February 15, 2008

Mr. Brad Skinner

Senior Assistant Chief Accountant

United States Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Mail Stop 7010

Washington, D.C. 20549

Re: Response to SEC Staff Comments dated January 23, 2008 on the Cabot Oil & Gas Corporation 2006 Form 10-K

Dear Mr. Skinner:

We are responding to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “SEC” or “Commission”) by a letter dated January 23, 2008 regarding our 2006 Form 10-K. For your convenience, our responses are prefaced by the Staff’s corresponding comment in italicized text. The reference to page numbers in the responses to the comments correspond to the pages in the Form 10-K. With respect to the Staff’s comments, we would propose to revise our future filings under the Securities Exchange Act of 1934 as indicated in our response.

Form 10-K filed February 28, 2007, File No. 001-10447

Engineering Comments

Business, page 3

1. We have reviewed your response to prior comment two of our letter dated October 30, 2007. Item 102 of Regulation S-K refers to principal properties and properties of major significance. It does not refer to geographic areas or regions as you appear to suggest. If you do not have properties that are of major significance you do not have to disclose maps or other detailed information but you must still disclose the required information of production, nature of interest, location, reserves and development of your principle properties. We note that your ten largest fields by reserves represent almost 45% of your total proved reserves and your ten largest fields by PV10%

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represent greater than 61% of the PV10% of all your fields. We also note in a number of recent press releases you have provided updated operational information on specific fields such as the County Line James, Hinton, Minden, Moxa Arch, Musreau, Redfish Bay, Sissonville and others. It would appear that some or all of these fields represent principal properties. We reissue comment two of our prior letter.

In future filings, beginning with our 2007 Form 10-K, we will amend the disclosures in the “Business-Overview” section in Item 1 to address production, nature of interest, location, reserves and development of our principal properties substantially as shown in the underlined sections below. If the revised disclosure had been included in our 2006 Form 10-K, it would have read substantially as follows:

“Our interest in both developed and undeveloped properties is primarily in the form of leasehold interests held under customary mineral leases. These leases provide us the right, in general, to develop oil and/or natural gas on the properties. Their primary terms range in length from approximately three to seven years. These properties are held for longer periods if production is established. We own leasehold rights on approximately 3.1 million gross acres. In addition, we own fee interest in approximately 0.2 million gross acres, primarily in West Virginia. Our ten largest fields, which are fields with 2.5% or greater of total company proved reserves, make up approximately 45% of total company proved reserves.

EAST REGION

Our East activities are concentrated primarily in West Virginia. In this region, our assets include a large acreage position, a high concentration of wells, natural gas gathering and pipeline systems, and storage capacity. This region is managed from our office in Charleston, West Virginia.

Capital and exploration expenditures for 2006 and 2005, respectively, were $145.4 million, or 27% of our total 2006 capital and exploration expenditures, and $99.0 million, or 23% of our total 2005 capital and exploration expenditures. Of the total company year-over-year increase in capital and exploration expenditures, 42% was attributable to an increase in the East region spending. For 2007, we have budgeted approximately $160 million for capital and exploration expenditures in the region.

At December 31, 2006, we had 2,926 wells (2,719.4 net), of which 2,833 wells are operated by us. There are multiple producing intervals that include the Big Lime, Weir, Berea and Devonian Shale formations at depths primarily ranging from 1,000 to 9,300 feet, with an average depth of approximately 3,750 feet. Average net daily production in 2006 was 64.9 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2006 was 23.5 Bcfe and 24 Mbbls, respectively.

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While natural gas production volumes from East reservoirs are relatively low on a per-well basis compared to other areas of the United States, the productive life of East reserves is relatively long. At December 31, 2006, we had 703.6 Bcfe of proved reserves (substantially all natural gas) in the East region, constituting 50% of our total proved reserves. Developed and undeveloped reserves made up 491.5 Bcfe and 212.1 Bcfe of the total proved reserves for the East region, respectively. While no properties are individually significant to the Company as a whole, the Pineville, Sissonville, Logan-Holden-Dingess, Big Creek, Hernshaw-Bullcreek and Huff Creek fields in West Virginia are included in the Company’s ten largest fields and together contain approximately 29% of our total company proved equivalent reserves.

In 2006, we drilled 200 wells (190.7 net) in the East region, of which 197 wells (188.0 net) were development wells. In 2007, we plan to drill approximately 270 wells, primarily in West Virginia, including the Sissonville, Big Creek, Pineville and Hernshaw-Bull Creek fields.

In 2006, we produced and marketed approximately 65 barrels of crude oil/condensate per day in the East region at market responsive prices.

