October 13, 2011
Mr. H. Roger Schwall
Assistant Director
United States Securities and Exchange Commission
Division of Corporation Finance
100 F Street, N.E.
Washington, D.C. 20549
Re: Cabot Oil & Gas Corporation
Form 10-K for Fiscal Year Ended December 31, 2010
Filed February 28, 2011
File No. 1-10447
Dear Mr. Schwall:
We are responding to comments received from the Staff of the Division of Corporation Finance of the Securities and Exchange Commission by letter dated September 29, 2011 regarding our 2010 Form 10-K. For your convenience, our responses are prefaced by the Staff’s corresponding comment in italicized text. With respect to the Staff’s comments, we would propose to revise our future filings under the Securities Exchange Act of 1934 as indicated below.
General
Glossary of Certain Oil and Gas Terms, page 1
1. | In the definition of proved reserves, please add after the first sentence the following: The project to extract hydrocarbons must have commenced or the operator must be reasonable certain that it will commence the project within a reasonable time. Please see Rule 4-10(a)(22) of Regulation S-X. |
Response
In future filings, we will include such sentence in the definition of proved reserves.
Overview, page 4
2. | You indicate in the fourth paragraph that you pursue “lower risk drilling opportunities.” Clarify the type of “risk” you consider and how you measure or assess the level of risk in a particular drilling opportunity. |
Response
The use of the words “lower risk drilling opportunities” refers to pursuing development drilling opportunities versus pursuing wildcat drilling opportunities (exploratory drilling in underground horizons from which there is no production in the general area). Although we do believe these activities are, and are viewed as being, lower risk, we will not characterize these development drilling opportunities as “lower risk” in future filings.
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Reserves, page 9
3. | Please provide us with a copy of your reserve report as of December 31, 2010. Please include the cash flow statements for all of the wells. |
Response
Pursuant to Rule 418 under the Securities Act of 1933 and Rule 12b-4 under the Securities Exchange Act of 1934, we are supplementally furnishing a copy of the reserve report electronically on a CD. We hereby request that the reserve report be returned to us upon completion of your review and that, pending its return, it be withheld from release as it contains competitively sensitive, proprietary business information of Cabot.
Proved Undeveloped Reserves, page 10
4. | You state that you spent $183 million in order to convert 216 BCFe from proved undeveloped reserves to proved developed reserves. Please tell us how many gross and net wells were drilled to accomplish this. Additionally please reconcile your statement that you spent $183 million to develop these reserves in 2010 with your disclosure on page 107 that you incurred $630 million in development costs in 2010. |
Response
In 2010, we drilled and converted to proved developed reserves 38 gross and 36.8 net proved undeveloped locations. Each year we allocate a portion of our capital budget to both PUD and non-PUD development drilling activities. The following table details the development costs incurred in 2010 associated with our development drilling activities:
2010 Development Cost Detail (in thousands)
Drilled PUD Development Costs | $ | 183,437 | ||
Non-PUD Development Costs | 425,332 | |||
Workover and Facility Costs | 21,742 | |||
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Total Development Costs | $ | 630,511 | ||
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5. | You state that your ability to sell your oil and gas production could be materially harmed if you fail to obtain adequate services such as transportation or processing. Please tell us if you have any pipeline constraints or if there are not enough processing facilities in place to adequately process your gas thereby causing you to shut in production for periods of time. |
Response
In future filings, we will expand our risk factor disclosure on page 25 as follows:
Our ability to sell our natural gas and oil production could be materially harmed if we fail to obtain adequate services such as transportation and processing.
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The sale of our natural gas and oil production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. We deliver our natural gas and oil production primarily through gathering systems and pipelines that we do not own. The lack of availability of capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our production through various firm transportation arrangements, third-party systems and facilities may be unavailable due to market conditions or mechanical or other reasons. Our failure to obtain these services on acceptable terms could materially harm our business.
