistency and repeatability in the formations and that the engineering and geoscience methods it utilizes meets the criteria for reliable technology set forth in Rule 4-10(a)(25) of Regulation S-X.
2.
You state that during 2009 you invested $19 million in connection with converting 120.8 Bcfe of your proved undeveloped reserves as of Decem ber 31, 2008 into proved developed reserves. This represents approximately 14% of your total proved undeveloped reserves at year end 2008. This rate of development of your proved undeveloped reserves suggests that it will take over 5 years to develop all of your proved undeveloped reserves. 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.
The Company acknowledges the Staff’s comments and supplementally advises the Staff that the rate of development of our proved undeveloped reserves in 2009 should not be misconstrued as indicating that the Company will be unable to develop its proved reserves within five years of initially booking them. There are a number of factors that have been taken into account in the Company’s five year development plan that will impact the proved undeveloped reserve development rate going forward.
Mr. H. Roger Schwall
Securities and Exchange Commission
August 12, 2010
Page 3
The Company’s proved undeveloped reserves are largely attributable to its Fayetteville Shale play. As of year-end 2009, the Company had 1,677.7 Bcfe of booked proved undeveloped reserves in 1,245 wells, of which 1,615.9 Bcfe and 1,150 wells were located in the Fayetteville Shale Play. In 2009, the Company drilled 639 wells in total, with 570 of these wells in the Fayetteville Shale Play. Of these 570 wells, only 93 wells had proved undeveloped reserves associated with them at year end 2008. The Company’s development plan with respect to its year-end 2009 proved undeveloped reserves will achieve the development of those reserves within five years primarily due to the planned shift in the focus of our Fayetteville Shale drilling program, beginning in 2011, away from drilling locations which did not have any associated proved undeveloped reserves in prior years in order to preserve the value of our leasehold investments.
As disclosed in the 2009 Form 10-K, beginning in 2011, the leasehold in the Company’s Fayetteville Shale play that will expire if the Company does not drill successful wells or extend the leases will decrease from 120,977 net ac res in 2010 to 23,722 net acres in 2011. Assuming a drilling program based on the Company’s current rig count and well development rate within this play, in 2011, the Company estimates that approximately forty percent (40%) of the wells to be drilled will relate to its proved undeveloped locations as of year-end 2009.
The Company would also like to supplementally advise the Staff that the amount of investments made in connection with converting proved undeveloped reserves as of December 31, 2008 into proved developed reserves was not $19 million as reflected in the 2009 Form 10-K but approximately $221 million, and this correction will be reflected in a future filing.
Production, Average Sales Price and Average Production Cost, page 38
3.
Please revise the table to also present the information by each field that contains 15% or more of your total proved reserves, or tell us why such disclosure is not required. See Item 1204(a) of Regulation S-K.
The Company acknowledges the Staff’s comments and hereby advises the Staff that the Company’s Fayetteville Shale operations represented its only field that contained 15% or more of the Company’s total proved reserves in fiscal years 2009 and 2008, and the field only produces natural gas. In fiscal year 2007, both the Fayetteville Shale operations and the Company’s Overton Field in East Texas contained 15% or more of the Company’s total proved reserves. The Overton Field produces both oil and natural gas. The Company will revise the presentation of its production, average sales price and average production cost in its future filings to be as set forth in Exhibit A hereto.
Exhibit 99
4.
Item 1202(a)(8) of Regulation S-K specifies disclosure items pertaining to third party engineering reports. Please obtain and file a revised report that includes the following information:
Mr. H. Roger Schwall
Securities and Exchange Commission
August 12, 2010
Page 4
•
The aggregate percentage difference between your proved reserve estimates and those of your third party engineer; and
•
The weighted average prices from the total company reserve report. You provide the average West Texas Intermediate and Henry Hub prices, but these appear to be for reference rather than the actual price u tilized.
The Company acknowledges the Staff’s comments, which have been conveyed to the Company’s third party engineer, Netherland, Sewell & Associates, Inc. (“NSAI”). NSAI has advised the Company of the following:
·
the audit conducted by NSAI primarily consists of substantive testing, which includes a detailed review of major properties making up approximately 90 percent of the Company’s total proved reserves;
·
the aggregate percentage difference of the audited proved reserves between NSAI and the Company was less than 10 percent; and
·
the average adjusted product prices for the total company reserve report weighted by production over the remaining lives of the properties are $57.15 per barrel of oil and $3.42 per MCF of gas.
NSAI has further advised the Company that it intends to include statements regarding (i) the aggregate audit tolerance threshold and (ii) an applicable statement of the weighted average prices in future audit reports filed with the Commission.
5.