Ancillary to our exploration, development and production operations, we operated a number of gas gathering and transmission pipeline systems, made up of approximately 2,700 miles of pipeline with interconnects to three interstate transmission systems, seven local distribution companies and numerous end users as of the end of 2006. The majority of our pipeline infrastructure in West Virginia is regulated by the Federal Energy Regulatory Commission (FERC) for interstate transportation service and the West Virginia Public Service Commission (WVPSC) for intrastate transportation service. As such, the transportation rates and terms of service of our pipeline subsidiary, Cranberry Pipeline Corporation, are subject to the rules and regulations of the FERC and the WVPSC. Our natural gas gathering and transmission pipeline systems enable us to connect new wells quickly and to transport natural gas from the wellhead directly to interstate pipelines, local distribution companies and industrial end users. Control of our gathering and transmission pipeline systems also enables us to purchase, transport and sell natural gas produced by third parties. In addition, we can engage in development drilling without relying upon third parties to transport our natural gas and incur only the incremental costs of pipeline and compressor additions to our system.

We have two natural gas storage fields located in West Virginia with a combined working capacity of approximately 4 Bcf. We use these storage fields to take advantage of the seasonal variations in the demand for natural gas and the higher prices typically associated with winter natural gas sales, while maintaining production at a nearly constant rate throughout the year. The

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storage fields also enable us to increase for shorter intervals of time the volume of natural gas that we can deliver by more than 40% above the volume that we could deliver solely from our production in the East region. The pipeline systems and storage fields are fully integrated with our operations.

The principal markets for our East region natural gas are in the northeast United States. We sell natural gas to industrial customers, local distribution companies and gas marketers both on and off our pipeline and gathering system.

Approximately 65% of our natural gas sales volume in the East region is sold at index-based prices under contracts with a term of one year or greater. In addition, spot market sales are made at index-based prices under month-to-month contracts, while industrial and utility sales generally are made under year-to-year contracts. Approximately two percent of East production is sold on fixed price contracts that typically renew annually.

GULF COAST REGION

Our development, exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in north Louisiana and in south and east Texas. A regional office in Houston manages the operations. Principal producing intervals are in the Cotton Valley and Hosston formations in north Louisiana and east Texas and the Frio, Vicksburg and Wilcox formations in south Texas at depths ranging from 2,200 to 17,000 feet, with an average depth of approximately 9,600 feet.

Capital and exploration expenditures were $234.8 million for 2006, or 44% of our total 2006 capital and exploration expenditures, and $233.5 million for 2005, or 55% of our total 2005 capital and exploration expenditures. For 2007, we have budgeted approximately $135 million for capital and exploration expenditures in the region. Our 2007 Gulf Coast drilling program will emphasize activity in our focus areas of east Texas, north Louisiana and south Texas.

In 2006, we drilled 64 wells (50.8 net) in the Gulf Coast region, of which 52 wells (41.4 net) were development and extension wells. In 2007, we plan to drill 51 wells, primarily in Texas, including the Minden, County Line and McCampbell fields.

We had 566 wells (380.4 net) in the Gulf Coast region as of December 31, 2006, of which 438 wells are operated by us. Average daily production in 2006 was 101.2 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2006 was 30.0 Bcfe and 1,164 Mbbls, respectively.

At December 31, 2006, we had 235.2 Bcfe of proved reserves (89% natural gas) in the Gulf Coast region, which represented 16% of our total proved reserves. Developed and undeveloped reserves made up 153.9 Bcfe and 81.3 Bcfe of the

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total proved reserves for the Gulf Coast region, respectively. While no properties are individually significant to the Company as a whole, the Minden field in east Texas is included in the Company’s ten largest fields based on percentage of total company proved equivalent reserves.

Our principal markets for Gulf Coast region natural gas are in the industrialized Gulf Coast area and the northeast United States. We sell natural gas to intrastate pipelines, natural gas processors and marketing companies. Currently, approximately 50% of our natural gas sales volumes in the Gulf Coast region are sold at index-based prices under contracts with terms of one to three years. The remaining 50% of our sales volumes are sold at index-based prices under short-term agreements. The Gulf Coast properties are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets.

In 2006, we produced and marketed approximately 3,177 barrels of crude oil/condensate per day in the Gulf Coast region at market responsive prices.

WEST REGION

Our activities in the West region, which is comprised of the Rocky Mountains and Mid-Continent areas, are managed by a regional office in Denver, Colorado. At December 31, 2006, we had 448.7 Bcfe of proved reserves (96% natural gas) in the West region, constituting 32% of our total proved reserves. Developed and undeveloped reserves made up 361.8 Bcfe and 86.9 Bcfe of the total proved reserves for the West region, respectively. While no properties are individually significant to the Company as a whole, the Mocane-Laverne field in Oklahoma in the Mid-Continent area and the Lincoln Road and Cow Hollow fields in Wyoming in the Rocky Mountain area are included within the Company’s ten largest fields and together contain approximately 10% of our total company proved equivalent reserves.