Major Customer, page 15
6. | Identify your major customer or tell us why you believe that disclosure is not required under Item 101(c)(vii) of Regulation S-K. |
Response
Item 101(c)(1)(vii) of Regulation S-K requires disclosure of the name of any customer if sales to the customer equal 10 percent or more of the registrant’s consolidated revenues and the loss of such customer would have a material adverse effect on the registrant.
As noted in our letter to the Staff dated July 6, 2010 in response to comment 5 provided by the Staff, sales of oil and natural gas to our customers that exceed 10 percent of consolidated revenues are generally under short-term contracts based on market prices. The loss of any of these customers would not have a material adverse effect on us as the oil and natural gas production sold to these customers is a commodity with a readily available market and could easily be sold to other market participants in the event that sales to these customers ceased. Accordingly, we continue to believe that disclosure of the names of our customers is not required under Item 101(c)(l)(vii) of Regulation S-K.
Risk Factors, page 20
We Face a Variety of Hazards and Risks That Could Cause Substantial Financial Losses, page 23
7. | On page 19, you disclose that your hydraulic fracturing fluids include chemical additives. Please revise this risk factor to specifically address the financial and operational risks associated with hydraulic fracturing such as the underground migration of hydraulic fracturing fluids or spillage or mishandling of recovered hydraulic fracturing fluids, if material. |
Response
We believe that the underground migration of hydraulic fracturing fluids and the spillage or mishandling of recovered hydraulic fracturing fluids used at our wells does not present material financial or operational risks.
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We adhere to currently existing best practices intended to minimize any potential environmental impact from our fracing operations. For example, we encourage our fracing service providers to use lower impact chemicals for additives such as friction reducers and surfactants, while keeping in mind both functionality and cost effectiveness. We publicly disclose the contents of our hydraulic fracturing fluid on a well-by-well basis at the websitewww.FracFocus.org. We use on-site real-time monitoring of our frac operations to ensure the frac process is performed in an environmentally appropriate and safe manner. We do not store flowback fluids (the portion of the frac fluid that returns up the well to the surface from the formation) in open pits; all flowback fluids recovered by us are stored in closed containers.
In Pennsylvania, we recycle and reuse essentially all water from natural gas drilling and well completion activities and have been doing so for in excess of one year. When fresh frac fluids are required, we add the fresh water to frac tanks (no open pits are utilized), and subsequently mix sand and additives on-site prior to being pumped down-hole. We use this approach to limit the need to truck large quantities of treated fluids to well sites.
At our drilling locations, steel pipe, known as casing or surface casing, is cemented into place at the uppermost portion of the well for the specific purpose of protecting groundwater, in some cases (all Pennsylvania wells) multiple protective casing strings are utilized. The depth of the surface casing is generally determined by the location of aquifers in the area, among other factors. As the well is drilled deeper, additional casing and cement is installed to isolate natural gas producing formations from ground water. Casing and cementing are critical parts of the well construction that not only protect groundwater, but are also important to ensuring efficient production of natural gas from the well. Before fracing begins, the casing and the cement surrounding the casing are pressure tested at pressures greater than those that will be used during fracing operations.
In future filings, we will expand our risk factor disclosure on page 23 as follows:
We face a variety of hazards and risks that could cause substantial financial losses.
Our business involves a variety of operating risks, including:
• | well site blowouts, cratering and explosions; |
• | equipment failures; |
• | pipe or cement failures and casing collapses, which can release natural gas, oil, drilling fluids or hydraulic fracturing fluids; |
• | uncontrolled flows of natural gas, oil or well fluids; |
• | fires; |
• | formations with abnormal pressures; |
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• | handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids; |
• | pollution and other environmental risks; and |
• | natural disasters. |
Any of these events could result in injury or loss of human life, loss of hydrocarbons, significant damage to or destruction of property, environmental pollution, regulatory investigations and penalties, suspension or impairment of our operations and substantial losses to us.
Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. As of December 31, 2010, we owned or operated approximately 3,150 miles of natural gas gathering and pipeline systems. As part of our normal maintenance program, we have identified certain segments of our pipelines that we believe periodically require repair, replacement or additional maintenance.