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 "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. Tell us the data items that were necessary for the estimates, but were accepted by your third party engineer without further confirmation.
The Company acknowledges the Staff’s comments, which the Staff clarified in a telephone conversation on August 3, 2010 are intended to be add ressed by NSAI. The Staff’s comments were conveyed to NSAI, which has advised the Company of the following:
·
In the February 19, 2007, publication of the Society of Petroleum Engineers (“SPE”) entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” (the “SPE 2007 Standards”), the SPE acknowledges in the foreword section thereof and in section 1.2 that there are “generally accepted engineering and evaluation principles” applicable to the estimation and auditing of oil and gas reserves. The SPE goes further in section 1.2 to define the relationship between such principles
Mr. H. Roger Schwall
Securities and Exchange Commission
August 12, 2010
Page 5
and the “principles of physical science, mathematics, and economics.” A copy of the SPE 2007 Standards is available for reference at the following website: http://www.spe.org/industry/reserves/docs/Reserves_Audit_Standards_2007.pdf. Beyond the SPE 2007 Standards, NSAI is not aware of a s ingle official reference or compilation that sets out a concise list of “generally accepted petroleum engineering and evaluation principles.” NSAI generally looks to the SPE 2007 Standards, the Commission’s regulations, and other SPE publications, including SPE’s publication entitled Petroleum Resources Management System, and uses textbooks such as “Applied Petroleum Reservoir Engineering” by Craft and Hawkins and “Practical Reservoir Engineering Methods” by H.C. Slider as a basis for “generally accepted engineering and evaluation principles.”
·
The estimates shown in the report of NSAI included as Exhibit 99.1 to the Company’s 2009 Form 10-K have been prepared using the generally accepted pr inciples and methods as promulgated by the SPE in the SPE 2007 Standards and as embodied by the petroleum engineering textbooks, as well as in accordance with applicable standards promulgated by the Commission.
·
The data items that were necessary for the estimates that were accepted by NSAI but were not independently verified for accuracy and completeness include 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 further explains in paragraph 9 of Exhibit 99.1, “However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data.”
NSAI has further advised the Company that it will include a reference to the SPE 2007 Standards in its future applicable audit reports filed with the Commission.
6.
We note the following language in Netherland Sewell's report:
In evaluating the information at our disposal concerning this report, we have excluded from o ur consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geoscience.
Clarify the reason for including this language. In this regard, we note that the definition of "reserves" in Rule 4-10 (a)(26) of Regulation S-X indicates that "there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or revenue interest in the production." We also note that the definition of proved reserves is contained in Regulation S-X which is an accounting regulation.
Mr. H. Roger Schwall
Securities and Exchange Commission
August 12, 2010
Page 6
The Company acknowledges the Staff’s comments, which have been conveyed to NSAI. NSAI has advised the Company that, in future audit reports filed with the Commission, it will delete the subject sentence and replace it with wording similar to the following:
“Our expertise is in petroleum engineering, geoscience, and petrophysical interpretation, not legal or accounting matters; we are not accountants, attorneys, or landmen.”
Definitive Proxy Statement filed April 6, 20 10
Transactions with Related Persons, page 17
7.
Please describe the standards to be applied in connection with the review, approval or ratification of transactions with related persons. See Item 404(b)(1)(ii) of Regulation S-K.
The Company acknowledges the Staff’s comments and supplementally advises the Staff of the following, which the Company will include in its future filings:
“The related-party transaction policy applie s to any potential related-party transaction other than a transaction involving less than $5,000 or involving compensation by the Company of a related party or an immediate family member of a related party. Under the Company’s related party transaction policy, directors and officers are required to bring any possible related-party transaction to the attention of the Company’s General Counsel. The Audit Committee reviews each related-party transaction of which it becomes aware and may approve or ratify a related-party transaction if the Audit Committee determines the transaction is on terms comparable to those that could be obtained in arm’s length dealings with an unrelated third party. The Audit Committee, in discharging its authority to review and approve related party transactions, must (i) review with management any decisions to undertake a significant collaboration or business dealing that may directly or indirectly benefit a related party; (ii) establish guidelines for management to follow in its ongoing dealings with related parties; (iii) periodically review and assess ongoing relationships with related parties to ensure compliance with the Committee’s guidelines and directives and to ensure the continuation of such relationship remains fair to the Company; and (iv) analyze and assess applicable potential conflicts of interests and usurpation of corporate opportunities. The Audit Committee reports periodically to the Board on the nature of the related-party transactions that have been presented to the Audit Committee and the determinations that the Audit Committee has made with respect to those transactions.”