Our principal markets for West region natural gas are in the northwest and midwest United States. We sell natural gas to power generators, natural gas processors, local distribution companies, industrial customers and marketing companies. Currently, approximately 75% of our natural gas production in the West region is sold primarily under contracts with a term of one to three years at index-based prices. Another 23% of the natural gas production is sold under short-term arrangements at index-based prices, and the remaining two percent is sold under certain fixed-price contracts. The West region properties are connected to the majority of the midwest and northwest interstate and intrastate pipelines, affording us access to multiple markets.

In 2006, we produced and marketed approximately 573 barrels of crude oil/condensate per day in the West region at market responsive prices.

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Rocky Mountains

Activities in the Rocky Mountains are concentrated in the Green River and Washakie Basins in Wyoming and Paradox Basin in Colorado. At December 31, 2006, we had 256.0 Bcfe of proved reserves (95% natural gas) in the Rocky Mountains area, or 18% of our total proved reserves.

Capital and exploration expenditures in the Rocky Mountains were $66.2 million for 2006, or 12% of our total 2006 capital and exploration expenditures, and $45.4 million for 2005, or 11% of our total 2005 capital and exploration expenditures. For 2007, we have budgeted approximately $59 million for capital and exploration expenditures in the area.

We had 638 wells (281.2 net) in the Rocky Mountains area as of December 31, 2006, of which 318 wells are operated by us. Principal producing intervals in the Rocky Mountains area are in the Almond, Frontier, Dakota and Honaker Trail formations at depths ranging from 4,500 to 14,200 feet, with an average depth of approximately 10,950 feet. Average net daily production in the Rocky Mountains during 2006 was 37.9 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2006 was 13.2 Bcfe and 104 Mbbls, respectively.

In 2006, we drilled 63 wells (27.6 net) in the Rocky Mountains, of which 61 wells (25.9 net) were development wells. In 2007, we plan to drill 55 wells, primarily in Wyoming, including the Cow Hollow and Lincoln Road fields.

Mid-Continent

Our Mid-Continent activities are concentrated in the Anadarko Basin in southwest Kansas, Oklahoma and the panhandle of Texas. At December 31, 2006, we had 192.7 Bcfe of proved reserves (97% natural gas) in the Mid-Continent area, or 14% of our total proved reserves.

Capital and exploration expenditures were $39.8 million for 2006, or seven percent of our total 2006 capital and exploration expenditures, and $23.7 million for 2005, or six percent of our total 2005 capital and exploration expenditures. For 2007, we have budgeted approximately $43 million for capital and exploration expenditures in the area.

As of December 31, 2006, we had 728 wells (502.6 net) in the Mid-Continent area, of which 556 wells are operated by us. Principal producing intervals in the Mid-Continent are in the Chase, Morrow and Chester formations at depths ranging from 2,200 to 17,500 feet, with an average depth of approximately 7,050 feet. Average net daily production in 2006 was 30.4 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2006 was 10.4 Bcfe and 110 Mbbls, respectively.

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In 2006, we drilled 50 wells (32.5 net) in the Mid-Continent, all of which were development and extension wells. In 2007, we plan to drill 53 wells, primarily in Oklahoma, including the Mocane-Laverne field.

CANADA REGION

Our activities in the Canada region are managed by a regional office in Calgary, Alberta. Our Canadian exploration, development and producing activities are concentrated in the Provinces of Alberta and British Columbia. At December 31, 2006, we had 28.6 Bcfe of proved reserves (98% natural gas) in the Canada region, constituting two percent of our total proved reserves. Developed and undeveloped reserves made up 24.9 Bcfe and 3.7 Bcfe of the total proved reserves for the Canada region, respectively. No properties in the Canada region are individually significant to the Company as a whole. The largest field in this region is the Hinton field in Alberta, which is not included in the Company’s ten largest fields.

Capital and exploration expenditures in Canada were $49.0 million for 2006, or nine percent of our total 2006 capital and exploration expenditures, and $22.9 million for 2005, or five percent of our total 2005 capital and exploration expenditures. For 2007, we have budgeted approximately $35 million for capital and exploration expenditures in the area.

We had 28 wells (8.2 net) in the Canada region as of December 31, 2006, of which 15 wells are operated by us. Principal producing intervals in the Canada region are in the Falher, Bluesky, Cadomin, Dunvegan and the Mountain Park formations at depths ranging from 9,500 to 12,000 feet. Average net daily production in Canada during 2006 was 7.3 Mmcfe. Natural gas and crude oil/condensate/NGL production for 2006 was 2.6 Bcfe and 13 Mbbls, respectively.