Notes to the Consolidated Financial Statements
Note 1. Summary of Significant Accounting Policies
Basis of Presentation and Nature of Operations, page 61
8. | We note your disclosure stating that you operate in one segment. However, it appears that you are organizationally structured based on the geographic location of your operations (i.e., the Rocky Mountain and Appalachian areas which primarily make up the North region and your operations in east and south Texas and Oklahoma which primarily make up the South region). Please tell us whether you have concluded that your operations represent a single operating segment or multiple operating segments that have been combined into a single reportable segment for purposes of applying FASB ASC 280. If you have concluded that your operations represent a single operating segment, explain to us how you have applied the guidance in FASB ASC 280-10-50-1. Alternatively, if you have combined multiple operating segments into a single reportable segment, explain to us how you have applied the aggregation criteria per FASB ASC 280-10-50-11. As part of your response, please tell us about the process through which your chief operating decision maker reviews information to make decisions about resources to be allocated to your segment and assess its performance. |
Response
We have concluded that our oil and gas operations represent a single operating segment as our operations are solely dependent on exploration and production activities within the continental United States. These activities are fully integrated and intertwined whereby key strategic management decisions are made based on the operations as a whole (e.g., at a consolidated level).
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ASC 280-10-50-1 indicates that an operating segment is a component of an enterprise (a) that engages in business activities from which it may earn revenues and incur expenses (including revenues and expenses relating to transactions with other components of the same enterprise), (b) whose operating results are regularly reviewed by the enterprise’s chief operating decision maker (CODM) to make decisions about resources to be allocated to the segment and assess its performance, and (c) for which discrete financial information is available. We have included below an analysis of the criteria from the above referenced guidance, specifically focusing on operating results regularly reviewed by the CODM to make decisions about resource allocation, to assess performance of the Company and the availability of discrete financial information, in order to support our conclusion that Cabot’s operations represent a single operating segment.
The Company has concluded that the CODM is the Chairman, President and Chief Executive Officer of the Company. The CODM package consists of the following reports:
• | Consolidated Budget/Forecast |
• | Consolidated Quarter to Quarter Variance Analysis |
• | Consolidated Drilling Priority List |
Annually and on an as needed basis, the CODM reviews the Consolidated Budget/Forecast for purposes of determining how to allocate resources. With regard to allocating resources, the CODM determines the capital available for expenditure based on the Consolidated Budget/Forecast. Once the capital expenditure budget is established, the CODM evaluates the projects the Company will pursue by considering economic returns of potential projects, the type of project (oil versus natural gas), the Company’s ability to secure services to complete the project, the Company’s ability to get the production to market and other strategic considerations, including but not limited to leasehold expirations and expansion into new areas with growth potential. Once the best strategic projects are identified for development, they are included on the Company’s Consolidated Drilling Priority List. This process is based on a Company-wide approach with no specific consideration given solely to geographic location of the project.
The CODM is provided with various reports on at least a quarterly basis. These reports include (i) the Consolidated Budget/Forecast (adjusted quarterly for actual activity to date and other significant changes such as divestitures or acquisitions), (ii) the Consolidated Quarter to Quarter Variance Analysis comparing the prior forecast to the current forecast and (iii) the Consolidated Drilling Priority List. The Annual Forecast provides the CODM with the consolidated statement of operations, consolidated balance sheet, consolidated statement of cash flows, consolidated capital expenditures and consolidated production, while the Variance Analysis provides a comparison of the prior quarter’s forecast to the current forecast on a total company basis. All of the metrics for which Cabot is evaluated (as noted below) are included in the Variance Analysis. The Consolidated Drilling Priority List provides the CODM with updated project and capital expenditure information that corresponds to the updated budget/forecast.