Mr. H. Roger Schwall
Securities and Exchange Commission
August 12, 2010
Page 7
Compensation Discussion and Analysis, page 22
Total Cash Compensation, page 25
Incentive Plan, page 26
8.
In response to comment 10 from our letter dated June 27, 2008, you undertook to discuss the degree of difficulty of achieving the performance targets under your Incentive Plan. We note your related disclosure that your compensation committee believes that , assuming external economic factors remain the same, the minimum performance levels should be achievable with some difficulty, while the target and maximum levels represent relatively more challenging degrees of difficulty. Please revise your disclosure to describe with meaningful specificity how difficult or likely it would be for you to achieve the undisclosed targets. Please provide support for the level of difficulty that you assert, which could include, for example, a discussion of the correlation between historical and future achievement of the relevant performance metric. Please also provide such disclosure with respect to the targets related to your Performance Unit Plan.
The Company acknowledges the Staff’s comments and advises the Staff that, in its future filings, the Company will include the requested additional disclosures, the substance of which is set forth in Exhibit B, with the additional disclosures shown in red with double underlining.
* * *
Mr. H. Roger Schwall
Securities and Exchange Commission
August 12, 2010
Page 8
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 comment s as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.
Please do not hesitate to contact the undersigned at (281) 618-4859, or the Company’s Executive Vice President & Chief Financial Officer, Greg D. Kerley at (281) 618-4803 if you have any questions regarding the foregoing.
Very truly yours,
/s/ TRECIA M. CANTY
Trecia M. Canty
Associate General Counsel-Corporate &
Assistant Secretary
cc:
Mr. Steve Mueller
President and CEO
Southwestern Energy Company
Mr. Greg Kerley
Executive Vice President and CFO
Southwestern Energy Company
Mr. Mark Boling
Executive Vice President and General Counsel
Southwestern Energy Company
EXHIBIT A
Production, Average Sales Price And Average Production Cost by Area
2009 | |
Gas: |
|
Production (Bcf): |
|
Fayetteville Shale | 243.5 |
Total | 299.7 |
Average sales price (per Mcf), including hedges: |
|
Fayetteville Shale | $ 5.73 |
Total | $ 5.30 |
Average sales pr ice (per Mcf), excluding hedges: |
|
Fayetteville Shale | $ 3.31 |
Total | $ 3.34 |
Oil(1): |
|
Production (MBbls) | 124 |
Average sales price (per Bbl) | $ 54.99 |
|
|
Average Production Cost: |
|
Cost, excluding ad valorem and severance taxes (per Mcfe): |
|
Fayetteville Shale | $ 0.80 |
Total | $ 0.77 |
(1) The Company’s Fayetteville Shale operations did not produce any oil.
2008 | |
Gas: |
|
Production (Bcf): |
|
Fayetteville Shale | 134.5 |
Total | 192.3 |
Average sales price (per Mcf), including hedges: |
|
Fayetteville Shale | $ 7.22 |
Total | $ 7.52 |
Average sales price (per Mcf), excluding hedges: |
|
Fayetteville Shale | $ 7.52 |
Total | $ 7.73 |
Oil(1): |
|
Production (MBbls) | 385 |
Average sales price (per Bbl) | $ 107.18 |
|
|
Average Production Cost: |
|
Cost, excluding ad valorem and severance taxes (per Mcfe): |
|
Fayetteville Shale | $ 0.99 |
Total | $ 0.89 |
(1) The Company’s Fayetteville Shale operations did not produce any oil.
2007 | |
Gas: |
|
Production (Bcf): |
|
Fayetteville Shal e | 53.5 |
Overton Field | 24.3 |
Total | 109.9 |
Average sales price (per Mcf), including hedges: |
|
Fayetteville Shale | $ 7.32 |
Overton Field | $ 6.40 |
Total | $ 6.80 |
Average sales price (per Mcf), excluding hedges: |
|
Fayetteville Shale | $ 6.00 |
Overton Field | $ 6.40 |
Total | $ 6.16 |
Oil(1): |
|
Production (MBbls): |
|
Overton Field | 167 |
Total | 614 |
Average sales price (per Bbl): |
|
Overton Field | $ 69.34 |
Total | $ 69.12 |
|
|
Average Production Cost: |
|
Cost, excluding ad valorem and severance taxes (per Mcfe): |
|
Fayetteville Shale | $ 0.89 |
Overton Field | $ 0.42 |
Total | $ 0.73 |
(1) The Company’s Fayetteville Shale operations did not produce any oil.