In 2006, we drilled 10 wells (5.4 net) in Canada, of which 7 wells (3.6 net) were development and extension wells. In 2007, we plan to drill 11 wells in various fields in Alberta.

Our principal markets for Canada natural gas are in western Alberta. We sell natural gas to gas marketers. Currently, all of our natural gas production in Canada is sold primarily under contracts with a term of one year at index-based prices. The Canadian properties are connected to the major interstate pipelines.

In 2006, we produced and marketed approximately 32 barrels of crude oil/condensate per day in the Canada region at market responsive prices.”

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Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 31

Potential Impact of our Critical Accounting Policies, page 36

Oil and Gas Reserves, page 36

2. We have reviewed your response to prior comment five. You indicate that the quality and quantity of available data may impact the accuracy of reserve estimates. However, Rule 4-10(a) of Regulation S-X states that proved reserves are the estimated quantities which geological and engineering data demonstrate with reasonable certainty to be recoverable. Therefore, if the quality or quantity of available data is not sufficient enough or not compelling enough, proved reserves should not be reported based on that data. Please revise your proposed disclosure so as to not imply that you may determine proved reserves with insufficient quantity or quality of engineering or geological data.

We believe that our proved reserves are reasonably certain to be recoverable. We are proposing to revise our disclosure to remove the statement to which you refer that may be read to imply that we do not have sufficient data to support proved reserves. In future filings, beginning with our 2007 Form 10-K, we will amend the disclosure under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Potential Impact of our Critical Accounting Policies—Oil and Gas Reserves” and related disclosure under “Risk Factors” to remove the last sentence discussing the accuracy of reserve estimates. In addition, we have removed the statements which discuss the differences in reserve estimates based on regional conditions due to the fact that these differences were largely attributable to complexities associated with estimation of reserves offshore and in south Louisiana. These properties were sold during 2006.

Reserve Report

3. We note that you appear to have booked proved undeveloped reserves that you will not develop until beyond 2012. Please provide us with a table by year of the number of proved undeveloped wells to be drilled and the reserves attributed to those wells and explain to us why you believe it is appropriate to attribute proved reserves that will not be developed until five years or later.

We show in the table below our proved undeveloped wells (PUD), by year, that are scheduled to be developed beyond 2012 as reported in our 2006 Year End Reserve Report. This table includes 23 PUD locations with reserves of 7.5 Bcfe, representing approximately 0.5% of our total proved reserves and 2% of our total proved undeveloped reserves. All PUD locations and reserves in the table below are on drilling units offsetting productive wells and the reserves assigned are reasonably certain of being produced once drilled. Of the 23 PUD wells in the table below, three were actually drilled in 2007 and five are

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currently scheduled in our 2008 drilling program. The remainder of the 23 PUD wells in the table below are currently scheduled to be drilled prior to 2011 based on our Year End 2007 Reserve Report which reports that all of our PUDs are currently scheduled to be developed by the year 2013.

Cabot Oil & Gas Corporation

YE 2006 Reserve Report - PUD Reserves Scheduled Beyond 2013

Number of Wells	Drill Year	Net Oil, Bbl	Net Gas, Mcf	Net Equivalents, Mcfe
6	2013	2,280	1,848,194	1,861,871
12	2015	24,285	3,254,737	3,400,445
1	2018	1,560	259,222	268,580
4	2019	13,240	1,914,393	1,993,831
23	Grand Total	41,363	7,276,546	7,524,727

4. Please reconcile the fact that your reserve report contains a Western region with significant reserves and a Rocky Mountain region but the Western region is not reported on page nine of your 2006 10-K report and these reserves do not appear to be included in the SFAS 69 reserve tables on pages 102 and 103 of the same report.

The West region is comprised of the Rocky Mountains and Mid-Continent areas. The table on page six of the 2006 10-K report shows that the Rocky Mountains and Mid-Continent total the West region. The entire West region results are reported in all reserve tables, including the SFAS 69 reserve tables on pages 102 and 103 of the 2006 10-K.

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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 the undersigned at (281) 589-4848 or Scott Schroeder at (281) 589-4993.

Sincerely,
	/s/ Henry C. Smyth
	Henry C. Smyth
	Principal Accounting Officer
	Vice President, Controller and Treasurer

Cc:	Mr. Roger Schwall, United States Securities and Exchange Commission
	Mr. Ryan Milne, United States Securities and Exchange Commission
	Mr. James Murphy, United States Securities and Exchange Commission
	Mr. Scott C. Schroeder, Cabot Oil & Gas Corporation
	Ms. Lisa A. Machesney, Cabot Oil & Gas Corporation
	Mr. J. David Kirkland, Jr., Baker Botts LLP
	Mr. Stephen Parker, PricewaterhouseCoopers LLP

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