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The CODM assesses the performance of the Company by evaluating various consolidated financial and operating metrics prevalent in the oil and gas industry on a quarterly and/or annual basis. These metrics are consistent with how external stakeholders evaluate Cabot’s performance, as reflected in our share value, and how the Company and its Board of Directors evaluate performance for incentive compensation purposes. Specifically these metrics include: (i) consolidated net income and earnings per share, (ii) consolidated operating cash flow and discretionary cash flow (non-GAAP measure), (iii) consolidated production growth, (iv) consolidated finding costs per Mcfe, (v) consolidated reserve additions, (vi) consolidated proved reserve growth, and (vii) certain consolidated unit cost metrics. Certain of these metrics are evaluated on a quarterly basis and others annually by reviewing actual results and updated forecast information. In addition, on an annual basis, these key metrics are presented to the Company’s Board of Directors for purposes of assessing the Company’s performance for the period and establishing performance objectives for the upcoming year.
We note that discrete financial information is made available on a regional basis (e.g., North and South) for others in the organization in order to monitor and maintain the efficiency of our operations. This discrete information, while available, is not provided as part of the regular CODM package, nor is it used for making decisions as to the allocation of resources or the assessment of performance of the Company.
We also acknowledge our disclosures required by subpart 1200 of Regulation S-K in Item 1. – Business in our Form 10-K might further indicate the Company may be organized geographically through its North and South regions. Specifically, oil and gas production, production prices and production costs were disclosed by region in our Form 10-K based on management’s interpretation of Item 1204 of Regulation S-K which requires disclosure by geographic area. We understand geographic area, as defined in Item 1201 of Regulation S-K, includes (1) an individual country; (2) a group of countries within a continent; or (3) a continent, and would not include regional information within a country. The inclusion of regional information in our Item 1204 disclosure was not provided to suggest that the CODM uses this information for purposes of allocating resources and assessing performance; it was only provided as a result of our interpretation of Item 1204 of Regulation S-K.
Based on the above analysis, we reaffirm that Cabot has one operating segment.
In future filings, we will remove the regional information from our Item 1204 disclosure and will expand our disclosure in Note 1 to the consolidated financial statements to clarify how the Company has applied the guidance in ASC 280-10-50-1. Such disclosure (in Note 1 of our 2010 Form 10-K) would have read substantially as follows:
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Business Segments
The Company operates in one segment, natural gas and oil development, exploitation and exploration, exclusively in the continental United States. The Company’s oil and gas properties are managed as a whole rather than through discrete operating segments or business units. Operational information is tracked by geographic area; however, financial performance is assessed as a single enterprise and not on a geographic basis. Allocation of resources is made on a project basis across the Company’s entire portfolio without regard to geographic areas.
Note 2. Properties and Equipment, Net
Disposition of Assets, page 68
9. | We note you sold your Pennsylvania gathering infrastructure of approximately 75 miles of pipeline and two compressor stations to Williams Field Services for $150 million and recognized a $49.3 million gain on sale of assets. We also note you are obligated to construct pipelines to connect certain of your 2010 program wells, complete the construction of a compressor station and complete taps into certain pipeline delivery points, and that you expect to complete your obligations under the agreement in the first half of 2011. Please tell us and disclose how these future obligations impacted the $49.3 million gain recognized in connection with this transaction. Please be specific in your response and cite the authoritative guidance used to support your accounting for this transaction. |
Response
Upon closing of the transaction with Williams Field Services, we recognized a $17.9 million liability, which represented the Company’s estimated cost of the future obligations under the agreement, with a corresponding decrease to the gain, resulting in the net gain of $49.3 million disclosed in our 2010 Form 10-K. As part of our evaluation of the impact of the future obligations on the net gain, we considered FASB Concepts Statement No. 6,Elements of Financial Statements(CON 6) and SAB Topic 5E (by analogy). We believe that the future obligations under the agreement represent probable future sacrifices of economic benefits arising from present obligations to transfer assets as prescribed by CON 6 and as such, these future obligations were accrued for as of the reporting date. Additionally, SAB Topic 5E states that prior to recognizing any gain, the seller should recognize certain obligations associated with the transaction. Consistent with SAB Topic 5E, the recognition of our future obligations under the agreement resulted in a reduction of the gain we recognized associated with the transaction. For reference purposes, we are providing the following reconciliation to illustrate the components of the gain recognized in connection with the Williams transaction (in millions of dollars):