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EXHIBIT B
Incentive Compensation Plan (Disclosures found in the last paragraph on page 28 of the 2010 Proxy Statement):
At the February meeting in 2010, after evaluating the Company’s performance relative to performance goals established for 2009, the Compensation Committee established the performance objectives for 2010. The 2010 performance targets take into consideration the anticipated economic recovery as well as the continued uncertainty and volatility in the natural gas commodity prices but are nonetheless designed to continue to motivate our NEOs to outperform relative to their peers at other companies. The Compensation Committee believes that, assuming external economic factors remain the same, the minimum performance levels should be achievable with some difficulty, while the target and maximum levels represent relatively more challenging degrees of difficulty. &nb sp;Although the Compensation Committee does not assign specific probabilities of achievement to the minimum, target or maximum award levels under the Incentive Plan, the minimum and target goals are generally set to be achievable if the Company achieves the minimum and target levels in its projected business plan. It is the Committee’s intention and expectation in setting the objectives for incentive bonuses to be paid at the target level or above. The maximum award levels are achievable to the extent the Company surpasses its target performance levels by a significant amount. However, since the business plan reflects a number of internal assumptions about factors beyond the Company’s control such as oil and gas prices, access to capital, the cost of supplies and equipment and other third party-related factors, the achievement of our performance measures has varied. As the following table detailing our corporate performance measure achievement fr om 2006 through 2009 illustrates, there has been no correlation between past and future achievement of our performance measures:
ICP CORPORATE PERFORMANCE MEASURE ACHIEVEMENT | ||||
| Production | PVI | Return on Equity | Reserve Replacement |
2006 | Below Minimum | Below Minimum | Below Minimum | Above Target |
2007 | Above Minimum | Above Target | Above Maximum | Above Target |
2008 | Above Maximum | Above Maximum | Above Maximum | Above Maximum |
2009 | Above Target | At Maximum | Above Target | At Maximum |
Performance Unit Plan (Disclosures found in the second full paragraph on page 30 of the 2010 Proxy Statement):
Performance Unit Plan. Our Performance Unit Plan is used to provide long-term cash incentives for our executives and certain employees. The Performance Unit Plan is designed to insure that our long-term strategy is competitive with our peers and that our executives are rewarded with cash for actual long-term performance and not just stock price appreciation. The Plan also complements the equity-based compensation awarded under the Stock Plan by providing additional awards for enhancing our long-term value and mitigating the effect of stockholder dilution. The determinations of performance unit awards are made at the December Compensation Meeting prior to the beginning of the fiscal year in order to coincide with the culmination of our performance review process and the establishment of the other components of compensation for the upcoming fiscal year. Because the Performance Unit Plan is tied to operating performance success metrics over a three-year period, it also provides a supplem entary long-term retention component. Actual payout occurs more than three years after the awards are given and is determined by the attainment of certain threshold, target and maximum performance objectives, which pay $500 per unit at the threshold level, $1,000 per unit at the target level and $2,000 per unit at the maximum level, at the end of the three-year period. Performance objectives are calculated weighing three-year total stockholder return versus the Peer Group at the time of the award and a performance measure known as a “reserve replacement efficiency ratio” (determined by dividing pre-tax operating cash flow by finding and development costs) versus the target and the Peer Group at the time of the award. The Company does not assign specific probabilities of achievement to the minimum, target or maximum award levels under the Performance Unit Plan. The target goals are set, at the beginning of the performance period, to be achievable if the Compa ny achieves its business plan for the relevant performance period. Because the performance units are awarded annually and cover a three-year performance cycle, the units granted over any three-year period necessarily overlap and the achievement of a performance measure in the earliest performance cycle may affect the level of achievement of the next two performance cycles. By way of example, since two of the years included in the performance cycle ended December 31, 2008 are also part of the performance cycle ended December 31, 2009, it is unlikely that there will be a substantial change in the level of achievement on an annual basis. The assessment as to whether the performance objectives have been attained for the performance units awarded in any given fiscal year are made by the Compensation Committee when the Peer Group results are finalized, approximately three years following the year in which the award was made.
At the December Compensation Meetings in 2008 and 2009, the Compensation Committee granted performance units to the NEOs for fiscal years 2009 and 2010, respectively, except in the case of our Executive Chairman, who did not receive any performance units for fiscal year 2010. In March 2010, the Compensation Committee determined that the level of achievement of the performance objectives for the three-year cycle ended December 31, 2009 was at the maximum level, resulting in the payment of approximately $2,000 per unit and our NEOs were paid calculated the amounts payable to the NEOs under performance units relating to the three-year period ended December 31, 2009 and authorized the payment of the following amounts: $1,800,000 for our Executive Chairman; $700,000 for our CFO; $534,000 for our EVP & General Counsel; and $384,000 for our President-Midstream. Our CE O did not receive a PUP payment because he did not have any performance units for this three-year period having only joined the Company in June 2008.
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