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Proceeds | $ | 150.0 | ||
Less: Net Book Value | 82.8 | |||
Less: Accrued Obligations | 17.9 | |||
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Net Gain on Sale | $ | 49.3 | ||
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While we believe that our current disclosure accurately reflects the financial impact of the transaction, in future filings we will expand our disclosure to include the amount of the liability accrued relative to the Company’s future obligations under the agreement and inform the reader that such amount is included as a reduction to the gain recognized in connection with this transaction. Such disclosure (in the first paragraph under the heading “Disposition of Assets” on page 68 of our 2010 Form 10-K) would have read substantially as follows:
Disposition of Assets
In December 2010, the Company sold its existing Pennsylvania gathering infrastructure of approximately 75 miles of pipeline and two compressor stations to Williams Field Services (Williams), a subsidiary of Williams Partners L.P., for $150 million. Under the terms of the purchase and sale agreement, the Company is obligated to construct pipelines to connect certain of its 2010 program wells, complete the construction of the Lathrop compressor station and complete taps into certain pipeline delivery points. The Company expects to complete these obligations in the first half of 2011. As of December 31, 2010, the Company recognized a $49.3 million gain on sale of assets, which includes the accrual of $17.9 million associated with the obligations described above.
The Company also entered into a 25-year firm gathering contract with Williams that requires Williams to complete construction of approximately 32 miles of high pressure pipeline, 65 miles of trunklines and two compressor stations in Susquehanna County in the next two years. Additionally, Williams will connect all of the Company’s drilling program wells, which will connect our production to five interstate pipeline delivery options.
Note 8. Commitments and Contingencies
Environmental Matters, page 86
10. | We note that you have accrued a $3.6 million settlement liability related to the global settlement agreement and consent order entered into with the Pennsylvania Department of Environmental Protection. In addition, we note that certain of the affected households appealed the Global Settlement Agreement to the Pennsylvania Environmental Hearing Board. Please tell us how this appeal impacts your estimate of the settlement liability incurred as of the end of the reporting period. Refer to FASB ASC 450-20-25-2. |
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Response
The affected households’ appeal of the Global Settlement Agreement to the Pennsylvania Environmental Hearing Board does not impact our estimate of settlement liability incurred as of the end of the reporting period under FASB ASC 450-20-25-2.
The estimated settlement liability was explicitly derived from the Global Settlement Agreement and represents the settlement amount we were required to pay the affected households as ordered by the PaDEP. We considered the appeal in our assessment and concluded that it did not impact the estimated settlement amount accrued as of December 31, 2010 due to the uncertainty around the potential outcome of the appeals process and its impact on the Global Settlement Agreement, if any. Due to this uncertainty and until the appeals process runs its course, we will continue to accrue for the estimated settlement liability as provided by the Global Settlement Agreement, as such estimate is the probable amount the Company expects to pay related to this matter. Consistent with ASC 450-20-25-2, in the event additional information related to the appeal becomes available that would impact our probable assessment and the related accrual, we will adjust our financial statements and related disclosures accordingly in the reporting period in which the additional information becomes available.
We note that subsequent to December 31, 2010, five additional households accepted the settlement under the Global Settlement Agreement. As of June 30, 2011, the remaining estimated settlement liability related to this matter was approximately $2.2 million. The Company continues to believe that the remaining estimated settlement liability accrued represents the probable amount the Company expects to pay related to this matter.
Note 9. Asset Retirement Obligation, page 88
11. | We note your change in estimate in the amount of $40.4 million and your disclosure that this change is attributable to additional regulatory requirements in east Texas and increased costs for services and equipment to plug and abandon wells in all of your areas of operations. Given the change in estimate represents a 136% increase from your asset retirement obligation at December 31, 2009, please tell us and disclose in more detail the specific factors that resulted in this significant increase. Please quantify the change in estimate attributable to each factor identified in your analysis. Refer to FASB ASC 410-20-35. |
Response
We acknowledge the Company’s current disclosure may indicate multiple factors led to the change in estimate (i.e., change in timing of cash flows and change in undiscounted cash flows) as described in ASC 410-20-35. We confirm to the Staff the sole factor for the change in estimate was due to increased costs for materials and services. The increase in cost of materials and services was primarily driven by the lack of availability of service providers in certain areas of our operations together with a higher demand for service providers as a result of increased regulatory requirements to plug temporarily abandoned and shut in wells.
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We believe we have complied in all material respects with the disclosure requirements in ASC 410-20-35 and ASC 410-20-50 and in future filings we will enhance our disclosure by expanding on the factors that led to the increase in costs. Such disclosure (in the first paragraph below the asset retirement obligation reconciliation table) would have read substantially as follows:
The change in estimate during 2010 is attributable to increased costs for materials and services to plug and abandon wells in certain areas of our operations. The increase in costs of materials and services is primarily due to the lack of availability of service providers in certain areas of our operations together with a higher demand for service providers as a result of increased regulatory requirements to plug temporarily abandoned and shut in wells.
Supplemental Oil and Gas Information, page 105
12. | We note that you recorded additions to your proved reserves related to extensions and discoveries of 650,644 MMcfe during 2010 and 462,880 MMcfe during 2009. Please provide us with additional information regarding these additions with a focus on the underlying causal factors. Refer to FASB ASC 932-235-50-5. |
Response
The additions to our proved reserves related to extensions and discoveries noted in the Staff’s comments primarily related to drilling activity in the Dimock field in Northeast Pennsylvania. The Company added 536,635 Mmcfe of proven reserves in this area in 2010 and 361,631 Mmcfe of proven reserves in 2009.
In future filings, we will expand our disclosure to discuss all material changes in proved reserves as required by ASC 932-235-50-5. For 2010, such disclosure (in a new footnote to the information at December 31, 2010 in the table on page 106 of our 2010 Form 10-K) would have read substantially as follows:
(6) Extensions, discoveries and other additions were primarily related to Cabot drilling activity in the Dimock field located in Northeast Pennsylvania. The Company added 536.6 Bcfe and 361.6 Bcfe of proven reserves in this area in 2010 and 2009, respectively.
Exhibit 99.1
13. | Item 1202(a)(8) of Regulation S-K specifies disclosure items pertaining to third party engineering reports. In this regard, you provide the average West Texas Intermediate and Henry Hub prices, but these appear to be for reference rather than the actual price utilized. Please obtain and file a revised report that also includes the average adjusted prices used to determine reserves. |
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Response
Miller and Lents Ltd. has indicated that it will add additional disclosure on this point in future Miller and Lents Ltd. report letters. For 2010, the additional disclosure would have read: “The actual average prices used in this report for proved reserves, after appropriate adjustments, were $74.25 per barrel for oil and $4.33 per Mcf for gas.”
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By copy of this memorandum, we are requesting that the Freedom of Information Act officer accord confidential treatment under the Commission’s rules to the CD and the reserve report furnished supplementally with the hard copy of this letter.
Cabot hereby acknowledges that:
• | Cabot 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 |
• | Cabot 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 or require additional information, you may contact Todd M. Roemer at (281) 589-4848 or the undersigned at (281) 589-4993.
Sincerely, |
/s/ Scott C. Schroeder |
Scott C. Schroeder |
Principal Financial Officer |
Vice President, Chief Financial Officer and Treasurer |
Cc: | Office of Freedom of Information and Privacy Operations |
Mr. Robert Carroll, United States Securities and Exchange Commission
Mr. Ethan Horowitz, United States Securities and Exchange Commission
Mr. Jim Murphy, United States Securities and Exchange Commission
Mr. Kevin Dougherty, United States Securities and Exchange Commission
Mr. Todd M. Roemer, Cabot Oil & Gas Corporation
Ms. Lisa A. Machesney, Cabot Oil & Gas Corporation
Mr. J. David Kirkland, Jr., Baker Botts L.L.P.
Mr. Chuck Chang, PricewaterhouseCoopers LLP
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